FirstEnergy
Annual Report 2019

Plain-text annual report

A N N U A L R E P O R T 2 0 1 9 2019 FINANCIAL HIGHLIGHTS KEY ACCOMPLISHMENTS • Increased the annualized dividend to $1.52 per common share, and in November 2019, increased the quarterly dividend by 3%, or $0.01 per share, payable to shareholders of record as of February 7, 2020, bringing the annualized dividend to $1.56 per common share • In November 2019, we extended our operating (non-GAAP) earnings per share compound annual growth rate (CAGR) projections through 2023, at a rate of 5% to 7%* • Provided total shareholder return of approximately 34%, placing us in the top quartile of the Edison Electric Institute Index • Invested $1.2 billion to modernize our transmission system as part of our Energizing the Future initiative FINANCIALS AT A GLANCE (in millions, except per share amounts) TOTAL REVENUES INCOME (loss) from continuing operations DILUTED EARNINGS (loss) per share from continuing operations DIVIDENDS PAID per common share 2017 $10,928 $(289) $(0.65) $1.44 2018 $11,261 $1,022 $1.33 $1.44 2019 $11,035 $904 $1.67 $1.52 CAPITAL SPEND** ($M) 3 8 9 , 2 2 9 9 , 2 9 1 5 , 2 3,000 2,500 2,000 1,500 1,000 500 0 REGULATED TRANSMISSION AND DISTRIBUTION REVENUES ($M) TOTAL SHAREHOLDER RETURN (%) 6 5 4 , 1 1 4 2 2 , 1 1 4 8 0 , 1 1 12,000 4 3 10,000 8 2 35 30 25 20 15 10 5 0 8,000 6,000 4,000 2,000 0 4 7 1 0 2 8 1 0 2 9 1 0 2 7 1 0 2 8 1 0 2 9 1 0 2 7 1 0 2 8 1 0 2 9 1 0 2 * FirstEnergy management cannot estimate on a forward-looking basis the impact of these items in the context of operating earnings (loss) per share growth projections because these items, which could be significant, are difficult to predict and may be highly variable. Consequently, the company is unable to reconcile operating earnings (loss) per share growth projections (i.e., CAGR) to a GAAP measure without unreasonable effort. ** 2017 excludes capital spend at FirstEnergy Solutions to conform to 2019 presentation. On the cover: Powered by our seven core values, we’re transforming FirstEnergy into a more forward-thinking company that anticipates our customers’ needs for years to come. A MESSAGE TO OUR SHAREHOLDERS Charles E. Jones President and Chief Executive Officer During this exciting and transformative time for our company, we are energized by the possibilities ahead of us and committed to our mission of making customers’ lives brighter, the environment better and our communities stronger. Our industry is undergoing rapid change, fueled by shifting customer expectations, emerging technologies and an evolving energy mix. To enable the grid of the future, we’re upgrading our energy infrastructure, implementing advanced technologies, and supporting widespread electrification and grid integration research. In our strategic plan, we articulate a clear, five-year vision that addresses the needs of our diverse customer base; enables a strong, secure and technologically advanced electric system; and leverages emerging technologies to enhance the customer experience. Guided by this strategic vision, we’re transforming FirstEnergy into a more diverse, innovative and sustainable company that is well-positioned to anticipate our customers’ needs for years to come. As we prepare to meet our customers’ evolving expectations, we continue to strengthen and modernize our transmission and distribution systems to enhance reliability, resiliency and security, while improving operational efficiency. With annual capital investments of up to $3 billion for the foreseeable future, we’re expanding the scale and scope of our regulated operations to achieve long-term, customer- focused growth. FirstEnergy has established a strong track record of meeting our commitments to investors and the larger financial community, and our sustainable growth plans continue to support our goal of enhancing shareholder returns. In 2018, we provided investors with our first long-term growth rate projection, and we achieved growth above the midpoint of our original forecast through 2019. To provide greater clarity on our expectations, we broadened our outlook by two additional years, through 2023. The projection includes plans to issue a modest amount of equity, up to $600 million annually, to fund our growth initiatives starting in 2022. MAKING CUSTOMER-FOCUSED TRANSMISSION INVESTMENTS Ensuring a brighter future for our customers requires long- term investments to modernize the electric infrastructure. Through our Energizing the Future initiative, we’re upgrading and modernizing our transmission system to improve the reliability, resiliency and security of FirstEnergy’s sizeable portion of the U.S. power grid. Since launching this initiative in 2014, our cumulative investments reached $6.8 billion in 2019. Projects are based on three main areas of investment: upgrading or replacing aging equipment to reduce outages and maintenance costs; enhancing system performance through cybersecurity and technology upgrades; and adding redundancy and operational flexibility to enable grid operators to more swiftly respond to changing conditions. Since the program’s inception, we’ve replaced or rebuilt 900 miles of transmission lines and installed 1,250 miles of new fiber-optic cable to improve our network communications. In 2019, we completed approximately 650 projects. These Energizing the Future investments are improving service to our customers. Since 2014, we’ve achieved a 47% reduction in equipment-related outages on our ATSI transmission system, as well as a 59% reduction in the duration of transmission-caused distribution outages and a 66% reduction in the number of customers affected by such outages. We expect to achieve similar results for customers in the eastern part of our service territory as we expand the program. In December 2019, the Federal Energy Regulatory Commission accepted JCP&L’s filing to move our New Jersey transmission assets to forward-looking formula rates, effective January 1, 2020, subject to refund. This rate structure supports the expansion of our Energizing the Future initiative to New Jersey, including an approximately $175 million investment planned for this year. As service reliability results in our ATSI system demonstrate, our transmission infrastructure investments bring value to customers. We will continue to advocate for long-term transmission investments and work to ensure that prudent and necessary cost-effective, customer-centric projects are approved and built. 1 BUILDING A SMARTER, MORE RESILIENT DISTRIBUTION SYSTEM Our 10 electric distribution companies plan to invest up to $1.7 billion per year through 2023 to enhance reliability, enable a smarter grid and harden our electric system against powerful storms. For example, our four Pennsylvania utilities received approval from the Public Utility Commission (PUC) in January 2020 to invest $572 million through 2024 as part of our second phase of Long-Term Infrastructure Improvement Plans (LTIIPs). These investments build on earlier improvement plans and are designed to reduce the frequency and duration of outages experienced by our customers. Major initiatives include rebuilding critical infrastructure; reconfiguring circuits to minimize the number of customers impacted by outages; installing smart devices that detect and isolate problems to restore power faster; and implementing an advanced distribution management system (ADMS) to provide enhanced grid monitoring, control and outage management. We continue to recover these investments through PUC-approved Distribution System Improvement Charges, which allow for the return on accelerated infrastructure investments made between rate cases. Our three Ohio utilities are implementing our $516 million, three-year Grid Modernization program, approved by the Public Utilities Commission of Ohio (PUCO) in July 2019. The program will enhance service reliability and help our customers make more informed decisions about their electricity usage through advanced metering and communications. Projects include deploying 700,000 smart meters; installing distribution automation equipment; adding voltage-regulating equipment to provide energy efficiency benefits; and implementing an ADMS platform that enhances grid monitoring, control, automation, optimization and outage management. As part of this grid modernization effort, we’ve also filed proposed time-varying rates that would give our customers the opportunity to save money by shifting their electricity use to off-peak periods. In addition, we received PUCO approval in January 2020 for a decoupling mechanism that breaks the link between utility revenue and the amount of electricity consumed by customers. Our decoupling plan fixes the level of base distribution revenue collected from residential and commercial customers to ensure we collect no more for distribution service than was charged in 2018. It supports our customers’ energy efficiency efforts, while ensuring our utilities have adequate resources to continue providing safe and reliable power. energizing In New Jersey, our JCP&L Reliability Plus initiative builds on reliability enhancements we made in our service area in recent years with an additional $97 million investment through December 2020. As part of the New Jersey Board of Public Utilities (BPU)-approved program, we’re replacing existing equipment with new smart devices, expanding our vegetation management program to address tree-related outages and implementing emerging technologies, including new electronic fuses and communications, to enable automation for distribution equipment. Key JCP&L Reliability Plus projects include trimming trees along nearly 1,400 miles of power lines and installing 1,700 new TripSaver® automated reclosing devices. These and other initiatives will help limit the frequency and duration of power interruptions by detecting issues, isolating outages and pinpointing problem locations. JCP&L will recover these investments through two rate filings – the initial filing made in September 2019 and the second to be filed at the completion of the program. JCP&L also filed an electric rate plan with the BPU in February 2020 to support service reliability enhancements made by the utility in recent years and recover costs incurred to restore power to customers following severe storms. Upon approval of the filing, JCP&L customers would continue to pay the lowest residential electric rates among New Jersey’s four regulated electric distribution companies. In March of last year, the Maryland Public Service Commission (PSC) approved Potomac Edison’s plan to increase its distribution rates by $6.2 million, concluding the company’s first base rate case in nearly 25 years. In its order, the PSC approved an Electric Distribution Investment Surcharge (EDIS) to fund programs that are expected to enhance service reliability for Maryland customers. The EDIS supports the installation of electronic reclosers and automated distribution equipment and accelerates the replacement of aging underground electric cables. 2 ENABLING THE ELECTRIC GRID OF THE FUTURE Our industry is undergoing a transformation that will soon require more from our electrical infrastructure. This includes enabling microgrids, renewables and distributed energy resources; widespread electrification of transportation, industrial equipment and home products; continued development of smart cities; and increasingly advanced energy management tools and data. We expect to simultaneously contend with an increased risk of extreme weather, as well as more frequent and sophisticated cyberthreats. All of this requires a much more complex, resilient, secure and technologically advanced power grid. We are preparing our systems for these advancements so we can seamlessly deliver the electricity our customers depend on every day. On our transmission system, we’re developing new grid solutions and deploying innovative, secure technologies through our Center for Advanced Energy Technology – one of the first and most comprehensive testing and training centers of its kind in the country. We’re exploring opportunities to use this state-of-the-art facility for industry collaboration with peer utilities, research institutes and key stakeholders. On our distribution system, we are working to leverage research and innovation that can deliver customer-focused service enhancements while making the environment better through emissions reductions and energy efficiency improvements. Our Emerging Technologies group continues to guide our efforts to advance new technologies and initiatives, including electric transportation, microgrids, solar energy, utility-owned storage and smart cities. For example, we’re advocating for greater availability of electric vehicle (EV) charging stations across our service territory. As part of our EV Driven program, our Potomac Edison utility is installing utility-owned, publicly available charging stations throughout our Maryland service area in support of the state’s goal to have 300,000 zero-emission vehicles on the road by 2025. Our efforts will help make EV adoption more accessible, convenient and cost effective through an enhanced public charging network, rebates for charger installations at residential and multifamily properties, and incentives for EV charging during off-peak periods. This initiative will position Maryland as a leader in EV technology and provide key data to help determine future implementation efforts throughout the state and other areas served by FirstEnergy’s utilities in preparation for continued growth in electric transportation. 3 empowering We’ve also partnered with the Electric Power Research Institute (EPRI) on a statewide project in Ohio to assess the impact of expanded electrification enabled by advanced metering infrastructure (AMI) deployment. By analyzing how a state’s energy system could evolve over time, under various policies and across multiple customer groups, we’ll be better positioned to ensure the reliability and efficiency of increased electrification. In 2019, our three Ohio utilities received PUCO approval for modifications to our Experimental Company-Owned LED Street Lighting program for municipalities. Program offerings include an additional LED lighting option and the opportunity to pursue advanced functionality, such as dimming capabilities, sensors or other network-enabled functions. In addition, we’re supporting research to better understand efficiency opportunities in next-generation heat pumps, data center infrastructure and building design. We are also working with universities on energy storage and grid integration research projects and have collaborated with EPRI to better understand microgrids’ effect on resiliency within our electric system. As we continue to prepare our grid for new technologies, we will work with our stakeholders to understand which investments are most valuable to the electric system and our customers. We’ll also continue to build an advanced communications system that creates a more direct link with greater visibility between us and our customers. We’re engaged in new business efforts to offer valuable products and services that enhance customers’ daily lives and help them save energy and money. We’re launching a new venture – FirstEnergy Advisors – to further support these efforts by connecting commercial, industrial and municipal aggregation customers with low-cost power suppliers. By offering the right products and services at the right time, FirstEnergy Advisors can strengthen connections with its customers, while growing new revenue streams. DELIVERING ON OUR COMMITMENT TO CORPORATE RESPONSIBILITY We are committed to corporate responsibility initiatives that foster a brighter future for our customers, employees, communities and the environment. We are driving the direction and implementation of our corporate responsibility strategy at the highest levels of our organization, including our Corporate Governance and Corporate Responsibility Board Committee. Our cross-functional, executive-led steering committee also continues to guide our strategy and related initiatives. We are focused on making the environment better by minimizing the impact of our operations and finding opportunities to enhance our ecosystem. 4 In 2019, we launched our corporate responsibility microsite, which highlights our commitment to transparency and accountability regarding our environmental, social and governance (ESG) efforts. This comprehensive report includes our initial steps to provide data in alignment with the Global Reporting Initiative (GRI) and Sustainability Accounting Standards Board (SASB) metrics. We intend to update this report annually and use it to track progress on our ESG initiatives and goals. We also published our Climate Report, which assessed the business risks and opportunities associated with a two-degree Celsius global climate scenario and examined how our regulated strategies align with emerging technology trends that support a lower-carbon future. Ashlyn Harlan, chemical technician, conducts environmental compliance testing at Mon Power’s Harrison Power Station in Haywood, West Virginia. We have made significant progress toward our goal of reducing carbon dioxide (CO2) emissions by at least 90% below 2005 levels by 2045. Through plant retirements and operational changes, we achieved an 80% reduction in these emissions as of the end of February 2020, placing us well ahead of schedule to achieve our goal. Our utility companies help customers reduce their electricity consumption through energy efficiency programs, which consistently exceed state targets. Customers participating in FirstEnergy’s efficiency programs received nearly $86 million in incentives and achieved energy savings of more than 1.3 million megawatt hours across our service area in 2019. These savings are equivalent to a reduction of almost 940,000 metric tons of CO2, or one year of electric use for nearly 160,000 homes, according to the U.S. Environmental Protection Agency’s Greenhouse Gas Equivalencies Calculator. In addition to our carbon reduction efforts, we’re developing and introducing waste- and water-reduction programs across the company. For example, we launched a waste reduction initiative in 2019 that included removing polystyrene and single-use plastics from several company breakrooms and food services. We also implemented a centralized waste program at our corporate locations to demonstrate how employee actions – even on a small scale – can make a big difference in reducing our environmental impact. Other key steps taken in 2019 to enhance our sustainability efforts include expanding our drone program to increase non-invasive inspections of equipment, bird nests and wetlands; reducing our landfill waste through the refurbishment, resale and recycling of our operations equipment; and introducing a pilot project at Mon Power’s Harrison Power Station in Haywood, West Virginia, to reduce the amount of water we draw from the nearby river. We continue to explore opportunities to expand these efforts and establish new environmental initiatives. We’re dedicated to the prosperity and vitality of our communities through our support of economic development initiatives that create jobs and attract new businesses to our service area. Over the past decade, our economic development efforts have helped attract more than $30 billion in capital investment and create more than 88,000 jobs in our operating territory. Key projects fostered by our collaborative economic development activities in 2019 include North Star BlueScope’s $700 million expansion in northwest Ohio, Kite Pharma’s new $85 million manufacturing facility in Maryland and CarbonLITE’s $80 million investment in a new plastic recycling facility near Reading, Pennsylvania. The resources of FirstEnergy and the FirstEnergy Foundation provide essential support that helps build stronger, more successful communities. Over the past decade, FirstEnergy and the FirstEnergy Foundation have provided more than $59 million in contributions and grants to over 3,800 community-based organizations across our service area. Our employees engage in our corporate responsibility efforts and share in our commitment to strengthening local organizations dedicated to enriching communities and serving those in need. To bolster their efforts, we introduced a Volunteer Time Off (VTO) program in 2019 that provides participating employees with 16 hours of annual paid time off to volunteer in their communities. In the first year of the initiative, nearly 2,300 employees collectively logged over 21,000 hours of VTO. EMPOWERING A SAFE, DIVERSE AND FORWARD-THINKING TEAM Safety is an unwavering core value at FirstEnergy. In 2019, we achieved a companywide OSHA-recordable injury rate of 0.98, which is less than one injury per 200,000 hours worked. During the year, we also experienced no life-changing events (LCEs), which are injuries that result in a fatality, require immediate life-saving measures or affect an employee’s ability to continue normal activities. As we look to the future, we’re enhancing our safety culture with a particular emphasis on recognizing and mitigating situations that can become LCEs. Building that culture of accountability begins with leadership. We’ve introduced comprehensive training and coaching to equip our leaders with the skills they need to effectively lead with safety as a 5 transforming core value. At the same time, we’re developing a personal safety culture in which employees openly communicate, give and receive feedback and continuously improve. As part of this effort, we’re training employees to recognize, reduce or eliminate exposure to hazards and to pause and seek assistance when a situation doesn’t look or feel right. This focus on proactively controlling, reducing and eliminating exposure will help us transform our safety culture and prevent LCEs. We’re also expanding the diversity of our team while creating an engaging and inclusive workplace where employees feel valued, motivated and empowered to drive FirstEnergy’s success. To achieve this goal, we’re enhancing our recruiting and hiring processes, increasing the number and scope of employee business resource groups, and implementing initiatives to create an inclusive environment in which our employees can thrive. Success in this key area helps us develop innovative energy solutions, meet our customers’ evolving expectations and deliver value to our stakeholders. As part of our annual incentive compensation program, our Diversity & Inclusion (D&I) Index helps us drive accountability and track our progress in creating a more diverse and inclusive environment. In 2019, we increased the weight of our D&I Index for managers and above to emphasize the importance of this culture change and reinforce the role of leadership in advancing this business imperative. For the second consecutive year, we earned the Bloomberg Gender-Equality Index (GEI) designation for our commitment to women’s equality in the workplace. The GEI uses a reporting framework to evaluate gender equality based on female leadership and talent pipelines, equal pay and gender pay parity, and other metrics. Our inclusion in the 2020 Bloomberg GEI reaffirms our commitment to transparency and leadership in gender-related performance and data reporting, which are important steps in furthering gender equality. And in January of this year, we were named to Forbes magazine’s Best Employers for Diversity 2020 list in recognition of our commitment to diversity in the workplace. We’re also committed to preparing our high-performing workforce for the future and helping employees reach their full potential. Earlier this year, we implemented our Educate to Elevate Program, which assists our Akron-area customer service employees in pursuing associate and bachelor’s degrees by providing on-site classes through partnerships with local colleges. Through the program, we can support our employees’ efforts to further their education and advance their careers, while developing a highly skilled and adaptable workforce that is ready for the future. We continue to develop employees through our New Supervisor and Manager Program, which has trained more than 2,220 new leaders for management positions since 2008. This year, we’ll launch our Experienced Leader Program to establish a development path for experienced managers and directors that provides additional tools they need to support their teams and drive FirstEnergy’s success. We’ve also introduced our FE University Program to provide opportunities for employees to broaden and deepen their knowledge of the rapidly changing electric utility industry, as well as our company strategy and supporting initiatives. ENERGIZED BY POSSIBILITY I’m proud of the important steps we took in 2019 to implement new initiatives designed to create a more innovative, diverse and sustainable corporate culture. These efforts are guided by FirstEnergy’s core values and our mission to be a forward- thinking electric utility and will position our company for continued success. As we build on our progress, we remain focused on executing our strategies for long-term growth that will continue to bring value to our investors, customers, communities and employees. We are energized by the possibilities ahead and confident our company and its dedicated employees are prepared to meet any challenge as we work together to deliver energy for a brighter future. Thank you for your continued support of FirstEnergy. Charles E. Jones President and Chief Executive Officer March 11, 2020 6 FIRSTENERGY CORPORATE PROFILE Headquartered in Akron, Ohio, FirstEnergy is a forward-thinking, fully regulated utility powered by a diverse team of employees committed to making customers’ lives brighter, the environment better and our communities stronger. Our subsidiaries are involved in the transmission, distribution and regulated generation of electricity. Our workforce of approximately 12,300 employees is dedicated to safety, reliability and operational excellence. Our 10 electric distribution companies form one of the nation’s largest investor-owned electric systems, based on serving 6.1 million customers in Ohio, Pennsylvania, New Jersey, West Virginia, Maryland and New York. The company’s transmission subsidiaries operate approximately 24,500 miles of transmission lines connecting the Midwest and Mid-Atlantic regions. FirstEnergy subsidiaries own generating capacity from two regulated coal plants and two pumped-storage hydro facilities. PA OH MD NJ WV VA GENERATING FACILITIES Regulated Coal Plants 1. Fort Martin Power Station 2. Harrison Power Station Pumped-Storage Hydro 3. Bath County 4. Yards Creek OHIO Ohio Edison The Illuminating Company Toledo Edison PENNSYLVANIA Met-Ed Penelec Penn Power West Penn Power WEST VIRGINIA/ MARYLAND Mon Power Potomac Edison NEW JERSEY Jersey Central Power & Light 7 FIRSTENERGY BOARD OF DIRECTORS FRONT ROW (LEFT TO RIGHT) Michael J. Anderson Chairman of the board of The Andersons, Inc. (diversified agribusiness) Donald T. Misheff Non-executive Chairman of the FirstEnergy Corp. Board of Directors. Retired, formerly managing partner of the Northeast Ohio offices of Ernst & Young LLP Julia L. Johnson President of NetCommunications, LLC (regulatory and public affairs firm) BACK ROW (LEFT TO RIGHT) Thomas N. Mitchell Chairman of the World Association of Nuclear Operators (nonprofit promoting nuclear safety). Retired, formerly president, chief executive officer and director of Ontario Power Generation Inc. Christopher D. Pappas Retired, formerly president and chief executive officer of Trinseo S.A. (plastics, latex and rubber producer) Steven J. Demetriou Chairman, chief executive officer and director of Jacobs Engineering Group, Inc. (technical professional and construction services) Charles E. Jones President and Chief Executive Officer of FirstEnergy Corp. James F. O’Neil III Chief executive officer and vice chairman of CUI Global Inc. (acquires and develops innovative companies) Luis A. Reyes Retired, formerly regional administrator of the U.S. Nuclear Regulatory Commission Leslie M. Turner Retired, formerly senior vice president, general counsel and corporate secretary of The Hershey Company Sandra Pianalto Retired, formerly president and chief executive officer of the Federal Reserve Bank of Cleveland DEAR SHAREHOLDERS: During 2019, your management team focused on driving sustainable, long-term earnings growth for shareholders, strengthening the company’s balance sheet and investment-grade credit ratings, and achieving operational excellence. These efforts, together with our attractive dividend, provided a total shareholder return of approximately 34% in 2019, placing FirstEnergy among the top quartile of stocks in the Edison Electric Institute Index. Based on the success of the company’s strategies and its projected growth, your Board declared an increased quarterly dividend of $0.39 per common share in November. This represents a 3% increase compared with payments of $0.38 per common share paid by the company since March 2019. The dividend increase is consistent with FirstEnergy’s dividend policy, which seeks to offer attractive shareholder returns and support continued investments in our strategic initiatives. The Board will continue to base decisions regarding future dividend payments on FirstEnergy’s earnings growth, cash flows, credit metrics and other business conditions. FirstEnergy also supports shareholder interests and business integrity through our leadership in corporate governance practices. For example, your Board has enacted a policy requiring the consideration of a diverse slate of qualified candidates for director positions, together with a goal to maintain a Board composition of at least 30% diverse members. Currently, your Board comprises 36% diverse nominees. The Board also is committed to actively seeking candidates with a breadth of backgrounds, skills and experiences. With support from the Board, CEO and your management team, we focus significant efforts on engaging with our major shareholders and the broader investment community. Shareholder feedback and recommendations we receive are reported to the appropriate committee or the entire Board for its consideration. Our commitment to shareholder outreach and engagement drove our adoption of leading governance practices including proxy access, a majority voting standard in uncontested Director elections, and expanding the responsibilities of the Corporate Governance and Corporate Responsibility Board Committee to include oversight of sustainability and corporate responsibility. As confirmation of our efforts, FirstEnergy earned the best possible governance score from Institutional Shareholder Services’ rating system, which assesses corporate governance risk. Your Board remains committed to representing your interests and enhancing the value of your investment in FirstEnergy. Thank you for your continued support. FIRSTENERGY LEADERSHIP TEAM Charles E. Jones* President and Chief Executive Officer Samuel L. Belcher* Senior Vice President and President, FirstEnergy Utilities Gary D. Benz* Senior Vice President, Strategy Dennis M. Chack Senior Vice President, Product Development, Marketing and Branding Michael J. Dowling Senior Vice President, External Affairs Bennett L. Gaines Senior Vice President, Corporate Services and Chief Information Officer Robert P. Reffner* Senior Vice President and General Counsel Steven E. Strah* Senior Vice President and Chief Financial Officer Christine L. Walker* Senior Vice President and Chief Human Resources Officer Jason J. Lisowski* Vice President, Controller and Chief Accounting Officer Eileen M. Mikkelsen Vice President, Rates and Regulatory Affairs Irene M. Prezelj Vice President, Investor Relations K. Jon Taylor Vice President, Utility Operations Ebony L. Yeboah-Amankwah Vice President, Deputy General Counsel, Corporate Secretary and Chief Ethics Officer *Indicates an Executive Officer of FirstEnergy. More detailed information on the principal occupation or employment of each of FirstEnergy’s Executive Officers and the principal business of any organization by which FirstEnergy Executive Officers are employed may be found on page 107 of this report. Sincerely, Donald T. Misheff Chairman of the Board 8 A N N U A L R E P O R T 2 0 1 9 CONTENTS 1 ..........Glossary of Terms 4 ..........Selected Financial Data 6 ..........Management’s Discussion and Analysis 46 ..........Report of Independent Registered Public Accounting Firm 48 ..........Consolidated Statements of Income (Loss) 49 ..........Consolidated Statements of Comprehensive Income (Loss) 50 ..........Consolidated Balance Sheets 51 ..........Consolidated Statements of Common Stockholders’ Equity 52 ..........Consolidated Statements of Cash Flows 53 ..........Notes to the Consolidated Financial Statements 107 ..........Executive Officers as of February 10, 2020 GLOSSARY OF TERMS The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries: AE AESC AE Supply AGC ATSI BSPC CEI CES FE FELHC FENOC FES Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011, which subsequently merged with and into FE on January 1, 2014 Allegheny Energy Service Corporation, a subsidiary of FirstEnergy Corp. Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary Allegheny Generating Company, formerly a generation subsidiary of AE Supply that became a wholly owned subsidiary of MP in May 2018 American Transmission Systems, Incorporated, formerly a direct subsidiary of FE that became a subsidiary of FET in April 2012, which owns and operates transmission facilities Bay Shore Power Company The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary Competitive Energy Services, formerly a reportable operating segment of FirstEnergy FirstEnergy Corp., a public utility holding company FirstEnergy License Holding Company FirstEnergy Nuclear Operating Company, a subsidiary of FE, which operates NG's nuclear generating facilities FirstEnergy Solutions Corp., together with its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C., and FGMUC, which provides energy-related products and services FES Debtors FES and FENOC AYE Director's Plan Allegheny Energy, Inc. Non-Employee FASB Financial Accounting Standards Board FESC FET FEV FG FirstEnergy Service Company, which provides legal, financial and other corporate support services FirstEnergy Transmission, LLC, formerly known as Allegheny Energy Transmission, LLC, which is the parent of ATSI, MAIT and TrAIL, and has a joint venture in PATH FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures FirstEnergy Generation, LLC, a wholly owned subsidiary of FES, which owns and operates non-nuclear generating facilities FGMUC FirstEnergy Generation Mansfield Unit 1 Corp., a wholly owned subsidiary of FG, which has certain leasehold FirstEnergy Global Holding interests in a portion of Unit 1 at the Bruce Mansfield plant FirstEnergy Corp., together with its consolidated subsidiaries Global Mining Holding Company, LLC, a joint venture between FEV, WMB Marketing Ventures, LLC and Pinesdale LLC Global Rail Global Rail Group, LLC, a subsidiary of Global Holding that owns coal transportation operations near Roundup, Montana GPU GPUN JCP&L MAIT ME MP NG OE GPU, Inc., former parent of JCP&L, ME and PN, that merged with FE on November 7, 2001 Collective Bargaining Agreement Financial Transmission Right GPU Nuclear, Inc., a subsidiary of FE, which operates TMI-2 Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary Mid-Atlantic Interstate Transmission, LLC, a subsidiary of FET, which owns and operates transmission facilities Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary Monongahela Power Company, a West Virginia electric utility operating subsidiary FirstEnergy Nuclear Generation, LLC, a wholly owned subsidiary of FES, which owns nuclear generating facilities Ohio Edison Company, an Ohio electric utility operating subsidiary Ohio Companies CEI, OE and TE PATH Potomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP CSAPR Cross-State Air Pollution Rule PATH-Allegheny PATH Allegheny Transmission Company, LLC PATH-WV PATH West Virginia Transmission Company, LLC PE Penn The Potomac Edison Company, a Maryland and West Virginia electric utility operating subsidiary Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE Pennsylvania Companies ME, PN, Penn and WP PN Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary Signal Peak Signal Peak Energy, LLC, an indirect subsidiary of Global Holding that owns mining operations near Roundup, Montana TE TrAIL The Toledo Edison Company, an Ohio electric utility operating subsidiary Trans-Allegheny Interstate Line Company, a subsidiary of FET, which owns and operates transmission facilities Transmission Companies ATSI, MAIT and TrAIL Utilities WP OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP West Penn Power Company, a Pennsylvania electric utility operating subsidiary 1 The following abbreviations and acronyms are used to identify frequently used terms in this report: Affordable Clean Energy Electric Distribution Company Accumulated Deferred Income Taxes Executive Deferred Compensation Plan American Electric Power Company, Inc. Electric Distribution Investment Surcharge AFUDC Allowance for Funds Used During Energy Efficiency and Conservation Electric Generation Supplier AYE DCD Facebook® Facebook is a registered trademark of Facebook, Bankruptcy Court U.S. Bankruptcy Court in the Northern FE Tomorrow Bath County Bath County Pumped Storage Hydro- FERC Federal Energy Regulatory Commission Available-for-sale Construction Administrative Law Judge Alternative Minimum Tax American Nuclear Insurers Accumulated Other Comprehensive Income Asset Retirement Obligation Alternative Revenue Program Accounting Standard Codification Accounting Standards Update Allegheny Energy, Inc. Amended and Restated Revised Plan for Deferral of Compensation of Directors Director Stock Plan District of Ohio in Akron Power Station Basic Generation Service BNSF Railway Company Basis points Clean Air Act Compact Fluorescent Light Code of Federal Regulations Carbon Dioxide EPA's Clean Power Plan CSX Transportation, Inc. Consolidated Tax Adjustment Clean Water Act Electric Generation Units EmPOWER Maryland Energy Efficiency Act EmPOWER Maryland Expanded Net Energy Cost United States Environmental Protection Agency Earnings per Share Electric Reliability Organization Employee Stock Ownership Plan Electric Security Plan IV Inc. FirstEnergy's initiative launched in late 2016 to identify its optimal organizational structure and properly align corporate costs and systems to efficiently support a fully regulated company going forward FES Bankruptcy FES Debtors' voluntary petitions for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code with the Bankruptcy Court Fitch Ratings First Mortgage Bond Federal Power Act IBEW ICP 2007 ICP 2015 International Brotherhood of Electrical Workers FirstEnergy Corp. 2007 Incentive Compensation Plan FirstEnergy Corp. 2015 Incentive Compensation Plan Infrastructure Investment Program Internal Revenue Service Independent System Operator JCP&L Reliability Plus IIP JCP&L Reliability Plus Kilovolt Kilowatt-hour Coal Combustion Residuals GAAP Accounting Principles Generally Accepted in the United States of America CERCLA Comprehensive Environmental Response, Compensation, and Liability Act of 1980 GHG Greenhouse Gases D.C. Circuit United States Court of Appeals for the District of Columbia Circuit DCPD Deferred Compensation Plan for Outside LBR Little Blue Run Directors Delivery Capital Recovery Distribution Modernization Rider Distribution Platform Modernization Light Emitting Diode London Interbank Offered Rate Letter of Credit Distribution System Improvement Charge LS Power LS Power Equity Partners III, LP Default Service Plan Deferred Tax Asset Earnings and Profits Load Serving Entity Long-Term Infrastructure Improvement Plans MDPSC Maryland Public Service Commission ACE ADIT AEP AFS ALJ AMT ANI AOCI ARO ARP ASC ASU BGS BNSF bps CAA CBA CCR CFL CFR CO2 CPP CSX CTA CWA DCR DMR DPM DSIC DSP DTA E&P EDC EDCP EDIS EE&C EGS EGU ENEC EPA EPS ERO ESOP ESP IV Fitch FMB FPA FTR IIP IRS ISO kV KWH LED LIBOR LOC LSE LTIIPs 2 GLOSSARY OF TERMS The following abbreviations and acronyms are used to identify frequently used terms in this report: The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries: Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011, which subsequently merged with and into FE on January 1, 2014 Allegheny Energy Service Corporation, a subsidiary of FirstEnergy Corp. Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary Allegheny Generating Company, formerly a generation subsidiary of AE Supply that became a wholly owned subsidiary of MP in May 2018 American Transmission Systems, Incorporated, formerly a direct subsidiary of FE that became a subsidiary of FET in April 2012, which owns and operates transmission facilities Bay Shore Power Company The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary Competitive Energy Services, formerly a reportable operating segment of FirstEnergy FirstEnergy Corp., a public utility holding company FirstEnergy License Holding Company FirstEnergy Nuclear Operating Company, a subsidiary of FE, which operates NG's nuclear generating facilities FirstEnergy Solutions Corp., together with its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C., and FGMUC, which provides energy-related products and services FirstEnergy Service Company, which provides legal, financial and other corporate support services FirstEnergy Transmission, LLC, formerly known as Allegheny Energy Transmission, LLC, which is the parent of ATSI, MAIT and TrAIL, and has a joint venture in PATH FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures FirstEnergy Generation, LLC, a wholly owned subsidiary of FES, which owns and operates non-nuclear generating FES Debtors FES and FENOC FGMUC FirstEnergy Generation Mansfield Unit 1 Corp., a wholly owned subsidiary of FG, which has certain leasehold FirstEnergy Global Holding interests in a portion of Unit 1 at the Bruce Mansfield plant FirstEnergy Corp., together with its consolidated subsidiaries Global Mining Holding Company, LLC, a joint venture between FEV, WMB Marketing Ventures, LLC and Pinesdale Global Rail Global Rail Group, LLC, a subsidiary of Global Holding that owns coal transportation operations near Roundup, facilities LLC Montana GPU, Inc., former parent of JCP&L, ME and PN, that merged with FE on November 7, 2001 GPU Nuclear, Inc., a subsidiary of FE, which operates TMI-2 Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary Mid-Atlantic Interstate Transmission, LLC, a subsidiary of FET, which owns and operates transmission facilities Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary Monongahela Power Company, a West Virginia electric utility operating subsidiary FirstEnergy Nuclear Generation, LLC, a wholly owned subsidiary of FES, which owns nuclear generating facilities Ohio Edison Company, an Ohio electric utility operating subsidiary Ohio Companies CEI, OE and TE PATH Potomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP PATH-Allegheny PATH Allegheny Transmission Company, LLC PATH-WV PATH West Virginia Transmission Company, LLC The Potomac Edison Company, a Maryland and West Virginia electric utility operating subsidiary Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE Pennsylvania Companies ME, PN, Penn and WP Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary Signal Peak Signal Peak Energy, LLC, an indirect subsidiary of Global Holding that owns mining operations near Roundup, Montana The Toledo Edison Company, an Ohio electric utility operating subsidiary Trans-Allegheny Interstate Line Company, a subsidiary of FET, which owns and operates transmission facilities Transmission Companies ATSI, MAIT and TrAIL OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP West Penn Power Company, a Pennsylvania electric utility operating subsidiary AE AESC AE Supply AGC ATSI BSPC CEI CES FE FELHC FENOC FES FESC FET FEV FG GPU GPUN JCP&L MAIT ME MP NG OE PE Penn PN TE TrAIL Utilities WP ACE ADIT AEP AFS AFUDC ALJ AMT ANI AOCI ARO ARP ASC ASU AYE DCD AYE Director's Plan Bankruptcy Court Affordable Clean Energy Accumulated Deferred Income Taxes American Electric Power Company, Inc. Available-for-sale Allowance for Funds Used During Construction Administrative Law Judge Alternative Minimum Tax American Nuclear Insurers Accumulated Other Comprehensive Income Asset Retirement Obligation Alternative Revenue Program Accounting Standard Codification Accounting Standards Update Allegheny Energy, Inc. Amended and Restated Revised Plan for Deferral of Compensation of Directors Allegheny Energy, Inc. Non-Employee Director Stock Plan U.S. Bankruptcy Court in the Northern District of Ohio in Akron Bath County Bath County Pumped Storage Hydro- Power Station BGS BNSF bps CAA CBA CCR Basic Generation Service BNSF Railway Company Basis points Clean Air Act Collective Bargaining Agreement Coal Combustion Residuals CERCLA Comprehensive Environmental Response, Compensation, and Liability Act of 1980 CFL CFR CO2 CPP Compact Fluorescent Light Code of Federal Regulations Carbon Dioxide EPA's Clean Power Plan CSAPR Cross-State Air Pollution Rule CSX Transportation, Inc. Consolidated Tax Adjustment EDC EDCP EDIS EE&C EGS EGU EmPOWER Maryland ENEC EPA EPS ERO ESOP ESP IV Electric Distribution Company Executive Deferred Compensation Plan Electric Distribution Investment Surcharge Energy Efficiency and Conservation Electric Generation Supplier Electric Generation Units EmPOWER Maryland Energy Efficiency Act Expanded Net Energy Cost United States Environmental Protection Agency Earnings per Share Electric Reliability Organization Employee Stock Ownership Plan Electric Security Plan IV Facebook® Facebook is a registered trademark of Facebook, Inc. FASB Financial Accounting Standards Board FE Tomorrow FirstEnergy's initiative launched in late 2016 to identify its optimal organizational structure and properly align corporate costs and systems to efficiently support a fully regulated company going forward FERC Federal Energy Regulatory Commission FES Bankruptcy FES Debtors' voluntary petitions for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code with the Bankruptcy Court Fitch FMB FPA FTR GAAP GHG IBEW ICP 2007 ICP 2015 IIP IRS ISO JCP&L Reliability Plus Fitch Ratings First Mortgage Bond Federal Power Act Financial Transmission Right Accounting Principles Generally Accepted in the United States of America Greenhouse Gases International Brotherhood of Electrical Workers FirstEnergy Corp. 2007 Incentive Compensation Plan FirstEnergy Corp. 2015 Incentive Compensation Plan Infrastructure Investment Program Internal Revenue Service Independent System Operator JCP&L Reliability Plus IIP Kilovolt Kilowatt-hour Little Blue Run Light Emitting Diode London Interbank Offered Rate Letter of Credit CSX CTA CWA D.C. Circuit DCPD DCR DMR DPM DSIC DSP DTA E&P Clean Water Act United States Court of Appeals for the District of Columbia Circuit Deferred Compensation Plan for Outside Directors Delivery Capital Recovery Distribution Modernization Rider Distribution Platform Modernization kV KWH LBR LED LIBOR LOC Distribution System Improvement Charge LS Power LS Power Equity Partners III, LP Default Service Plan Deferred Tax Asset Earnings and Profits LSE LTIIPs Load Serving Entity Long-Term Infrastructure Improvement Plans MDPSC Maryland Public Service Commission 1 2 MGP MISO mmBTU Moody’s MW MWH NAAQS NAV NDT NEIL NERC NJBPU NMB NOL NOx NPDES NRC NSR NUG NYPSC OCA OCC OEPA OMAEG OPEB OPEIU OPIC OSHA OVEC PA DEP PCRB PJM Manufactured Gas Plants Midcontinent Independent System Operator, Inc. One Million British Thermal Units Moody’s Investors Service, Inc. Megawatt Megawatt-hour PPB PPUC PUCO PURPA RCRA REC Parts per Billion Pennsylvania Public Utility Commission Public Utilities Commission of Ohio Public Utility Regulatory Policies Act of 1978 Resource Conservation and Recovery Act Renewable Energy Credit National Ambient Air Quality Standards Regulation FD Regulation Fair Disclosure promulgated by the SEC Earnings (Loss) per Share of Common Stock: SELECTED FINANCIAL DATA For the Years Ended December 31, 2019 2018 2017 2016 2015 Net Asset Value Nuclear Decommissioning Trust Nuclear Electric Insurance Limited North American Electric Reliability Corporation New Jersey Board of Public Utilities Non-Market Based Net Operating Loss Nitrogen Oxide National Pollutant Discharge Elimination System Nuclear Regulatory Commission New Source Review Non-Utility Generation New York State Public Service Commission Office of Consumer Advocate Ohio Consumers' Counsel Ohio Environmental Protection Agency Ohio Manufacturers' Association Energy Group Other Post-Employment Benefits Office and Professional Employees International Union Other Paid-in Capital Occupational Safety and Health Administration Ohio Valley Electric Corporation Pennsylvania Department of Environmental Protection RFC RFP RGGI ROE RSS RSU RTEP RTO S&P SBC SCOH SEC SIP SO2 SOS SPE ReliabilityFirst Corporation Request for Proposal Regional Greenhouse Gas Initiative Return on Equity Rich Site Summary Restricted Stock Unit Regional Transmission Expansion Plan Regional Transmission Organization Standard & Poor’s Ratings Service Societal Benefits Charge Supreme Court of Ohio United States Securities and Exchange Commission State Implementation Plan(s) Under the Clean Air Act Sulfur Dioxide Standard Offer Service Special Purpose Entity SREC Solar Renewable Energy Credit SSO SVC Tax Act TMI-2 Twitter® UCC Standard Service Offer Static Var Compensator Tax Cuts and Jobs Act adopted December 22, 2017 Three Mile Island Unit 2 Twitter is a registered trademark of Twitter, Inc. Official committee of unsecured creditors appointed in connection with the FES Bankruptcy Pollution Control Revenue Bond UWUA Utility Workers Union of America PJM Interconnection, L.L.C. VEPCO Virginia Electric and Power Company PJM Region PJM Tariff The aggregate of the zones within PJM PJM Open Access Transmission Tariff POLR POR PPA Provider of Last Resort Purchase of Receivables Purchase Power Agreement VIE VMS VSCC WVPSC Variable Interest Entity Vegetation Management Surcharge Virginia State Corporation Commission Public Service Commission of West Virginia 3 $ $ $ $ $ 904 908 1.69 0.01 1.67 0.01 (In millions, except per share amounts) 11,035 11,261 10,928 $ 10,700 10,583 $ $ $ $ 1,022 981 1.33 0.66 (289) $ 551 (1,724) $ (6,177) $ $ $ (0.65) $ 1.29 $ (3.23) (15.78) 1.70 $ 1.99 $ (3.88) $ (14.49) $ 1.37 1.33 0.66 $ (0.65) $ 1.29 $ (3.23) (15.78) 1.68 $ 1.99 $ (3.88) $ (14.49) $ 1.37 383 578 0.91 0.46 0.91 0.46 422 424 1.44 Revenues Income (Loss) From Continuing Operations Net Income (Loss) Attributable to Common Stockholders Basic - Continuing Operations Basic - Discontinued Operations Basic - Net Income (Loss) Attributable to Common Stockholders Diluted - Continuing Operations Diluted - Discontinued Operations Diluted - Net Income (Loss) Attributable to Common Stockholders Weighted Average Number of Common Shares Outstanding: Basic Diluted As of December 31, Total Assets Capitalization: Total Equity Dividends Declared per Share of Common Stock 1.53 $ 1.82 $ 1.44 $ 1.44 $ 535 542 492 494 444 444 426 426 Long-Term Debt and Other Long-Term Obligations 19,618 17,751 18,687 15,251 16,444 Total Capitalization 26,593 $ 24,565 $ 22,612 $ 21,492 $ 28,866 42,301 $ 40,063 $ 42,257 $ 43,148 $ 52,094 6,975 $ 6,814 $ 3,925 $ 6,241 $ 12,422 $ $ $ $ $ $ $ $ $ $ $ 4 Manufactured Gas Plants Midcontinent Independent System Operator, Inc. One Million British Thermal Units Moody’s Investors Service, Inc. Megawatt Megawatt-hour Net Asset Value Nuclear Decommissioning Trust Nuclear Electric Insurance Limited North American Electric Reliability Corporation New Jersey Board of Public Utilities Non-Market Based Net Operating Loss Nitrogen Oxide National Pollutant Discharge Elimination System Nuclear Regulatory Commission New Source Review Non-Utility Generation Office of Consumer Advocate Ohio Consumers' Counsel Ohio Environmental Protection Agency Group Other Post-Employment Benefits Office and Professional Employees International Union Other Paid-in Capital Occupational Safety and Health Administration Parts per Billion Pennsylvania Public Utility Commission Public Utilities Commission of Ohio Public Utility Regulatory Policies Act of 1978 Resource Conservation and Recovery Act Renewable Energy Credit ReliabilityFirst Corporation Request for Proposal Regional Greenhouse Gas Initiative Return on Equity Rich Site Summary Restricted Stock Unit Regional Transmission Expansion Plan Regional Transmission Organization Standard & Poor’s Ratings Service Societal Benefits Charge Supreme Court of Ohio Sulfur Dioxide Standard Offer Service Special Purpose Entity Standard Service Offer Static Var Compensator Ohio Valley Electric Corporation Twitter® Twitter is a registered trademark of Twitter, Inc. Pennsylvania Department of Environmental UCC Official committee of unsecured creditors appointed Protection in connection with the FES Bankruptcy Pollution Control Revenue Bond UWUA Utility Workers Union of America PJM Interconnection, L.L.C. VEPCO Virginia Electric and Power Company PJM Region PJM Tariff The aggregate of the zones within PJM PJM Open Access Transmission Tariff Provider of Last Resort Purchase of Receivables Purchase Power Agreement VIE VMS VSCC WVPSC Variable Interest Entity Vegetation Management Surcharge Virginia State Corporation Commission Public Service Commission of West Virginia MGP MISO mmBTU Moody’s MW MWH NAAQS NAV NDT NEIL NERC NJBPU NMB NOL NOx NPDES NRC NSR NUG NYPSC OCA OCC OEPA OMAEG OPEB OPEIU OPIC OSHA OVEC PA DEP PCRB PJM POLR POR PPA PPB PPUC PUCO PURPA RCRA REC RFC RFP RGGI ROE RSS RSU RTEP RTO S&P SBC SCOH SEC SIP SO2 SOS SPE SSO SVC Tax Act TMI-2 3 SELECTED FINANCIAL DATA For the Years Ended December 31, 2019 2018 2017 2016 2015 National Ambient Air Quality Standards Regulation FD Regulation Fair Disclosure promulgated by the SEC Earnings (Loss) per Share of Common Stock: Revenues Income (Loss) From Continuing Operations Net Income (Loss) Attributable to Common Stockholders Basic - Continuing Operations Basic - Discontinued Operations Basic - Net Income (Loss) Attributable to Common Stockholders Diluted - Continuing Operations Diluted - Discontinued Operations Diluted - Net Income (Loss) Attributable to Common Stockholders Weighted Average Number of Common Shares Outstanding: New York State Public Service Commission State Implementation Plan(s) Under the Clean Air Act United States Securities and Exchange Commission Basic Diluted Ohio Manufacturers' Association Energy SREC Solar Renewable Energy Credit Dividends Declared per Share of Common Stock As of December 31, Total Assets Capitalization: Total Equity Tax Cuts and Jobs Act adopted December 22, 2017 Three Mile Island Unit 2 Long-Term Debt and Other Long-Term Obligations Total Capitalization (In millions, except per share amounts) $ $ $ $ 11,035 904 908 1.69 0.01 $ $ $ $ 11,261 1,022 981 1.33 0.66 10,928 $ 10,700 (289) $ 551 $ $ (1,724) $ (6,177) $ (0.65) $ 1.29 $ (3.23) (15.78) 10,583 383 578 0.91 0.46 1.70 $ 1.99 $ (3.88) $ (14.49) $ 1.37 $ 1.67 0.01 1.33 0.66 $ (0.65) $ 1.29 $ (3.23) (15.78) 0.91 0.46 1.68 $ 1.99 $ (3.88) $ (14.49) $ 1.37 535 542 492 494 444 444 426 426 1.53 $ 1.82 $ 1.44 $ 1.44 $ 422 424 1.44 42,301 $ 40,063 $ 42,257 $ 43,148 $ 52,094 6,975 $ 6,814 $ 3,925 $ 6,241 $ 12,422 19,618 17,751 18,687 15,251 16,444 26,593 $ 24,565 $ 22,612 $ 21,492 $ 28,866 $ $ $ $ $ $ $ $ $ $ $ 4 COMMON STOCK MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol “FE” and is traded on other registered exchanges. SHAREHOLDER RETURN The following graph shows the total cumulative return from a $100 investment on December 31, 2014, in FE’s common stock compared with the total cumulative returns of EEI’s Index of Investor-Owned Electric Utility Companies and the S&P 500. HOLDERS OF COMMON STOCK There were 70,622 holders of 540,652,222 shares of FE’s common stock as of December 31, 2019, and 70,327 holders of 540,713,909 shares of FE's common stock as of January 31, 2020. We have historically paid quarterly cash dividends on our common stock. Dividend payments are subject to declaration by the Board and future dividend decisions determined by the Board may be impacted by earnings growth, cash flows, credit metrics and other business conditions. Information regarding retained earnings available for payment of cash dividends is given in Note 11, "Capitalization," of the Notes to Consolidated Financial Statements. 5 6 Forward-Looking Statements: This Annual Report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 based on information currently available. Such statements are subject to certain risks and uncertainties and readers are cautioned not to place undue reliance on these forward-looking statements. These statements include declarations regarding management's intents, beliefs and current expectations, and typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” "forecast," "target," "will," "intend," “believe,” "project," “estimate," "plan" and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements, which may include the following (see Glossary of Terms for definitions of capitalized terms): The ability to successfully execute an exit from commodity-based generation, including, without limitation, mitigating exposure for remedial activities associated with formerly owned generation assets. The ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, our strategy to operate and grow as a fully regulated business, to execute our transmission and distribution investment plans, to continue to reduce costs, and to improve our credit metrics, strengthen our balance sheet and grow earnings. Legislative and regulatory developments, including, but not limited to, matters related to rates, compliance and enforcement activity. Economic and weather conditions affecting future operating results, such as significant weather events and other natural disasters, and associated regulatory events or actions. Changes in assumptions regarding economic conditions within our territories, the reliability of our transmission and distribution system, or the availability of capital or other resources supporting identified transmission and distribution investment opportunities. and peak demand reduction mandates. or others with which we do business. Changes in customers’ demand for power, including, but not limited to, the impact of climate change or energy efficiency Changes in national and regional economic conditions affecting us and/or our major industrial and commercial customers The risks associated with cyber-attacks and other disruptions to our information technology system, which may compromise our operations, and data security breaches of sensitive data, intellectual property and proprietary or personally identifiable information. anticipated. The ability to comply with applicable reliability standards and energy efficiency and peak demand reduction mandates. Changes to environmental laws and regulations, including, but not limited to, those related to climate change. Changing market conditions affecting the measurement of certain liabilities and the value of assets held in our pension trusts and other trust funds, or causing us to make contributions sooner, or in amounts that are larger, than currently The risks associated with the FES Bankruptcy that could adversely affect us, our liquidity or results of operations, including, without limitation, that conditions to the FES Bankruptcy settlement agreement may not be met or that the FES Bankruptcy settlement agreement may not be otherwise consummated, and if so, the potential for litigation and payment demands against us by FES or FENOC or their creditors. The risks associated with the decommissioning of our retired and former nuclear facilities. The risks and uncertainties associated with litigation, arbitration, mediation and like proceedings. Labor disruptions by our unionized workforce. Changes to significant accounting policies. Any changes in tax laws or regulations, or adverse tax audit results or rulings. The ability to access the public securities and other capital and credit markets in accordance with our financial plans, the cost of such capital and overall condition of the capital and credit markets affecting us, including the increasing number of financial institutions evaluating the impact of climate change on their investment decisions. Actions that may be taken by credit rating agencies that could negatively affect either our access to or terms of financing or our financial condition and liquidity. The risks and other factors discussed from time to time in our SEC filings. • • • • • • • • • • • • • • • • • • • • Dividends declared from time to time on our common stock during any period may in the aggregate vary from prior periods due to circumstances considered by our Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating. These forward-looking statements are also qualified by, and should be read together with, the risk factors included in (a) Item 1A. Risk Factors to FE's Form 10-K for the fiscal year ended December 31, 2019, filed with the SEC on February 10, 2020, (b) this Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) other factors discussed herein and in FirstEnergy's other filings with the SEC. The foregoing review of factors also should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on our business or the extent to which any factor, or combination of factors, may cause results to The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol “FE” and is traded on other COMMON STOCK registered exchanges. SHAREHOLDER RETURN The following graph shows the total cumulative return from a $100 investment on December 31, 2014, in FE’s common stock compared with the total cumulative returns of EEI’s Index of Investor-Owned Electric Utility Companies and the S&P 500. HOLDERS OF COMMON STOCK There were 70,622 holders of 540,652,222 shares of FE’s common stock as of December 31, 2019, and 70,327 holders of 540,713,909 shares of FE's common stock as of January 31, 2020. We have historically paid quarterly cash dividends on our common stock. Dividend payments are subject to declaration by the Board and future dividend decisions determined by the Board may be impacted by earnings growth, cash flows, credit metrics and other business conditions. Information regarding retained earnings available for payment of cash dividends is given in Note 11, "Capitalization," of the Notes to Consolidated Financial Statements. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Forward-Looking Statements: This Annual Report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 based on information currently available. Such statements are subject to certain risks and uncertainties and readers are cautioned not to place undue reliance on these forward-looking statements. These statements include declarations regarding management's intents, beliefs and current expectations, and typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” "forecast," "target," "will," "intend," “believe,” "project," “estimate," "plan" and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements, which may include the following (see Glossary of Terms for definitions of capitalized terms): • • • • • • • • • • • • • • • • • • • • The ability to successfully execute an exit from commodity-based generation, including, without limitation, mitigating exposure for remedial activities associated with formerly owned generation assets. The ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, our strategy to operate and grow as a fully regulated business, to execute our transmission and distribution investment plans, to continue to reduce costs, and to improve our credit metrics, strengthen our balance sheet and grow earnings. Legislative and regulatory developments, including, but not limited to, matters related to rates, compliance and enforcement activity. Economic and weather conditions affecting future operating results, such as significant weather events and other natural disasters, and associated regulatory events or actions. Changes in assumptions regarding economic conditions within our territories, the reliability of our transmission and distribution system, or the availability of capital or other resources supporting identified transmission and distribution investment opportunities. Changes in customers’ demand for power, including, but not limited to, the impact of climate change or energy efficiency and peak demand reduction mandates. Changes in national and regional economic conditions affecting us and/or our major industrial and commercial customers or others with which we do business. The risks associated with cyber-attacks and other disruptions to our information technology system, which may compromise our operations, and data security breaches of sensitive data, intellectual property and proprietary or personally identifiable information. The ability to comply with applicable reliability standards and energy efficiency and peak demand reduction mandates. Changes to environmental laws and regulations, including, but not limited to, those related to climate change. Changing market conditions affecting the measurement of certain liabilities and the value of assets held in our pension trusts and other trust funds, or causing us to make contributions sooner, or in amounts that are larger, than currently anticipated. The risks associated with the FES Bankruptcy that could adversely affect us, our liquidity or results of operations, including, without limitation, that conditions to the FES Bankruptcy settlement agreement may not be met or that the FES Bankruptcy settlement agreement may not be otherwise consummated, and if so, the potential for litigation and payment demands against us by FES or FENOC or their creditors. The risks associated with the decommissioning of our retired and former nuclear facilities. The risks and uncertainties associated with litigation, arbitration, mediation and like proceedings. Labor disruptions by our unionized workforce. Changes to significant accounting policies. Any changes in tax laws or regulations, or adverse tax audit results or rulings. The ability to access the public securities and other capital and credit markets in accordance with our financial plans, the cost of such capital and overall condition of the capital and credit markets affecting us, including the increasing number of financial institutions evaluating the impact of climate change on their investment decisions. Actions that may be taken by credit rating agencies that could negatively affect either our access to or terms of financing or our financial condition and liquidity. The risks and other factors discussed from time to time in our SEC filings. Dividends declared from time to time on our common stock during any period may in the aggregate vary from prior periods due to circumstances considered by our Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating. These forward-looking statements are also qualified by, and should be read together with, the risk factors included in (a) Item 1A. Risk Factors to FE's Form 10-K for the fiscal year ended December 31, 2019, filed with the SEC on February 10, 2020, (b) this Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) other factors discussed herein and in FirstEnergy's other filings with the SEC. The foregoing review of factors also should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on our business or the extent to which any factor, or combination of factors, may cause results to 5 6 differ materially from those contained in any forward-looking statements. We expressly disclaim any obligation to update or revise, except as required by law, any forward-looking statements contained herein or in the information incorporated by reference as a result of new information, future events or otherwise. FIRSTENERGY CORP. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FIRSTENERGY’S BUSINESS FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments, Regulated Distribution and Regulated Transmission. The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment's results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs. The service areas of, and customers served by, FirstEnergy's regulated distribution utilities as of December 31, 2019, are summarized below (in thousands): Company Area Served Customers Served JCP&L Northern, Western and East Central New Jersey OE Penn CEI TE ME PN WP MP PE Central and Northeastern Ohio Western Pennsylvania Northeastern Ohio Northwestern Ohio Eastern Pennsylvania Western Pennsylvania and Western New York Southwest, South Central and Northern Pennsylvania Northern, Central and Southeastern West Virginia Western Maryland and Eastern West Virginia 1,055 1,142 168 752 313 575 587 729 392 419 6,132 The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are primarily derived from forward-looking formula rates at the Transmission Companies as well as stated transmission rates at JCP&L, MP, PE and WP. Effective January 1, 2020, JPC&L's transmission rates became forward-looking formula rates, subject to refund, pending further hearing and settlement proceedings. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities. Corporate/Other reflects corporate support not charged to FE's subsidiaries, interest expense on FE’s holding company debt and other businesses that do not constitute an operating segment. Additionally, reconciling adjustments for the elimination of inter- segment transactions and discontinued operations are included in Corporate/Other. As of December 31, 2019, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was included in continuing operations of Corporate/ Other. As of December 31, 2019, Corporate/Other had approximately $7.1 billion of FE holding company debt. 7 8 differ materially from those contained in any forward-looking statements. We expressly disclaim any obligation to update or revise, except as required by law, any forward-looking statements contained herein or in the information incorporated by reference as a result of new information, future events or otherwise. FIRSTENERGY CORP. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FIRSTENERGY’S BUSINESS FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments, Regulated Distribution and Regulated Transmission. The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment's results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs. The service areas of, and customers served by, FirstEnergy's regulated distribution utilities as of December 31, 2019, are summarized below (in thousands): Company OE Penn CEI TE JCP&L ME PN WP MP PE Area Served Customers Served Central and Northeastern Ohio Western Pennsylvania Northeastern Ohio Northwestern Ohio Northern, Western and East Central New Jersey Eastern Pennsylvania Western Pennsylvania and Western New York Southwest, South Central and Northern Pennsylvania Northern, Central and Southeastern West Virginia Western Maryland and Eastern West Virginia 1,055 168 752 313 1,142 575 587 729 392 419 6,132 The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are primarily derived from forward-looking formula rates at the Transmission Companies as well as stated transmission rates at JCP&L, MP, PE and WP. Effective January 1, 2020, JPC&L's transmission rates became forward-looking formula rates, subject to refund, pending further hearing and settlement proceedings. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities. Corporate/Other reflects corporate support not charged to FE's subsidiaries, interest expense on FE’s holding company debt and other businesses that do not constitute an operating segment. Additionally, reconciling adjustments for the elimination of inter- segment transactions and discontinued operations are included in Corporate/Other. As of December 31, 2019, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was included in continuing operations of Corporate/ Other. As of December 31, 2019, Corporate/Other had approximately $7.1 billion of FE holding company debt. 7 8 As previously disclosed, on January 22, 2018, FirstEnergy announced a $2.5 billion equity issuance, which included $1.62 billion in mandatorily convertible preferred equity with an initial conversion price of $27.42 per share and $850 million of common equity issued at $28.22 per share. The equity investment strengthened the Company’s balance sheet, supported the company’s transition to a fully regulated utility company and positions FirstEnergy for sustained investment-grade credit metrics. The shares of preferred stock participated in the dividend paid on common stock on an as-converted basis and were non-voting except in certain limited circumstances. Because of this investment, FirstEnergy does not currently anticipate the need to issue additional equity through 2021 and expects to issue, subject to, among other things, market conditions, pricing terms and business operations, up to $600 million of equity annually in 2022 and 2023, including approximately $100 million in equity for its regular stock investment and employee benefit plans. As of August 1, 2019, an aggregate of 1,616,000 shares of preferred stock had been converted into 58,935,078 shares of common stock, and as a result, there were no shares of preferred stock outstanding as of December 31, 2019. On March 31, 2018, FirstEnergy's competitive subsidiary the FES Debtors voluntarily filed petitions under Chapter 11 of the Federal Bankruptcy Code with the U.S. Bankruptcy Court. FirstEnergy and its other subsidiaries - including its Utilities and AE Supply - are not part of the filing and are not subject to the Chapter 11 process. The voluntary bankruptcy filings by the FES Debtors represented a significant event in FirstEnergy’s previously announced strategy to exit the competitive generation business and become a fully regulated utility company with a stronger balance sheet, solid cash flows and more predictable earnings. As a result of the bankruptcy filings, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy’s financial statements. Additionally, the operating results of the FES Debtors, as well as BSPC and a portion of AE Supply (including the Pleasants Power Station) that were subject to completed or pending asset sales, collectively representing substantially all of FirstEnergy’s operations that comprised the CES reportable segment, are presented as discontinued operations. Prior periods have been reclassified to conform with such presentation as discontinued operations. On April 23, 2018, FirstEnergy and the FES Key Creditor Groups reached an agreement in principle to resolve certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and their creditors against FirstEnergy. On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy. See below for further discussion on the terms of the settlement agreement. The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements. With the bankruptcy filings of the FES Debtors, the completed sale of the previously announced competitive Bath hydroelectric station, and the completed transfer of the Pleasants Power Station, FirstEnergy’s electric generation fleet is now made up of 3,790 MW of regulated generation, including four plants in West Virginia, Virginia and New Jersey. The Form 10-K discusses 2019 and 2018 items and year-over-year comparisons between 2019 and 2018. Discussions of 2017 items and year-over-year comparisons between 2018 and 2017 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018, filed with the SEC on February 19, 2019. EXECUTIVE SUMMARY FirstEnergy is a forward-thinking fully regulated electric utility focused on stable and predictable earnings and cash flow from its regulated business units - Regulated Distribution and Regulated Transmission - through delivering enhanced customer service and reliability that supports FE's dividend. In 2019, FirstEnergy continued its significant progress of executing on its regulated growth plans, which included the following achievements: NJ BPU-approved JCP&L IIP settlement, PUCO-approved Ohio Grid Modernization plan and Tax Reform settlement, PUCO-approved Ohio Companies’ decoupling application, • MDPSC-approved distribution base rate increase, • MDPSC-approved EDIS programs, • • • • WVPSC-approved ENEC rates that began January 1, 2020, • • Filed for forward-looking formula rates for JCP&L’s transmission assets, Pennsylvania Companies filed LTIIP II plans for 2020-2024, including a DSIC cap increase at Penn to 7.5%, approved in January 2020, Signed an agreement to transfer TMI-2 to a subsidiary of EnergySolutions, LLC, Received credit ratings upgrades from Fitch Ratings at FE and all rated Utility and Transmission subsidiaries, Received credit ratings upgrades from Moody's at ATSI, CEI, JCP&L, MAIT, OE, Penn and TE, Announced that the FE Board of Directors approved a 3% increase to the dividend payable March 1, 2020, and Published a Strategic Plan and a Corporate Responsibility Report as part of our forward-thinking strategy and commitment to ESG issues. • • • • • With an operating territory of 65,000 square miles, the scale and diversity of the ten Utilities that comprise the Regulated Distribution business uniquely position this business for growth through opportunities for additional investment. Over the past several years, Regulated Distribution has experienced rate base growth through investments that have improved reliability and added operating flexibility to the distribution infrastructure, which provide benefits to the customers and communities those Utilities serve. Based on its current capital plan, which includes over $10 billion in forecasted capital investments from 2018 through 2023, Regulated Distribution’s rate base compounded annual growth rate is expected to be approximately 4% from 2018 through 2023. Additionally, this business is exploring other opportunities for growth, including investments in electric system improvement and modernization projects to increase reliability and improve service to customers, as well as exploring opportunities in customer engagement that focus on the electrification of customers’ homes and businesses by providing a full range of products and services. With approximately 24,500 miles of transmission lines in operation, the Regulated Transmission business is the centerpiece of FirstEnergy’s regulated investment strategy with nearly 90% of its capital investments recovered under forward-looking formula rates at the Transmission Companies, and beginning in 2020, JCP&L. Regulated Transmission has also experienced significant growth as part of its Energizing the Future transmission plan with plans to invest over $7 billion in capital from 2018 to 2023, which is expected to result in Regulated Transmission rate base compounded annual growth rate of approximately 10% from 2018 through 2023. As part of the Energizing the Future initiative, the Center for Advanced Technology was opened in Akron, Ohio in April 2019. The 88,000 square feet facility was designed to be a hands-on environment where engineers and technicians can develop and evaluate new technology and grid solutions and simulate a variety of real-world conditions. FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion beyond those identified through 2023, which are expected to strengthen grid and cyber-security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility. In November 2018, the Board of Directors approved a dividend policy that includes a targeted payout ratio. As a first step, the Board declared a $0.02 increase to the common dividend payable March 1, 2019, to $0.38 per share, which represents an increase of 6% compared to the quarterly dividend of $0.36 per share that has been paid since 2014. In November 2019, the Board declared a $0.01 increase to the common dividend payable March 1, 2020, to $0.39 per share, which represents a 3% increase. Modest dividend growth enables enhanced shareholder returns, while still allowing for continued substantial regulated investments. Dividend payments are subject to declaration by the Board and future dividend decisions determined by the Board may be impacted by earnings growth, cash flows, credit metrics and other business conditions. FirstEnergy is progressing in its sustainability efforts. In 2019, FirstEnergy's Sustainability group focused on the continued realization of sustainability accomplishments. In November 2019, FirstEnergy's Corporate Responsibility Report was published. The report addresses FirstEnergy's work to reduce the environmental impact of our operations, including progress on our CO2 reduction goal, as we continue to build, strengthen and modernize our transmission and distribution system. The report also describes FirstEnergy's high standards for corporate governance and our work to improve lives in our communities, while providing safe, reliable electric service to our customers. In 2020, FirstEnergy is focusing on additional initiatives that aim to inform, engage and achieve its sustainability goals, and demonstrate its commitment to stakeholders. 9 10 As previously disclosed, on January 22, 2018, FirstEnergy announced a $2.5 billion equity issuance, which included $1.62 billion in mandatorily convertible preferred equity with an initial conversion price of $27.42 per share and $850 million of common equity issued at $28.22 per share. The equity investment strengthened the Company’s balance sheet, supported the company’s transition to a fully regulated utility company and positions FirstEnergy for sustained investment-grade credit metrics. The shares of preferred stock participated in the dividend paid on common stock on an as-converted basis and were non-voting except in certain limited circumstances. Because of this investment, FirstEnergy does not currently anticipate the need to issue additional equity through 2021 and expects to issue, subject to, among other things, market conditions, pricing terms and business operations, up to $600 million of equity annually in 2022 and 2023, including approximately $100 million in equity for its regular stock investment and employee benefit plans. As of August 1, 2019, an aggregate of 1,616,000 shares of preferred stock had been converted into 58,935,078 shares of common stock, and as a result, there were no shares of preferred stock outstanding as of December 31, 2019. On March 31, 2018, FirstEnergy's competitive subsidiary the FES Debtors voluntarily filed petitions under Chapter 11 of the Federal Bankruptcy Code with the U.S. Bankruptcy Court. FirstEnergy and its other subsidiaries - including its Utilities and AE Supply - are not part of the filing and are not subject to the Chapter 11 process. The voluntary bankruptcy filings by the FES Debtors represented a significant event in FirstEnergy’s previously announced strategy to exit the competitive generation business and become a fully regulated utility company with a stronger balance sheet, solid cash flows and more predictable earnings. As a result of the bankruptcy filings, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy’s financial statements. Additionally, the operating results of the FES Debtors, as well as BSPC and a portion of AE Supply (including the Pleasants Power Station) that were subject to completed or pending asset sales, collectively representing substantially all of FirstEnergy’s operations that comprised the CES reportable segment, are presented as discontinued operations. Prior periods have been reclassified to conform with such presentation as discontinued operations. On April 23, 2018, FirstEnergy and the FES Key Creditor Groups reached an agreement in principle to resolve certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and their creditors against FirstEnergy. On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy. See below for further discussion on the terms of the settlement agreement. The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements. With the bankruptcy filings of the FES Debtors, the completed sale of the previously announced competitive Bath hydroelectric station, and the completed transfer of the Pleasants Power Station, FirstEnergy’s electric generation fleet is now made up of 3,790 MW of regulated generation, including four plants in West Virginia, Virginia and New Jersey. The Form 10-K discusses 2019 and 2018 items and year-over-year comparisons between 2019 and 2018. Discussions of 2017 items and year-over-year comparisons between 2018 and 2017 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018, filed with the SEC on February 19, 2019. EXECUTIVE SUMMARY FirstEnergy is a forward-thinking fully regulated electric utility focused on stable and predictable earnings and cash flow from its regulated business units - Regulated Distribution and Regulated Transmission - through delivering enhanced customer service and reliability that supports FE's dividend. In 2019, FirstEnergy continued its significant progress of executing on its regulated growth plans, which included the following achievements: • • • • • • • • • • • MDPSC-approved distribution base rate increase, • MDPSC-approved EDIS programs, NJ BPU-approved JCP&L IIP settlement, PUCO-approved Ohio Grid Modernization plan and Tax Reform settlement, PUCO-approved Ohio Companies’ decoupling application, • WVPSC-approved ENEC rates that began January 1, 2020, Filed for forward-looking formula rates for JCP&L’s transmission assets, Pennsylvania Companies filed LTIIP II plans for 2020-2024, including a DSIC cap increase at Penn to 7.5%, approved in January 2020, to ESG issues. Signed an agreement to transfer TMI-2 to a subsidiary of EnergySolutions, LLC, Received credit ratings upgrades from Fitch Ratings at FE and all rated Utility and Transmission subsidiaries, Received credit ratings upgrades from Moody's at ATSI, CEI, JCP&L, MAIT, OE, Penn and TE, Announced that the FE Board of Directors approved a 3% increase to the dividend payable March 1, 2020, and Published a Strategic Plan and a Corporate Responsibility Report as part of our forward-thinking strategy and commitment With an operating territory of 65,000 square miles, the scale and diversity of the ten Utilities that comprise the Regulated Distribution business uniquely position this business for growth through opportunities for additional investment. Over the past several years, Regulated Distribution has experienced rate base growth through investments that have improved reliability and added operating flexibility to the distribution infrastructure, which provide benefits to the customers and communities those Utilities serve. Based on its current capital plan, which includes over $10 billion in forecasted capital investments from 2018 through 2023, Regulated Distribution’s rate base compounded annual growth rate is expected to be approximately 4% from 2018 through 2023. Additionally, this business is exploring other opportunities for growth, including investments in electric system improvement and modernization projects to increase reliability and improve service to customers, as well as exploring opportunities in customer engagement that focus on the electrification of customers’ homes and businesses by providing a full range of products and services. With approximately 24,500 miles of transmission lines in operation, the Regulated Transmission business is the centerpiece of FirstEnergy’s regulated investment strategy with nearly 90% of its capital investments recovered under forward-looking formula rates at the Transmission Companies, and beginning in 2020, JCP&L. Regulated Transmission has also experienced significant growth as part of its Energizing the Future transmission plan with plans to invest over $7 billion in capital from 2018 to 2023, which is expected to result in Regulated Transmission rate base compounded annual growth rate of approximately 10% from 2018 through 2023. As part of the Energizing the Future initiative, the Center for Advanced Technology was opened in Akron, Ohio in April 2019. The 88,000 square feet facility was designed to be a hands-on environment where engineers and technicians can develop and evaluate new technology and grid solutions and simulate a variety of real-world conditions. FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion beyond those identified through 2023, which are expected to strengthen grid and cyber-security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility. In November 2018, the Board of Directors approved a dividend policy that includes a targeted payout ratio. As a first step, the Board declared a $0.02 increase to the common dividend payable March 1, 2019, to $0.38 per share, which represents an increase of 6% compared to the quarterly dividend of $0.36 per share that has been paid since 2014. In November 2019, the Board declared a $0.01 increase to the common dividend payable March 1, 2020, to $0.39 per share, which represents a 3% increase. Modest dividend growth enables enhanced shareholder returns, while still allowing for continued substantial regulated investments. Dividend payments are subject to declaration by the Board and future dividend decisions determined by the Board may be impacted by earnings growth, cash flows, credit metrics and other business conditions. FirstEnergy is progressing in its sustainability efforts. In 2019, FirstEnergy's Sustainability group focused on the continued realization of sustainability accomplishments. In November 2019, FirstEnergy's Corporate Responsibility Report was published. The report addresses FirstEnergy's work to reduce the environmental impact of our operations, including progress on our CO2 reduction goal, as we continue to build, strengthen and modernize our transmission and distribution system. The report also describes FirstEnergy's high standards for corporate governance and our work to improve lives in our communities, while providing safe, reliable electric service to our customers. In 2020, FirstEnergy is focusing on additional initiatives that aim to inform, engage and achieve its sustainability goals, and demonstrate its commitment to stakeholders. 9 10 RESULTS OF OPERATIONS Summary of Results of Operations — 2019 Compared with 2018 The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 17, "Segment Information," of the Notes to Consolidated Financial Statements. Certain prior year amounts have been reclassified to conform to the current year presentation. Net income (loss) by business segment was as follows: (In millions, except per share amounts) For the Years Ended December 31, Increase (Decrease) 2019 2018 2017 2019 vs 2018 2018 vs 2017 Net Income (Loss) By Business Segment: Regulated Distribution Regulated Transmission Corporate/Other Income (Loss) from Continuing Operations Discontinued Operations Net Income (Loss) Earnings (Loss) per share of common stock Basic - Continuing Operations Basic - Discontinued Operations Basic - Net Income (Loss) Attributable to Common Stockholders Earnings (Loss) per share of common stock Diluted - Continuing Operations Diluted - Discontinued Operations Diluted - Net Income (Loss) Attributable to Common Stockholders $ $ $ $ $ $ $ 1,076 $ 1,242 $ 447 (619) 397 (617) $ 916 336 (1,541) (166) $ 50 (2) 904 $ 1,022 $ (289) $ (118) $ 8 326 (1,435) (318) 912 $ 1,348 $ (1,724) $ (436) $ 326 61 924 1,311 1,761 3,072 $ 1.69 0.01 1.33 0.66 $ (0.65) $ (3.23) 0.36 $ (0.65) 1.98 3.89 1.70 $ 1.99 $ (3.88) $ (0.29) $ 5.87 $ 1.67 0.01 $ 1.33 0.66 (0.65) $ (3.23) $ 0.34 (0.65) 1.98 3.89 1.68 $ 1.99 $ (3.88) $ (0.31) $ 5.87 Financial results for FirstEnergy’s business segments for the years ended December 31, 2019 and 2018, were as follows: Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated (In millions) $ 9,452 $ 1,510 $ (128) $ Amortization (deferral) of regulatory assets, net 2019 Financial Results Revenues: Electric Other Total Revenues Operating Expenses: Fuel Purchased power Other operating expenses Provision for depreciation General taxes Total Operating Expenses Operating Income (Loss) Other Income (Expense): Miscellaneous income, net Interest expense Capitalized financing costs Total Other Expense Pension and OPEB mark-to-market adjustment Income (Loss) Before Income Taxes (Benefits) Income taxes (benefits) Income (Loss) From Continuing Operations Discontinued Operations, net of tax 246 9,698 497 2,910 2,836 863 (89) 760 7,777 1,921 174 (290) (495) 37 (574) 1,347 271 1,076 — 16 1,526 — — 272 284 10 209 775 751 15 (47) (192) 33 (191) 560 113 447 — (61) (189) (156) — 17 73 — 39 (27) (162) 54 (337) (346) 1 (628) (790) (171) (619) 8 10,834 201 11,035 497 2,927 2,952 1,220 (79) 1,008 8,525 2,510 243 (674) (1,033) 71 (1,393) 1,117 213 904 8 912 Net Income (Loss) $ 1,076 $ 447 $ (611) $ 11 12 RESULTS OF OPERATIONS Summary of Results of Operations — 2019 Compared with 2018 The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. Financial results for FirstEnergy’s business segments for the years ended December 31, 2019 and 2018, were as follows: A reconciliation of segment financial results is provided in Note 17, "Segment Information," of the Notes to Consolidated Financial Statements. Certain prior year amounts have been reclassified to conform to the current year presentation. Net income (loss) by business segment was as follows: (In millions, except per share amounts) For the Years Ended December 31, Increase (Decrease) 2019 2018 2017 2019 vs 2018 2018 vs 2017 Net Income (Loss) By Business Segment: Regulated Distribution Regulated Transmission Corporate/Other 1,076 $ 1,242 $ 447 (619) 397 (617) $ 916 336 (1,541) (166) $ 50 (2) Income (Loss) from Continuing Operations 904 $ 1,022 $ (289) $ (118) $ Discontinued Operations 8 326 (1,435) (318) 326 61 924 1,311 1,761 3,072 Earnings (Loss) per share of common stock Basic - Continuing Operations Basic - Discontinued Operations Basic - Net Income (Loss) Attributable to Earnings (Loss) per share of common stock Diluted - Continuing Operations Diluted - Discontinued Operations Diluted - Net Income (Loss) Attributable to $ 1.69 0.01 1.33 0.66 $ (0.65) $ (3.23) 0.36 $ (0.65) 1.98 3.89 Common Stockholders 1.70 $ 1.99 $ (3.88) $ (0.29) $ 5.87 $ 1.67 0.01 1.33 0.66 $ (0.65) $ (3.23) 0.34 $ (0.65) 1.98 3.89 Common Stockholders 1.68 $ 1.99 $ (3.88) $ (0.31) $ 5.87 $ $ $ $ $ $ $ Net Income (Loss) 912 $ 1,348 $ (1,724) $ (436) $ Amortization (deferral) of regulatory assets, net 2019 Financial Results Revenues: Electric Other Total Revenues Operating Expenses: Fuel Purchased power Other operating expenses Provision for depreciation General taxes Total Operating Expenses Operating Income (Loss) Other Income (Expense): Miscellaneous income, net Pension and OPEB mark-to-market adjustment Interest expense Capitalized financing costs Total Other Expense Income (Loss) Before Income Taxes (Benefits) Income taxes (benefits) Income (Loss) From Continuing Operations Discontinued Operations, net of tax Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated (In millions) $ 9,452 $ 1,510 $ (128) $ 246 9,698 497 2,910 2,836 863 (89) 760 7,777 1,921 174 (290) (495) 37 (574) 1,347 271 1,076 — 16 1,526 — — 272 284 10 209 775 751 15 (47) (192) 33 (191) 560 113 447 — (61) (189) — 17 (156) 73 — 39 (27) (162) 54 (337) (346) 1 (628) (790) (171) (619) 8 10,834 201 11,035 497 2,927 2,952 1,220 (79) 1,008 8,525 2,510 243 (674) (1,033) 71 (1,393) 1,117 213 904 8 912 Net Income (Loss) $ 1,076 $ 447 $ (611) $ 11 12 Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated Changes Between 2019 and 2018 Financial Results Increase (Decrease) Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated 2018 Financial Results Revenues: Electric Other Total Revenues Operating Expenses: Fuel Purchased power Other operating expenses Provision for depreciation Amortization (deferral) of regulatory assets, net General taxes Total Operating Expenses Operating Income (Loss) Other Income (Expense): Miscellaneous income (expense), net Pension and OPEB mark-to-market adjustment Interest expense Capitalized financing costs Total Other Expense Income (Loss) Before Income Taxes (Benefits) Income taxes (benefits) Income (Loss) From Continuing Operations Discontinued Operations, net of tax (In millions) $ 9,851 $ 1,335 $ (136) $ 252 10,103 18 1,353 538 3,103 2,984 812 (163) 760 8,034 2,069 192 (109) (514) 26 (405) 1,664 422 1,242 — — — 253 252 13 192 710 643 14 (8) (167) 37 (124) 519 122 397 — (59) (195) — 6 (104) 72 — 41 15 (210) (1) (27) (435) 2 (461) (671) (54) (617) 326 Net Income (Loss) $ 1,242 $ 397 $ (291) $ 11,050 211 11,261 538 3,109 3,133 1,136 (150) 993 8,759 2,502 205 (144) (1,116) 65 (990) 1,512 490 1,022 326 1,348 Revenues: Electric Other Total Revenues Operating Expenses: Fuel Purchased power Other operating expenses Provision for depreciation General taxes Total Operating Expenses Operating Income (Loss) Other Income (Expense): Amortization (deferral) of regulatory assets, net Miscellaneous income (expense), net Pension and OPEB mark-to-market adjustment Interest expense Capitalized financing costs Total Other Expense Income (Loss) Before Income Taxes (Benefits) Income taxes (benefits) Income (Loss) From Continuing Operations Discontinued Operations, net of tax $ (399) $ (In millions) 175 $ (2) 173 8 $ (2) 6 (6) (405) (41) (193) (148) 51 74 — (257) (148) (18) (181) 19 11 (169) (317) (151) (166) — — — 19 32 (3) 17 65 108 1 (39) (25) (4) (67) 41 (9) 50 — 50 (52) — 11 1 — (2) (42) 48 55 (310) 89 (1) (167) (119) (117) (2) (318) Net Income (Loss) $ (166) $ $ (320) $ (216) (10) (226) (41) (182) (181) 84 71 15 8 (234) (530) 38 83 6 (403) (395) (277) (118) (318) (436) 13 14 Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated Changes Between 2019 and 2018 Financial Results Increase (Decrease) Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated Amortization (deferral) of regulatory assets, net Amortization (deferral) of regulatory assets, net Revenues: Electric Other Total Revenues Operating Expenses: Fuel Purchased power Other operating expenses Provision for depreciation General taxes Total Operating Expenses Operating Income (Loss) Other Income (Expense): Miscellaneous income (expense), net Pension and OPEB mark-to-market adjustment Interest expense Capitalized financing costs Total Other Expense Income (Loss) Before Income Taxes (Benefits) Income taxes (benefits) Income (Loss) From Continuing Operations Discontinued Operations, net of tax $ (399) $ (6) (405) (41) (193) (148) 51 74 — (257) (148) (18) (181) 19 11 (169) (317) (151) (166) — Net Income (Loss) $ 1,242 $ 397 $ (291) $ Net Income (Loss) $ (166) $ (In millions) 175 $ (2) 173 8 $ (2) 6 — — 19 32 (3) 17 65 108 1 (39) (25) (4) (67) 41 (9) 50 — 50 — 11 (52) 1 — (2) (42) 48 55 (310) 89 (1) (167) (119) (117) (2) (318) $ (320) $ (216) (10) (226) (41) (182) (181) 84 71 15 (234) 8 38 (530) 83 6 (403) (395) (277) (118) (318) (436) 2018 Financial Results Revenues: Electric Other Total Revenues Operating Expenses: Fuel Purchased power Other operating expenses Provision for depreciation General taxes Total Operating Expenses Operating Income (Loss) Other Income (Expense): Miscellaneous income (expense), net Pension and OPEB mark-to-market adjustment Interest expense Capitalized financing costs Total Other Expense Income (Loss) Before Income Taxes (Benefits) Income taxes (benefits) Income (Loss) From Continuing Operations Discontinued Operations, net of tax (In millions) $ 9,851 $ 1,335 $ (136) $ 252 10,103 18 1,353 538 3,103 2,984 812 (163) 760 8,034 2,069 192 (109) (514) 26 (405) 1,664 422 1,242 — — — 253 252 13 192 710 643 14 (8) (167) 37 (124) 519 122 397 — (59) (195) (104) — 6 72 — 41 15 (210) (1) (27) (435) 2 (461) (671) (54) (617) 326 11,050 211 11,261 538 3,109 3,133 1,136 (150) 993 8,759 2,502 205 (144) (1,116) 65 (990) 1,512 490 1,022 326 1,348 13 14 Regulated Distribution — 2019 Compared with 2018 The following table summarizes the price and volume factors contributing to the $300 million decrease in generation revenues in 2019, as compared to 2018: Regulated Distribution's net income decreased $166 million in 2019, as compared to 2018, primarily resulting from the SCOH ruling that ceased collection of Rider DMR, a higher pension and OPEB mark-to-market adjustment, the absence of the reversal of a reserve on recoverability of certain REC purchases in Ohio, and lower revenues associated with decreased weather-related usage. Revenues — The $405 million decrease in total revenues resulted from the following sources: Revenues by Type of Service 2019 2018 Decrease Distribution services (1) $ 5,314 $ 5,413 $ (99) (In millions) For the Years Ended December 31, Generation sales: Retail Wholesale Total generation sales Other 3,727 411 4,138 246 3,936 502 4,438 252 (209) (91) (300) (6) Source of Change in Generation Revenues Retail: Change in prices Effect of decrease in sales volumes $ Increase (Decrease) (In millions) Wholesale: Effect of increase in sales volumes Change in prices Capacity revenue (2) (207) (209) 2 (51) (42) (91) Decrease in Generation Revenues $ (300) Total generation provided by alternative suppliers as a percentage of total MWH deliveries was flat. The decrease in retail generation prices primarily resulted from lower non-shopping generation auction rates across all service territories and a lower ENEC rate in West Virginia, which included rate reductions resulting from the Tax Act. Wholesale generation revenues decreased $91 million in 2019, as compared to 2018, primarily due to lower spot market energy prices and capacity revenue. The difference between current wholesale generation revenues and certain energy costs incurred are deferred for future recovery or refund, with no material impact to earnings. $ (1) Includes $181 million and $254 million of ARP revenues for the years ended December 31, 2019 and 2018, respectively. Total Revenues 10,103 9,698 (405) $ $ Distribution services revenues decreased $99 million in 2019, as compared to 2018, primarily resulting from the SCOH ruling that ceased collection of Rider DMR, lower weather-related customer usage, and the implementation of rate orders and settlements related to the Tax Act, partially offset by implementation of NJ Zero Emission Program in June 2019 and higher rates associated with the recovery of deferred costs. Distribution deliveries by customer class are summarized in the following table: Operating Expenses — Total operating expenses decreased $257 million primarily due to the following: Electric Distribution MWH Deliveries 2019 2018 Decrease For the Years Ended December 31, • • Fuel expense decreased $41 million in 2019, as compared to 2018, primarily due to lower unit costs. Purchased power costs decreased $193 million in 2019, as compared to 2018, primarily due to lower unit costs and capacity expense, partially offset by the implementation of the NJ Zero Emission Program in June 2019. Residential Commercial Industrial Other (In thousands) 54,159 37,330 55,649 558 55,994 38,605 56,611 560 Total Electric Distribution MWH Deliveries 147,696 151,770 (3.3)% (3.3)% (1.7)% (0.4)% (2.7)% Lower distribution deliveries to residential and commercial customers primarily reflect lower weather-related usage resulting from cooling degree days that were 16% below 2018, but 16% above normal, as well as, heating degree days that were 5% below 2018, and 4% below normal. Deliveries to industrial customers reflect lower steel and automotive customer usage, partially offset by higher shale customer usage. Source of Change in Purchased Power Purchases from non-affiliates: Change due to decreased unit costs $ Change due to increased volumes Increase (Decrease) (In millions) Purchases from affiliates: Change due to decreased unit costs Change due to decreased volumes Capacity expense Decrease in Purchased Power Costs $ (82) 89 7 (9) (138) (147) (53) (193) 15 16 Regulated Distribution — 2019 Compared with 2018 Regulated Distribution's net income decreased $166 million in 2019, as compared to 2018, primarily resulting from the SCOH ruling that ceased collection of Rider DMR, a higher pension and OPEB mark-to-market adjustment, the absence of the reversal of a reserve on recoverability of certain REC purchases in Ohio, and lower revenues associated with decreased weather-related usage. Revenues — The $405 million decrease in total revenues resulted from the following sources: Revenues by Type of Service 2019 2018 Decrease Distribution services (1) $ 5,314 $ 5,413 $ (99) For the Years Ended December 31, (In millions) Generation sales: Retail Wholesale Total generation sales Other Total Revenues 3,727 411 4,138 246 3,936 502 4,438 252 $ 9,698 $ 10,103 $ (209) (91) (300) (6) (405) (1) Includes $181 million and $254 million of ARP revenues for the years ended December 31, 2019 and 2018, respectively. Residential Commercial Industrial Other For the Years Ended December 31, (In thousands) 54,159 37,330 55,649 558 55,994 38,605 56,611 560 (3.3)% (3.3)% (1.7)% (0.4)% (2.7)% Total Electric Distribution MWH Deliveries 147,696 151,770 Lower distribution deliveries to residential and commercial customers primarily reflect lower weather-related usage resulting from cooling degree days that were 16% below 2018, but 16% above normal, as well as, heating degree days that were 5% below 2018, and 4% below normal. Deliveries to industrial customers reflect lower steel and automotive customer usage, partially offset by higher shale customer usage. The following table summarizes the price and volume factors contributing to the $300 million decrease in generation revenues in 2019, as compared to 2018: Source of Change in Generation Revenues Increase (Decrease) (In millions) Retail: Effect of decrease in sales volumes $ Change in prices Wholesale: Effect of increase in sales volumes Change in prices Capacity revenue (2) (207) (209) 2 (51) (42) (91) Decrease in Generation Revenues $ (300) Total generation provided by alternative suppliers as a percentage of total MWH deliveries was flat. The decrease in retail generation prices primarily resulted from lower non-shopping generation auction rates across all service territories and a lower ENEC rate in West Virginia, which included rate reductions resulting from the Tax Act. Wholesale generation revenues decreased $91 million in 2019, as compared to 2018, primarily due to lower spot market energy prices and capacity revenue. The difference between current wholesale generation revenues and certain energy costs incurred are deferred for future recovery or refund, with no material impact to earnings. Distribution services revenues decreased $99 million in 2019, as compared to 2018, primarily resulting from the SCOH ruling that ceased collection of Rider DMR, lower weather-related customer usage, and the implementation of rate orders and settlements related to the Tax Act, partially offset by implementation of NJ Zero Emission Program in June 2019 and higher rates associated with the recovery of deferred costs. Distribution deliveries by customer class are summarized in the following table: Operating Expenses — Total operating expenses decreased $257 million primarily due to the following: Electric Distribution MWH Deliveries 2019 2018 Decrease • • Fuel expense decreased $41 million in 2019, as compared to 2018, primarily due to lower unit costs. Purchased power costs decreased $193 million in 2019, as compared to 2018, primarily due to lower unit costs and capacity expense, partially offset by the implementation of the NJ Zero Emission Program in June 2019. Source of Change in Purchased Power Purchases from non-affiliates: Change due to decreased unit costs $ Change due to increased volumes Purchases from affiliates: Change due to decreased unit costs Change due to decreased volumes Capacity expense Decrease in Purchased Power Costs $ Increase (Decrease) (In millions) (82) 89 7 (9) (138) (147) (53) (193) 15 16 • Other operating expenses decreased $148 million primarily due to: Revenues by transmission asset owner are shown in the following table: • • • • • • Decreased storm restoration costs of $129 million, which were mostly deferred for future recovery, resulting in no material impact on current period earnings. Lower operating and maintenance expenses of $49 million, primarily associated with lower employee benefits and corporate support costs. Decreased expenses due to transactions now accounted for as finance leases of $21 million. As a result of the adoption of the new lease accounting standard, financing lease expenses that were recognized in other operating expenses are now recognized in depreciation and interest expense. The absence of $30 million in costs that occurred in 2018 associated with the voluntary enhanced retirement program. Lower energy efficiency and other program costs of $27 million, partially offset by higher vegetation management spend of $13 million. These costs are deferred for future recovery, resulting in no material impact on current period earnings. Higher network transmission expenses of $95 million reflecting increased transmission costs as well as the absence of the FERC settlement during 2018 that reallocated certain transmission costs across utilities in PJM and resulted in a refund to the Ohio Companies. Except for certain transmission costs and credits at the Ohio Companies recognized in 2018, the difference between current revenues and transmission costs incurred are deferred for future recovery or refund, resulting in no material impact on current period earnings. Revenues by Transmission Asset Owner 2019 2018 Increase For the Years Ended December 31, (In millions) $ 668 $ 246 154 285 758 251 227 290 90 5 73 5 $ $ Total Revenues 1,526 $ 1,353 $ 173 ATSI TrAIL MAIT Other Operating Expenses — Total operating expenses increased $65 million in 2019, as compared to 2018, primarily due to higher operating and maintenance expenses, as well as higher property taxes and depreciation due to a higher asset base. The majority of the increases are recovered through formula rates at ATSI and MAIT, resulting in no material impact on current period earnings. • • Depreciation expense increased $51 million, primarily due to a higher asset base and transactions now accounted for as finance leases, as discussed above. Other Expense — Net amortization expense increased $74 million, primarily due to decreased storm restoration cost deferrals, the absence of the reversal of a liability at the Ohio Companies for an Ohio Supreme Court ruling regarding the purchase of RECs, partially offset by higher deferrals of generation and transmission expenses, including the FERC settlement discussed above and the termination of the Morgantown Energy Associates PPA. Total other expense increased $67 million in 2019, as compared to 2018, primarily due to an increase in the 2019 pension and OPEB mark-to-market adjustment and higher interest expense associated with new debt issuances at ATSI, MAIT and FET. The 2019 mark-to-market adjustment resulted from a decrease in the discount rate used to measure benefit obligations partially offset Other Expense — Total other expense increased $169 million, primarily due to an increase in the 2019 pension and OPEB mark-to-market adjustment, higher net pension and OPEB non-service costs, and transactions now accounted for as finance leases, as discussed above. This was partially offset by lower interest expense resulting from activities related to debt maturities and refinancing and higher capitalized financing costs. The 2019 mark-to-market adjustment resulted from a decrease in the discount rate used to measure benefit obligations, partially offset by higher than expected asset returns. Income Taxes Regulated Distribution’s effective tax rate was 20.1% and 25.4% for 2019 and 2018, respectively. The lower effective tax rate in 2019 was primarily due the amortization of net excess deferred income taxes resulting from Tax Act settlements and orders with certain regulatory commissions. Regulated Transmission — 2019 Compared with 2018 Regulated Transmission's operating results increased $50 million in 2019, as compared to 2018, primarily resulting from the impact of a higher rate base at ATSI and MAIT, partially offset by a lower rate base at TrAIL. expenses. Revenues — Total revenues increased $173 million in 2019, as compared to 2018, primarily due to higher rate base at ATSI and MAIT and the recovery of incremental expenses at the formula rate companies, partially offset by a lower rate base at TrAIL. by higher than expected asset returns. Income Taxes — Regulated Transmission’s effective tax rate was 20.2% and 23.5% for 2019 and 2018, respectively. The lower effective tax rate was primarily due to the amortization of net excess deferred income taxes resulting from FERC guidance related to the Tax Act. Corporate/Other — 2019 Compared with 2018 Financial results from Corporate/Other and reconciling adjustments resulted in a $2 million decrease in income from continuing operations for 2019 compared to 2018, primarily due to a $310 million increase in the 2019 pension and OPEB mark-to-market adjustment. This was partially offset by lower income taxes from the absence of a $126 million charge in the first quarter of 2018 associated with the remeasurement of state deferred taxes in West Virginia when the FES Debtors were removed from the unitary group following their bankruptcy filing on March 31, 2018, lower interest expense of $89 million due to the absence of make-whole payments, and lower other operating expenses of $42 million primarily due to lower incurred corporate support costs in continuing operations related to the FES Debtors and the absence of remeasuring the ARO of McElroy’s Run. Although the operations of the FES Debtors for the first quarter of 2018 (prior to deconsolidation on March 31, 2018) are reflected as discontinued operations, certain allocated corporate support costs to the FES Debtors continue to be reflected in continuing operations. Additionally, higher net miscellaneous income was primarily due to higher returns on certain equity method investments and lower non-operating For the years ended December 31, 2019 and 2018, FirstEnergy recorded income from discontinued operations, net of tax, of $8 million and $326 million, respectively. The change in discontinued operations, net of tax was primarily due to the absence of a $435 million gain on deconsolidation of FES and FENOC. 17 18 • Other operating expenses decreased $148 million primarily due to: Revenues by transmission asset owner are shown in the following table: Lower operating and maintenance expenses of $49 million, primarily associated with lower employee benefits Revenues by Transmission Asset Owner 2019 2018 Increase For the Years Ended December 31, ATSI TrAIL MAIT Other Total Revenues Operating Expenses — (In millions) $ 668 $ 246 154 285 758 251 227 290 90 5 73 5 1,526 $ 1,353 $ 173 $ $ Total operating expenses increased $65 million in 2019, as compared to 2018, primarily due to higher operating and maintenance expenses, as well as higher property taxes and depreciation due to a higher asset base. The majority of the increases are recovered through formula rates at ATSI and MAIT, resulting in no material impact on current period earnings. Depreciation expense increased $51 million, primarily due to a higher asset base and transactions now accounted for as finance leases, as discussed above. Other Expense — Net amortization expense increased $74 million, primarily due to decreased storm restoration cost deferrals, the absence of the reversal of a liability at the Ohio Companies for an Ohio Supreme Court ruling regarding the purchase of RECs, partially offset by higher deferrals of generation and transmission expenses, including the FERC settlement discussed above and the termination of the Morgantown Energy Associates PPA. Total other expense increased $67 million in 2019, as compared to 2018, primarily due to an increase in the 2019 pension and OPEB mark-to-market adjustment and higher interest expense associated with new debt issuances at ATSI, MAIT and FET. The 2019 mark-to-market adjustment resulted from a decrease in the discount rate used to measure benefit obligations partially offset by higher than expected asset returns. Income Taxes — Regulated Transmission’s effective tax rate was 20.2% and 23.5% for 2019 and 2018, respectively. The lower effective tax rate was primarily due to the amortization of net excess deferred income taxes resulting from FERC guidance related to the Tax Act. Corporate/Other — 2019 Compared with 2018 Financial results from Corporate/Other and reconciling adjustments resulted in a $2 million decrease in income from continuing operations for 2019 compared to 2018, primarily due to a $310 million increase in the 2019 pension and OPEB mark-to-market adjustment. This was partially offset by lower income taxes from the absence of a $126 million charge in the first quarter of 2018 associated with the remeasurement of state deferred taxes in West Virginia when the FES Debtors were removed from the unitary group following their bankruptcy filing on March 31, 2018, lower interest expense of $89 million due to the absence of make-whole payments, and lower other operating expenses of $42 million primarily due to lower incurred corporate support costs in continuing operations related to the FES Debtors and the absence of remeasuring the ARO of McElroy’s Run. Although the operations of the FES Debtors for the first quarter of 2018 (prior to deconsolidation on March 31, 2018) are reflected as discontinued operations, certain allocated corporate support costs to the FES Debtors continue to be reflected in continuing operations. Additionally, higher net miscellaneous income was primarily due to higher returns on certain equity method investments and lower non-operating expenses. For the years ended December 31, 2019 and 2018, FirstEnergy recorded income from discontinued operations, net of tax, of $8 million and $326 million, respectively. The change in discontinued operations, net of tax was primarily due to the absence of a $435 million gain on deconsolidation of FES and FENOC. • • • • • • Decreased storm restoration costs of $129 million, which were mostly deferred for future recovery, resulting in no material impact on current period earnings. and corporate support costs. Decreased expenses due to transactions now accounted for as finance leases of $21 million. As a result of the adoption of the new lease accounting standard, financing lease expenses that were recognized in other operating expenses are now recognized in depreciation and interest expense. The absence of $30 million in costs that occurred in 2018 associated with the voluntary enhanced retirement program. period earnings. Lower energy efficiency and other program costs of $27 million, partially offset by higher vegetation management spend of $13 million. These costs are deferred for future recovery, resulting in no material impact on current Higher network transmission expenses of $95 million reflecting increased transmission costs as well as the absence of the FERC settlement during 2018 that reallocated certain transmission costs across utilities in PJM and resulted in a refund to the Ohio Companies. Except for certain transmission costs and credits at the Ohio Companies recognized in 2018, the difference between current revenues and transmission costs incurred are deferred for future recovery or refund, resulting in no material impact on current period earnings. • • Other Expense — Income Taxes Revenues — Total other expense increased $169 million, primarily due to an increase in the 2019 pension and OPEB mark-to-market adjustment, higher net pension and OPEB non-service costs, and transactions now accounted for as finance leases, as discussed above. This was partially offset by lower interest expense resulting from activities related to debt maturities and refinancing and higher capitalized financing costs. The 2019 mark-to-market adjustment resulted from a decrease in the discount rate used to measure benefit obligations, partially offset by higher than expected asset returns. Regulated Distribution’s effective tax rate was 20.1% and 25.4% for 2019 and 2018, respectively. The lower effective tax rate in 2019 was primarily due the amortization of net excess deferred income taxes resulting from Tax Act settlements and orders with certain regulatory commissions. Regulated Transmission — 2019 Compared with 2018 Regulated Transmission's operating results increased $50 million in 2019, as compared to 2018, primarily resulting from the impact of a higher rate base at ATSI and MAIT, partially offset by a lower rate base at TrAIL. Total revenues increased $173 million in 2019, as compared to 2018, primarily due to higher rate base at ATSI and MAIT and the recovery of incremental expenses at the formula rate companies, partially offset by a lower rate base at TrAIL. 17 18 CAPITAL RESOURCES AND LIQUIDITY of financing plans could require FE or any of its consolidated subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity. In addition, FE and its consolidated subsidiaries expect to continually evaluate any planned financings, which FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest payments, dividend payments and contributions to its pension plan. may result in changes from time to time. As previously disclosed, on January 22, 2018, FirstEnergy announced a $2.5 billion equity issuance, which included $1.62 billion in mandatorily convertible preferred equity with an initial conversion price of $27.42 per share and $850 million of common equity issued at $28.22 per share. The equity investment strengthened the Company’s balance sheet, supported the company’s transition to a fully regulated utility company and positions FirstEnergy for sustained investment-grade credit metrics. The shares of preferred stock participated in the dividend paid on common stock on an as-converted basis and were non-voting except in certain limited circumstances. Because of this investment, FirstEnergy does not currently anticipate the need to issue additional equity through 2021 and expects to issue, subject to, among other things, market conditions, pricing terms and business operations, up to $600 million of equity annually in 2022 and 2023, including approximately $100 million in equity for its regular stock investment and employee benefit plans. As of August 1, 2019, an aggregate of 1,616,000 shares of preferred stock had been converted into 58,935,078 shares of common stock, and as a result, there were no shares of preferred stock outstanding as of December 31, 2019. In addition to this equity investment, FE and its distribution and transmission subsidiaries expect their existing sources of liquidity to remain sufficient to meet their respective anticipated obligations. In addition to internal sources to fund liquidity and capital requirements for 2020 and beyond, FE and its distribution and transmission subsidiaries expect to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt by FE and certain of its distribution and transmission subsidiaries to, among other things, fund capital expenditures and refinance short-term and maturing long-term debt, subject to market conditions and other factors. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. FirstEnergy expects no required contributions through 2021. As part of the Energizing the Future initiative, the Center for Advanced Technology was opened in Akron, Ohio in April 2019. The 88,000 square feet facility was designed to be a hands-on environment where engineers and technicians can develop and evaluate new technology and grid solutions and simulate a variety of real-world conditions. With an operating territory of 65,000 square miles, the scale and diversity of the ten Utilities that comprise the Regulated Distribution business uniquely position this business for growth through opportunities for additional investment. Over the past several years, Regulated Distribution has experienced rate base growth through investments that have improved reliability and added operating flexibility to the distribution infrastructure, which provide benefits to the customers and communities those Utilities serve. Based on its current capital plan, which includes over $10 billion in forecasted capital investments from 2018 through 2023, Regulated Distribution’s rate base compounded annual growth rate is expected to be approximately 4% from 2018 through 2023. Additionally, this business is exploring other opportunities for growth, including investments in electric system improvement and modernization projects to increase reliability and improve service to customers, as well as exploring opportunities in customer engagement that focus on the electrification of customers’ homes and businesses by providing a full range of products and services. Capital expenditures for 2018 and 2019 and forecasted expenditures for 2020, 2021, 2022, and 2023, by reportable segment are included below: Reportable Segment 2018 Actual 2019 Actual 2020 Forecast 2021 Forecast 2022 Forecast 2023 Forecast Regulated Distribution Regulated Transmission Corporate/Other Total $ $ 1,635 $ 1,698 $ 1,700 $ 1,700 $ 1,700 $ 1,700 1,165 183 1,189 105 1,200 90 1,200 - 1,450 1,200 - 1,450 1,200 - 1,450 110 110 110 2,983 $ 2,992 $ 2,990 $ 3,010 - 3,260 $ 3,010 - 3,260 $ 3,010 - 3,260 (In millions) FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion beyond those identified through 2023, which are expected to strengthen grid and cyber-security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility. In alignment with FirstEnergy’s strategy to invest in its Regulated Transmission and Regulated Distribution segments as a fully regulated company, FirstEnergy is also focused on improving the balance sheet over time consistent with its business profile and maintaining investment grade ratings at its regulated businesses and FE. Specifically, at the regulated businesses, regulatory authority has been obtained for various regulated distribution and transmission subsidiaries to issue and/or refinance debt. Any financing plans by FE or any of its consolidated subsidiaries, including the issuance of equity and debt, and the refinancing of short-term and maturing long-term debt are subject to market conditions and other factors. No assurance can be given that any such issuances, financing or refinancing, as the case may be, will be completed as anticipated or at all. Any delay in the completion On March 9, 2018, FES borrowed $500 million from FE under the secured credit facility, dated as of December 6, 2016, among FES, as borrower, FG and NG as guarantors, and FE, as lender, which fully utilized the committed line of credit available under the secured credit facility. Following the FES Bankruptcy deconsolidation of FES, FE fully reserved for the $500 million associated with the borrowings under the secured credit facility. Under the terms of the FES Bankruptcy settlement agreement discussed below, FE will release any and all claims against the FES Debtors with respect to the $500 million borrowed under the secured credit facility. On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, and includes the following terms, among others: FE will pay certain pre-petition FES Debtors employee-related obligations, which include unfunded pension obligations and other employee benefits. FE will waive all pre-petition claims (other than those claims under the Tax Allocation Agreement for the 2018 tax year) and certain post-petition claims, against the FES Debtors related to the FES Debtors and their businesses, including the full borrowings by FES under the $500 million secured credit facility, the $200 million credit agreement being used to support surety bonds, the BNSF Railway Company/CSX Transportation, Inc. rail settlement guarantee, and the FES Debtors' unfunded pension The nonconsensual release of all claims against FirstEnergy by the FES Debtors' creditors, which was subsequently waived obligations. pursuant to the Waiver Agreement, discussed below. A $225 million cash payment from FirstEnergy. An additional $628 million cash payment from FirstEnergy, which may be decreased by the amount, if any, of cash paid by FirstEnergy to the FES Debtors under the Intercompany Income Tax Allocation Agreement for the tax benefits related to the sale or deactivation of certain plants. On November 21, 2019, FirstEnergy, the FES Debtors, the UCC, and the FES Key Creditors Group entered into an amendment to the settlement agreement, which among other things, changed the $628 million note issuance, into a cash payment to be made upon emergence. The amendment was approved by the Bankruptcy Court on December 16, 2019. • Transfer of the Pleasants Power Station and related assets, including the economic interests therein as of January 1, 2019, and a requirement that FE continues to provide access to the McElroy's Run CCR Impoundment Facility, which is not being transferred. In addition, FE provides guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. On January 21, 2020, AE Supply, FG and a newly formed subsidiary of FG, entered into a letter agreement authorizing the transfer of Pleasants Power Station prior to the FES Debtors’ emergence from bankruptcy. The letter agreement was approved by the Bankruptcy Court on January 28, 2020. The transfer of the Pleasants Power Station was completed on January 30, 2020. FirstEnergy agrees to waive all pre-petition claims related to shared services and credit for nine months of the FES Debtors' shared service costs beginning as of April 1, 2018 through December 31, 2018, in an amount not to exceed $112.5 million, and FirstEnergy agrees to extend the availability of shared services until no later than June 30, 2020. Subject to a cap, FirstEnergy has agreed to fund a pension enhancement through its pension plan for voluntary enhanced retirement packages offered to certain FES employees, as well as offer certain other employee benefits (approximately $14 million recognized for the year ending December 31, 2019). FirstEnergy agrees to perform under the Intercompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million for 2018. Based on the 2018 federal tax return filed in September 2019, FirstEnergy owes the FES debtors approximately $31 million associated with 2018, which will be paid upon emergence. Based on current estimates for the 2019 tax return to be filed in 2020, FirstEnergy estimates that it owes the FES Debtors approximately $83 million of which FirstEnergy has paid $14 million as of December 31, 2019. The estimated amounts owed to the FES Debtors for 2018 and 2019 tax returns excludes amounts allocated for non-deductible interest as discussed in Note 3, "Discontinued Operations." FirstEnergy is currently reconciling tax matters under the Intercompany Tax Allocation Agreement with the FES Debtors. • • • • • • • • The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements. In connection with the FES Bankruptcy settlement agreement, FirstEnergy entered into a separation agreement with the FES Debtors to implement the separation of the FES Debtors and their businesses from FirstEnergy. A business separation committee was established between FirstEnergy and the FES Debtors to review and determine issues that arise in the context of the separation of the FES Debtors’ businesses from those of FirstEnergy. 19 20 CAPITAL RESOURCES AND LIQUIDITY FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest payments, dividend payments and contributions to its pension plan. As previously disclosed, on January 22, 2018, FirstEnergy announced a $2.5 billion equity issuance, which included $1.62 billion in mandatorily convertible preferred equity with an initial conversion price of $27.42 per share and $850 million of common equity issued at $28.22 per share. The equity investment strengthened the Company’s balance sheet, supported the company’s transition to a fully regulated utility company and positions FirstEnergy for sustained investment-grade credit metrics. The shares of preferred stock participated in the dividend paid on common stock on an as-converted basis and were non-voting except in certain limited circumstances. Because of this investment, FirstEnergy does not currently anticipate the need to issue additional equity through 2021 and expects to issue, subject to, among other things, market conditions, pricing terms and business operations, up to $600 million of equity annually in 2022 and 2023, including approximately $100 million in equity for its regular stock investment and employee benefit plans. As of August 1, 2019, an aggregate of 1,616,000 shares of preferred stock had been converted into 58,935,078 shares of common stock, and as a result, there were no shares of preferred stock outstanding as of December 31, 2019. In addition to this equity investment, FE and its distribution and transmission subsidiaries expect their existing sources of liquidity to remain sufficient to meet their respective anticipated obligations. In addition to internal sources to fund liquidity and capital requirements for 2020 and beyond, FE and its distribution and transmission subsidiaries expect to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt by FE and certain of its distribution and transmission subsidiaries to, among other things, fund capital expenditures and refinance short-term and maturing long-term debt, subject to market conditions and other factors. no required contributions through 2021. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. FirstEnergy expects As part of the Energizing the Future initiative, the Center for Advanced Technology was opened in Akron, Ohio in April 2019. The 88,000 square feet facility was designed to be a hands-on environment where engineers and technicians can develop and evaluate new technology and grid solutions and simulate a variety of real-world conditions. With an operating territory of 65,000 square miles, the scale and diversity of the ten Utilities that comprise the Regulated Distribution business uniquely position this business for growth through opportunities for additional investment. Over the past several years, Regulated Distribution has experienced rate base growth through investments that have improved reliability and added operating flexibility to the distribution infrastructure, which provide benefits to the customers and communities those Utilities serve. Based on its current capital plan, which includes over $10 billion in forecasted capital investments from 2018 through 2023, Regulated Distribution’s rate base compounded annual growth rate is expected to be approximately 4% from 2018 through 2023. Additionally, this business is exploring other opportunities for growth, including investments in electric system improvement and modernization projects to increase reliability and improve service to customers, as well as exploring opportunities in customer engagement that focus on the electrification of customers’ homes and businesses by providing a full range of products and services. Capital expenditures for 2018 and 2019 and forecasted expenditures for 2020, 2021, 2022, and 2023, by reportable segment are included below: Reportable Segment 2018 Actual 2019 Actual 2020 Forecast 2021 Forecast 2022 Forecast 2023 Forecast Regulated Distribution 1,635 $ 1,698 $ 1,700 $ 1,700 $ 1,700 $ 1,700 Regulated Transmission Corporate/Other Total 1,165 183 1,189 105 1,200 90 1,200 - 1,450 1,200 - 1,450 1,200 - 1,450 110 110 110 2,983 $ 2,992 $ 2,990 $ 3,010 - 3,260 $ 3,010 - 3,260 $ 3,010 - 3,260 $ $ (In millions) FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion beyond those identified through 2023, which are expected to strengthen grid and cyber-security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility. In alignment with FirstEnergy’s strategy to invest in its Regulated Transmission and Regulated Distribution segments as a fully regulated company, FirstEnergy is also focused on improving the balance sheet over time consistent with its business profile and maintaining investment grade ratings at its regulated businesses and FE. Specifically, at the regulated businesses, regulatory authority has been obtained for various regulated distribution and transmission subsidiaries to issue and/or refinance debt. Any financing plans by FE or any of its consolidated subsidiaries, including the issuance of equity and debt, and the refinancing of short-term and maturing long-term debt are subject to market conditions and other factors. No assurance can be given that any such issuances, financing or refinancing, as the case may be, will be completed as anticipated or at all. Any delay in the completion of financing plans could require FE or any of its consolidated subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity. In addition, FE and its consolidated subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to time. On March 9, 2018, FES borrowed $500 million from FE under the secured credit facility, dated as of December 6, 2016, among FES, as borrower, FG and NG as guarantors, and FE, as lender, which fully utilized the committed line of credit available under the secured credit facility. Following the FES Bankruptcy deconsolidation of FES, FE fully reserved for the $500 million associated with the borrowings under the secured credit facility. Under the terms of the FES Bankruptcy settlement agreement discussed below, FE will release any and all claims against the FES Debtors with respect to the $500 million borrowed under the secured credit facility. On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, and includes the following terms, among others: • • • • • • • • • FE will pay certain pre-petition FES Debtors employee-related obligations, which include unfunded pension obligations and other employee benefits. FE will waive all pre-petition claims (other than those claims under the Tax Allocation Agreement for the 2018 tax year) and certain post-petition claims, against the FES Debtors related to the FES Debtors and their businesses, including the full borrowings by FES under the $500 million secured credit facility, the $200 million credit agreement being used to support surety bonds, the BNSF Railway Company/CSX Transportation, Inc. rail settlement guarantee, and the FES Debtors' unfunded pension obligations. The nonconsensual release of all claims against FirstEnergy by the FES Debtors' creditors, which was subsequently waived pursuant to the Waiver Agreement, discussed below. A $225 million cash payment from FirstEnergy. An additional $628 million cash payment from FirstEnergy, which may be decreased by the amount, if any, of cash paid by FirstEnergy to the FES Debtors under the Intercompany Income Tax Allocation Agreement for the tax benefits related to the sale or deactivation of certain plants. On November 21, 2019, FirstEnergy, the FES Debtors, the UCC, and the FES Key Creditors Group entered into an amendment to the settlement agreement, which among other things, changed the $628 million note issuance, into a cash payment to be made upon emergence. The amendment was approved by the Bankruptcy Court on December 16, 2019. Transfer of the Pleasants Power Station and related assets, including the economic interests therein as of January 1, 2019, and a requirement that FE continues to provide access to the McElroy's Run CCR Impoundment Facility, which is not being transferred. In addition, FE provides guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. On January 21, 2020, AE Supply, FG and a newly formed subsidiary of FG, entered into a letter agreement authorizing the transfer of Pleasants Power Station prior to the FES Debtors’ emergence from bankruptcy. The letter agreement was approved by the Bankruptcy Court on January 28, 2020. The transfer of the Pleasants Power Station was completed on January 30, 2020. FirstEnergy agrees to waive all pre-petition claims related to shared services and credit for nine months of the FES Debtors' shared service costs beginning as of April 1, 2018 through December 31, 2018, in an amount not to exceed $112.5 million, and FirstEnergy agrees to extend the availability of shared services until no later than June 30, 2020. Subject to a cap, FirstEnergy has agreed to fund a pension enhancement through its pension plan for voluntary enhanced retirement packages offered to certain FES employees, as well as offer certain other employee benefits (approximately $14 million recognized for the year ending December 31, 2019). FirstEnergy agrees to perform under the Intercompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million for 2018. Based on the 2018 federal tax return filed in September 2019, FirstEnergy owes the FES debtors approximately $31 million associated with 2018, which will be paid upon emergence. Based on current estimates for the 2019 tax return to be filed in 2020, FirstEnergy estimates that it owes the FES Debtors approximately $83 million of which FirstEnergy has paid $14 million as of December 31, 2019. The estimated amounts owed to the FES Debtors for 2018 and 2019 tax returns excludes amounts allocated for non-deductible interest as discussed in Note 3, "Discontinued Operations." FirstEnergy is currently reconciling tax matters under the Intercompany Tax Allocation Agreement with the FES Debtors. The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements. In connection with the FES Bankruptcy settlement agreement, FirstEnergy entered into a separation agreement with the FES Debtors to implement the separation of the FES Debtors and their businesses from FirstEnergy. A business separation committee was established between FirstEnergy and the FES Debtors to review and determine issues that arise in the context of the separation of the FES Debtors’ businesses from those of FirstEnergy. 19 20 As of December 31, 2019, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was due in large part to short-term borrowings of $1.0 billion, accounts payable of $918 million, current payable long-term debt of $380 million, and other current liabilities of $1.4 billion primarily attributable to customer deposits and anticipated payments under the FES Bankruptcy settlement. Currently payable long-term debt as of December 31, 2019, consistent of the following: The following table summarizes the borrowing sub-limits for each borrower under the facilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of January 31, 2020: Currently Payable Long-Term Debt Unsecured notes Secured notes Sinking fund requirements Other notes December 31, 2019 (In millions) $ $ 250 50 64 16 380 FirstEnergy believes its cash from operations and available liquidity will be sufficient to meet its working capital needs. Short-Term Borrowings / Revolving Credit Facilities FE and the Utilities and FET and certain of its subsidiaries participate in two separate five-year syndicated revolving credit facilities providing for aggregate commitments of $3.5 billion, which are available until December 6, 2022. Under the FE credit facility, an aggregate amount of $2.5 billion is available to be borrowed, repaid and reborrowed, subject to separate borrowing sub-limits for each borrower including FE and its regulated distribution subsidiaries. Under the FET credit facility, an aggregate amount of $1.0 billion is available to be borrowed, repaid and reborrowed under a syndicated credit facility, subject to separate borrowing sub-limits for each borrower including FE's transmission subsidiaries. Borrowings under the credit facilities may be used for working capital and other general corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries. Generally, borrowings under each of the credit facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the credit facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the credit facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FirstEnergy had $1.0 billion and $1.25 billion of short-term borrowings as of December 31, 2019 and 2018, respectively. FirstEnergy’s available liquidity from external sources as of January 31, 2020, was as follows: Borrower(s) Type Maturity Commitment Available Liquidity FirstEnergy(1) FET(2) Revolving December 2022 $ 2,500 $ Revolving December 2022 1,000 (In millions) Subtotal $ 3,500 $ Cash and cash equivalents — Total $ 3,500 $ 2,496 1,000 3,496 465 3,961 (1) (2) FE and the Utilities. Available liquidity includes impact of $4 million of LOCs issued under various terms. Includes FET and the Transmission Companies. Borrower FirstEnergy Revolving Credit Facility Sub-Limit FET Revolving Credit Facility Sub-Limit Regulatory and Other Short-Term Debt Limitations $ 2,500 $ $ (In millions) 1,000 — 500 500 300 500 500 300 200 500 150 — 100 — — — — — — — — — — — — 500 — 400 400 — (1) — (1) 500 (2) 500 (2) 300 (2) 500 (2) 500 (2) 300 (2) 200 (2) 500 (2) 150 (2) 500 (2) 100 (2) 400 (2) 400 (2) JCP&L FE FET OE CEI TE ME PN WP MP PE ATSI Penn TrAIL MAIT (1) No limitations. (2) Includes amounts which may be borrowed under the regulated companies' money pool. $250 million of the FE Facility and $100 million of the FET Facility, subject to each borrower's sub-limit, is available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the Facilities and against the applicable borrower’s borrowing sub-limit. The Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the Facilities is related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross- default for other indebtedness in excess of $100 million. As of December 31, 2019, the borrowers were in compliance with the applicable debt-to-total-capitalization ratio covenants in each case as defined under the respective Facilities. The minimum interest charge coverage ratio no longer applies following FE's upgrade to an investment grade credit rating. Term Loans On October 19, 2018, FE entered into two separate syndicated term loan credit agreements, the first being a $1.25 billion 364-day facility with The Bank of Nova Scotia, as administrative agent, and the lenders identified therein, and the second being a $500 million two-year facility with JPMorgan Chase Bank, N.A., as administrative agent, and the lenders identified therein, respectively, the proceeds of each were used to reduce short-term debt. The term loans contain covenants and other terms and conditions substantially similar to those of the FE revolving credit facility described above, including a consolidated debt-to-total-capitalization ratio. Effective September 11, 2019, the two credit agreements noted above were amended to change the amounts available under the existing facilities from $1.25 billion and $500 million to $1 billion and $750 million, respectively, and extend the maturity dates until September 9, 2020, and September 11, 2021, respectively. The borrowing of $1.75 billion under the term loans, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. Outstanding alternate base rate advances will bear interest at a fluctuating interest rate per annum equal to the sum of an applicable margin for alternate base rate advances determined by reference to FE’s reference ratings plus the highest of (i) the administrative agent’s publicly-announced “prime rate,” (ii) the sum of 1/2 of 1% per annum plus the Federal Funds Rate in effect from time to time and (iii) the rate of interest per annum appearing on a nationally-recognized service such as the Dow Jones Market Service (Telerate) equal to one-month LIBOR on each day plus 1%. Outstanding Eurodollar rate advances will bear interest at LIBOR for interest periods of one week or 21 22 As of December 31, 2019, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was due in large part to short-term borrowings of $1.0 billion, accounts payable of $918 million, current payable long-term debt of $380 million, and other current liabilities of $1.4 billion primarily attributable to customer deposits and anticipated payments under the FES Bankruptcy settlement. Currently payable long-term debt as of December 31, 2019, consistent of the following: The following table summarizes the borrowing sub-limits for each borrower under the facilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of January 31, 2020: Currently Payable Long-Term Debt Unsecured notes Secured notes Sinking fund requirements Other notes December 31, 2019 (In millions) $ $ 250 50 64 16 380 FirstEnergy believes its cash from operations and available liquidity will be sufficient to meet its working capital needs. Short-Term Borrowings / Revolving Credit Facilities FE and the Utilities and FET and certain of its subsidiaries participate in two separate five-year syndicated revolving credit facilities providing for aggregate commitments of $3.5 billion, which are available until December 6, 2022. Under the FE credit facility, an aggregate amount of $2.5 billion is available to be borrowed, repaid and reborrowed, subject to separate borrowing sub-limits for each borrower including FE and its regulated distribution subsidiaries. Under the FET credit facility, an aggregate amount of $1.0 billion is available to be borrowed, repaid and reborrowed under a syndicated credit facility, subject to separate borrowing sub-limits for each borrower including FE's transmission subsidiaries. Borrowings under the credit facilities may be used for working capital and other general corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries. Generally, borrowings under each of the credit facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the credit facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the credit facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FirstEnergy had $1.0 billion and $1.25 billion of short-term borrowings as of December 31, 2019 and 2018, respectively. FirstEnergy’s available liquidity from external sources as of January 31, 2020, was as follows: Borrower(s) Type Maturity Commitment FirstEnergy(1) FET(2) Revolving December 2022 $ 2,500 $ Revolving December 2022 1,000 Available Liquidity (In millions) Subtotal $ 3,500 $ Cash and cash equivalents — Total $ 3,500 $ 2,496 1,000 3,496 465 3,961 Borrower FirstEnergy Revolving Credit Facility Sub-Limit FET Revolving Credit Facility Sub-Limit Regulatory and Other Short-Term Debt Limitations (In millions) FE FET OE CEI TE JCP&L ME PN WP MP PE ATSI Penn TrAIL MAIT $ 2,500 $ — $ — 500 500 300 500 500 300 200 500 150 — 100 — — 1,000 — — — — — — — — — 500 — 400 400 — (1) — (1) 500 (2) 500 (2) 300 (2) 500 (2) 500 (2) 300 (2) 200 (2) 500 (2) 150 (2) 500 (2) 100 (2) 400 (2) 400 (2) (1) No limitations. (2) Includes amounts which may be borrowed under the regulated companies' money pool. $250 million of the FE Facility and $100 million of the FET Facility, subject to each borrower's sub-limit, is available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the Facilities and against the applicable borrower’s borrowing sub-limit. The Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the Facilities is related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross- default for other indebtedness in excess of $100 million. As of December 31, 2019, the borrowers were in compliance with the applicable debt-to-total-capitalization ratio covenants in each case as defined under the respective Facilities. The minimum interest charge coverage ratio no longer applies following FE's upgrade to an investment grade credit rating. FE and the Utilities. Available liquidity includes impact of $4 million of LOCs issued under various terms. Term Loans (1) (2) Includes FET and the Transmission Companies. On October 19, 2018, FE entered into two separate syndicated term loan credit agreements, the first being a $1.25 billion 364-day facility with The Bank of Nova Scotia, as administrative agent, and the lenders identified therein, and the second being a $500 million two-year facility with JPMorgan Chase Bank, N.A., as administrative agent, and the lenders identified therein, respectively, the proceeds of each were used to reduce short-term debt. The term loans contain covenants and other terms and conditions substantially similar to those of the FE revolving credit facility described above, including a consolidated debt-to-total-capitalization ratio. Effective September 11, 2019, the two credit agreements noted above were amended to change the amounts available under the existing facilities from $1.25 billion and $500 million to $1 billion and $750 million, respectively, and extend the maturity dates until September 9, 2020, and September 11, 2021, respectively. The borrowing of $1.75 billion under the term loans, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. Outstanding alternate base rate advances will bear interest at a fluctuating interest rate per annum equal to the sum of an applicable margin for alternate base rate advances determined by reference to FE’s reference ratings plus the highest of (i) the administrative agent’s publicly-announced “prime rate,” (ii) the sum of 1/2 of 1% per annum plus the Federal Funds Rate in effect from time to time and (iii) the rate of interest per annum appearing on a nationally-recognized service such as the Dow Jones Market Service (Telerate) equal to one-month LIBOR on each day plus 1%. Outstanding Eurodollar rate advances will bear interest at LIBOR for interest periods of one week or 21 22 one, two, three or six months plus an applicable margin determined by reference to FE’s reference ratings. Changes in FE’s reference ratings would lower or raise its applicable margin depending on whether ratings improved or were lowered, respectively. On March 27, 2019, Moody’s upgraded JCP&L’s Senior Unsecured and Issuer ratings to Baa1 from Baa2, and maintained the positive outlook pending the outcome of the Reliability Plus infrastructure investment program. A portion of FirstEnergy’s indebtedness bears interest at fluctuating interest rates, primarily based on LIBOR. LIBOR tends to fluctuate based on general interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on LIBOR and other variable interest rates. On July 27, 2017, the Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index, calculated based on repurchase agreements backed by treasury securities. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United Kingdom, the United States or elsewhere. To the extent these interest rates increase, interest expense will increase. If sources of capital for FirstEnergy are reduced, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could have an adverse effect on our results of operations, cash flows, financial condition and liquidity. FirstEnergy Money Pools FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2019 was 2.27% per annum for the regulated companies’ money pool and 2.74% per annum for the unregulated companies’ money pool. Long-Term Debt Capacity On April 17, 2019, Fitch upgraded JCP&L’s Issuer rating to BBB from BBB- and its Senior Unsecured rating to BBB+ from BBB with a positive outlook. Also, on April 17, 2019, Fitch upgraded MP, AGC, and PE’s Issuer ratings to BBB from BBB- and the Senior Secured ratings of MP and PE to A- from BBB+ with a stable outlook for MP, AGC and PE and affirmed FE’s and all other FE subsidiaries ratings and positive outlooks. On July 23, 2019, Moody’s upgraded the Senior Unsecured and Issuer ratings of OE and Penn to A3 from Baa1, TE to Baa1 from Baa3, and CEI to Baa2 from Baa3. The secured ratings for OE and Penn were changed to A1 from A2, TE to A2 from Baa1, and CEI to A3 from Baa1. The rating outlook for OE remains positive, Penn was revised to positive, and TE and CEI were revised to stable. On November 8, 2019, Fitch upgraded the Corporate Credit Ratings and Senior Unsecured Ratings of FE and FET to BBB from BBB-. The Corporate Credit Ratings of ATSI, CEI, JCP&L, ME, MAIT, OE, PN, Penn, TE, TrAIL, and WP were upgraded to BBB+ from BBB, and the Senior Unsecured Ratings of ATSI, CEI, JCP&L, ME, MAIT, OE, PN, and TrAIL were upgraded to A- from BBB+. Additionally, the Senior Secured Ratings of CEI, OE, Penn, TE, and WP were upgraded to A from A-. At the same time, the Outlook for each of the companies upgraded was changed to Stable from Positive. Debt capacity is subject to the consolidated debt-to-total-capitalization limits in the credit facilities previously discussed. As of December 31, 2019, FE and its subsidiaries could issue additional debt of approximately $7.8 billion, or incur a $4.2 billion reduction to equity, and remain within the limitations of the financial covenants required by the FE Facility. As of December 31, 2019, FirstEnergy had $627 million of cash and cash equivalents and approximately $52 million of restricted cash compared to $367 million of cash and cash equivalents and approximately $62 million of restricted cash as of December 31, Changes in Cash Position 2018, on the Consolidated Balance Sheets. Cash Flows From Operating Activities FE's and its subsidiaries' access to capital markets and costs of financing are influenced by the credit ratings of their securities. The following table displays FE’s and its subsidiaries’ credit ratings as of February 6, 2020: Corporate Credit Rating Senior Secured Senior Unsecured Issuer S&P Moody’s Fitch S&P Moody’s Fitch S&P Moody’s Fitch Outlook (1) S&P Moody’s Fitch FirstEnergy's most significant sources of cash are derived from electric service provided by its distribution and transmission operating subsidiaries. The most significant use of cash from operating activities is buying electricity to serve non-shopping customers and paying fuel suppliers, employees, tax authorities, lenders and others for a wide range of materials and services. Net cash provided from operating activities was $2,467 million during 2019, $1,410 million during 2018 and $3,808 million during FE AGC ATSI CEI FET JCP&L ME MAIT MP OE PN Penn PE TE TrAIL WP BBB BBB- BBB BBB BBB BBB BBB BBB BBB BBB BBB BBB BBB BBB BBB BBB Baa3 Baa2 A3 Baa2 Baa2 Baa1 A3 A3 Baa2 A3 BBB BBB — — BBB+ — BBB+ BBB A- — BBB+ — BBB+ — BBB+ — BBB BBB+ A- A- Baa1 BBB+ — A3 Baa2 Baa1 A3 A3 BBB+ — BBB BBB+ — A- BBB+ — BBB+ — (1) S = Stable and P = Positive — — — A3 — — — — A3 A1 — A1 — A2 — — — BBB- Baa3 BBB — — A — BBB BBB — BBB- — — — A- A — A A- A — A BBB BBB BBB BBB BBB BBB — — — BBB — — A3 Baa2 Baa2 Baa1 A3 A3 Baa2 A3 Baa1 — — — A3 — — A- A- BBB A- A- A- — A- A- — — — A- — S S S S S S S S S S S S S S S S S S S S S P S S S P S P S S S S S S S S S S S S S S S S S S S S On March 21, 2019, Moody’s upgraded the Senior Unsecured and Issuer ratings of ATSI and MAIT to A3 from Baa1. At the same time, Moody's affirmed the Senior Unsecured and Issuer ratings of their intermediate holding company, FET, at Baa2 as well as TrAIL at A3. The rating outlooks of these companies are stable. 23 24 2017. 2019 compared with 2018 Cash flows from operations increased $1,057 million in 2019 as compared with 2018. The year-over-year change in cash from operations increased due to the following: a $750 million decrease in cash contributions to the qualified pension plan; higher transmission revenue reflecting a higher base rate and recovery of incremental operating expenses at ATSI and MAIT; • • • • • • decrease to working capital primarily due to higher receipts from customers; lower storm costs; partially offset by lower revenues due to tax savings being provided to customers in relation to the Tax Act; the absence of FES' cash from operations from the first quarter of 2018. one, two, three or six months plus an applicable margin determined by reference to FE’s reference ratings. Changes in FE’s reference ratings would lower or raise its applicable margin depending on whether ratings improved or were lowered, respectively. On March 27, 2019, Moody’s upgraded JCP&L’s Senior Unsecured and Issuer ratings to Baa1 from Baa2, and maintained the positive outlook pending the outcome of the Reliability Plus infrastructure investment program. A portion of FirstEnergy’s indebtedness bears interest at fluctuating interest rates, primarily based on LIBOR. LIBOR tends to fluctuate based on general interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on LIBOR and other variable interest rates. On July 27, 2017, the Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index, calculated based on repurchase agreements backed by treasury securities. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United Kingdom, the United States or elsewhere. To the extent these interest rates increase, interest expense will increase. If sources of capital for FirstEnergy are reduced, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could have an adverse effect on our results of operations, cash flows, financial condition and liquidity. FirstEnergy Money Pools FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2019 was 2.27% per annum for the regulated companies’ money pool and 2.74% per annum for the unregulated companies’ money pool. Long-Term Debt Capacity On April 17, 2019, Fitch upgraded JCP&L’s Issuer rating to BBB from BBB- and its Senior Unsecured rating to BBB+ from BBB with a positive outlook. Also, on April 17, 2019, Fitch upgraded MP, AGC, and PE’s Issuer ratings to BBB from BBB- and the Senior Secured ratings of MP and PE to A- from BBB+ with a stable outlook for MP, AGC and PE and affirmed FE’s and all other FE subsidiaries ratings and positive outlooks. On July 23, 2019, Moody’s upgraded the Senior Unsecured and Issuer ratings of OE and Penn to A3 from Baa1, TE to Baa1 from Baa3, and CEI to Baa2 from Baa3. The secured ratings for OE and Penn were changed to A1 from A2, TE to A2 from Baa1, and CEI to A3 from Baa1. The rating outlook for OE remains positive, Penn was revised to positive, and TE and CEI were revised to stable. On November 8, 2019, Fitch upgraded the Corporate Credit Ratings and Senior Unsecured Ratings of FE and FET to BBB from BBB-. The Corporate Credit Ratings of ATSI, CEI, JCP&L, ME, MAIT, OE, PN, Penn, TE, TrAIL, and WP were upgraded to BBB+ from BBB, and the Senior Unsecured Ratings of ATSI, CEI, JCP&L, ME, MAIT, OE, PN, and TrAIL were upgraded to A- from BBB+. Additionally, the Senior Secured Ratings of CEI, OE, Penn, TE, and WP were upgraded to A from A-. At the same time, the Outlook for each of the companies upgraded was changed to Stable from Positive. Debt capacity is subject to the consolidated debt-to-total-capitalization limits in the credit facilities previously discussed. As of December 31, 2019, FE and its subsidiaries could issue additional debt of approximately $7.8 billion, or incur a $4.2 billion reduction to equity, and remain within the limitations of the financial covenants required by the FE Facility. Changes in Cash Position As of December 31, 2019, FirstEnergy had $627 million of cash and cash equivalents and approximately $52 million of restricted cash compared to $367 million of cash and cash equivalents and approximately $62 million of restricted cash as of December 31, 2018, on the Consolidated Balance Sheets. Cash Flows From Operating Activities FE's and its subsidiaries' access to capital markets and costs of financing are influenced by the credit ratings of their securities. The following table displays FE’s and its subsidiaries’ credit ratings as of February 6, 2020: Corporate Credit Rating Senior Secured Senior Unsecured Outlook (1) Issuer S&P Moody’s Fitch S&P Moody’s Fitch S&P Moody’s Fitch S&P Moody’s Fitch — BBB- Baa3 BBB FirstEnergy's most significant sources of cash are derived from electric service provided by its distribution and transmission operating subsidiaries. The most significant use of cash from operating activities is buying electricity to serve non-shopping customers and paying fuel suppliers, employees, tax authorities, lenders and others for a wide range of materials and services. Net cash provided from operating activities was $2,467 million during 2019, $1,410 million during 2018 and $3,808 million during 2017. 2019 compared with 2018 Cash flows from operations increased $1,057 million in 2019 as compared with 2018. The year-over-year change in cash from operations increased due to the following: • • • • • • a $750 million decrease in cash contributions to the qualified pension plan; higher transmission revenue reflecting a higher base rate and recovery of incremental operating expenses at ATSI and MAIT; decrease to working capital primarily due to higher receipts from customers; lower storm costs; partially offset by lower revenues due to tax savings being provided to customers in relation to the Tax Act; the absence of FES' cash from operations from the first quarter of 2018. 24 FE AGC ATSI CEI FET JCP&L ME MAIT MP OE PN PE TE Penn TrAIL WP BBB BBB- BBB BBB BBB BBB BBB BBB BBB BBB BBB BBB BBB BBB BBB BBB Baa3 Baa2 A3 Baa2 Baa2 Baa1 A3 A3 Baa2 A3 A3 Baa2 Baa1 A3 A3 BBB+ — BBB+ — BBB+ — BBB+ — BBB BBB BBB+ BBB BBB BBB+ BBB BBB+ — — A- — A- A- — A- BBB+ — BBB+ — Baa1 BBB+ — BBB+ — (1) S = Stable and P = Positive — — — A3 — — — — A3 A1 — A1 — A2 — — — BBB- BBB — BBB BBB BBB BBB BBB BBB BBB BBB — — — — BBB — A3 Baa2 Baa2 Baa1 A3 A3 Baa2 A3 Baa1 — — — A3 — — A- A- A- A- A- — A- A- — — — A- — S S S S S S S S S S S S S S S S S S S S S P S S S P S P S S S S S S S S S S S S S S S S S S S S On March 21, 2019, Moody’s upgraded the Senior Unsecured and Issuer ratings of ATSI and MAIT to A3 from Baa1. At the same time, Moody's affirmed the Senior Unsecured and Issuer ratings of their intermediate holding company, FET, at Baa2 as well as TrAIL at A3. The rating outlooks of these companies are stable. — — A — — — A- A — A A- A — A 23 FirstEnergy's Consolidated Statements of Cash Flows combine cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of operating cash flow items from discontinued operations for the years ended December 31, 2019, 2018 and 2017: (In millions) CASH FLOWS FROM OPERATING ACTIVITIES: Income (loss) from discontinued operations Gain on disposal, net of tax For the Years Ended December 31, 2018 2019 2017 $ 8 $ 326 $ (1,435) (59) (435) — Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs Deferred income taxes and investment tax credits, net Unrealized (gain) loss on derivative transactions — 47 — 110 61 (10) 333 (842) 81 Cash Flows From Financing Activities Cash provided from financing activities was $656 million and $1,394 million in 2019 and 2018, respectively, compared to cash used for financing activities of $702 million in 2017. The following table summarizes new equity and debt financing, redemptions, repayments, make-whole premiums paid on debt redemptions short-term borrowings and dividends: Securities Issued or Redeemed / Repaid 2019 2018 2017 For the Years Ended December 31, (In millions) $ — $ 1,616 $ — 1,850 — 450 — 850 850 74 50 500 — — 3,800 — 625 250 $ 2,300 $ 3,940 $ 4,675 $ (725) $ (555) $ (1,330) New Issues Preferred stock issuance Common stock issuance Unsecured notes PCRBs FMBs Term loan Redemptions / Repayments Unsecured notes PCRBs FMBs Term loan Senior secured notes Tender premiums paid on debt redemptions Short-term borrowings (repayments), net Preferred stock dividend payments Common stock dividend payments $ $ $ $ $ — (1) — (63) (216) (325) (1,450) (62) (158) (725) — (78) (789) $ (2,608) $ (2,291) — $ (89) $ — — $ 950 $ (2,375) (6) $ (61) $ — (814) $ (711) $ (639) 2019 compared with 2018 On February 8, 2019, JCP&L issued $400 million of 4.30% senior notes due 2026. Proceeds from the issuance of the senior notes were primarily used to refinance existing indebtedness, including amounts outstanding under the FE regulated utility money pool incurred in connection with the repayment at maturity of JCP&L’s $300 million of 7.35% senior notes due 2019 and the funding of storm recovery and restoration costs and expenses, to fund capital expenditures and working capital requirements and for other general corporate purposes. On March 28, 2019, FET issued $500 million of 4.55% senior notes due 2049. Proceeds from the issuance of the senior notes were used primarily to support FET’s capital structure, to repay short-term borrowings outstanding under the FE unregulated money pool, to finance capital improvements, and for other general corporate purposes, including funding working capital needs and day-to-day operations. purposes. On April 15, 2019, ATSI issued $100 million of 4.38% senior notes due 2031. Proceeds from the issuance of the senior notes were used primarily to repay short-term borrowings, to fund capital expenditures and working capital needs, and for other general corporate On May 21, 2019, WP issued $100 million of 4.22% FMBs due 2059. Proceeds from the issuance of the FMBs were or are, as the case may be, used to refinance existing indebtedness, to fund capital expenditures, and for other general corporate purposes. On June 3, 2019, PN issued $300 million of 3.60% senior notes due 2029. Proceeds from the issuance of the senior notes were used to refinance existing indebtedness, including amounts outstanding under the FE regulated companies’ money pool incurred in connection with the repayment at maturity of PN’s $125 million of 6.63% senior notes due 2019, to fund capital expenditures, and for other general corporate purposes. On June 5, 2019, AGC issued $50 million of 4.47% senior unsecured notes due 2029. Proceeds from the issuance of the senior notes were used to improve liquidity, re-establish the debt component within its capital structure following the recent redemption of all of its existing long-term debt, and satisfy working capital requirements and other general corporate purposes. On August 15, 2019, WP issued $150 million of 4.22% FMBs due 2059. Proceeds were used to refinance existing indebtedness, fund capital expenditures and for other general corporate purposes. On November 14, 2019, MP issued $155 million of 3.23% FMBs due 2029 and $45 million of 3.93% FMBs due 2049. Proceeds were used to refinance existing debt, to fund capital expenditures, and for other general corporate purposes. Cash Flows From Investing Activities Cash used for investing activities in 2019 principally represented cash used for property additions. The following table summarizes investing activities for 2019, 2018 and 2017: Cash Used for Investing Activities 2019 2018 2017 For the Years Ended December 31, Property Additions: Regulated Distribution Regulated Transmission Corporate/Other Nuclear fuel Proceeds from asset sales Investments Asset removal costs Other Notes receivable from affiliated companies (In millions) $ 1,473 $ 1,411 $ 1,090 1,104 102 — (47) 38 — 217 — 160 — (425) 54 500 218 (4) 1,191 1,030 366 254 (388) 98 — 172 — $ 2,873 $ 3,018 $ 2,723 On January 10, 2019, ME issued $500 million of 4.30% senior notes due 2029. Proceeds from the issuance of senior notes were primarily used to refinance existing indebtedness, including ME’s $300 million of 7.70% senior notes due 2019, and borrowings outstanding under the FE regulated utility money pool and the FE Facility, to fund capital expenditures, and for other general corporate purposes. Cash used for investing activities in 2019 decreased $145 million compared to 2018, primarily due to the decrease in notes receivable from affiliated companies resulting from FES's borrowings from the committed line of credit available under the secured credit facility with FE during the first quarter of 2018 and investments, partially offset by lower proceeds from asset sales. 25 26 FirstEnergy's Consolidated Statements of Cash Flows combine cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of operating cash flow items from discontinued operations for the years ended December 31, 2019, 2018 and 2017: (In millions) CASH FLOWS FROM OPERATING ACTIVITIES: Income (loss) from discontinued operations Gain on disposal, net of tax For the Years Ended December 31, 2019 2018 2017 $ 8 $ 326 $ (1,435) (59) (435) — Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs Deferred income taxes and investment tax credits, net Unrealized (gain) loss on derivative transactions — 47 — 110 61 (10) 333 (842) 81 Cash Flows From Financing Activities Cash provided from financing activities was $656 million and $1,394 million in 2019 and 2018, respectively, compared to cash used for financing activities of $702 million in 2017. The following table summarizes new equity and debt financing, redemptions, repayments, make-whole premiums paid on debt redemptions short-term borrowings and dividends: Securities Issued or Redeemed / Repaid 2019 2018 2017 New Issues Preferred stock issuance Common stock issuance Unsecured notes PCRBs FMBs Term loan Redemptions / Repayments Unsecured notes PCRBs FMBs Term loan Senior secured notes For the Years Ended December 31, (In millions) $ — $ 1,616 $ — 1,850 — 450 — 850 850 74 50 500 — — 3,800 — 625 250 $ 2,300 $ 3,940 $ 4,675 $ (725) $ (555) $ (1,330) — (1) — (63) (216) (325) (1,450) (62) (158) (725) — (78) (789) $ (2,608) $ (2,291) $ $ $ $ $ Tender premiums paid on debt redemptions — $ (89) $ — Short-term borrowings (repayments), net — $ 950 $ (2,375) On February 8, 2019, JCP&L issued $400 million of 4.30% senior notes due 2026. Proceeds from the issuance of the senior notes were primarily used to refinance existing indebtedness, including amounts outstanding under the FE regulated utility money pool incurred in connection with the repayment at maturity of JCP&L’s $300 million of 7.35% senior notes due 2019 and the funding of storm recovery and restoration costs and expenses, to fund capital expenditures and working capital requirements and for other general corporate purposes. On March 28, 2019, FET issued $500 million of 4.55% senior notes due 2049. Proceeds from the issuance of the senior notes were used primarily to support FET’s capital structure, to repay short-term borrowings outstanding under the FE unregulated money pool, to finance capital improvements, and for other general corporate purposes, including funding working capital needs and day-to-day operations. On April 15, 2019, ATSI issued $100 million of 4.38% senior notes due 2031. Proceeds from the issuance of the senior notes were used primarily to repay short-term borrowings, to fund capital expenditures and working capital needs, and for other general corporate purposes. On May 21, 2019, WP issued $100 million of 4.22% FMBs due 2059. Proceeds from the issuance of the FMBs were or are, as the case may be, used to refinance existing indebtedness, to fund capital expenditures, and for other general corporate purposes. On June 3, 2019, PN issued $300 million of 3.60% senior notes due 2029. Proceeds from the issuance of the senior notes were used to refinance existing indebtedness, including amounts outstanding under the FE regulated companies’ money pool incurred in connection with the repayment at maturity of PN’s $125 million of 6.63% senior notes due 2019, to fund capital expenditures, and for other general corporate purposes. On June 5, 2019, AGC issued $50 million of 4.47% senior unsecured notes due 2029. Proceeds from the issuance of the senior notes were used to improve liquidity, re-establish the debt component within its capital structure following the recent redemption of all of its existing long-term debt, and satisfy working capital requirements and other general corporate purposes. On August 15, 2019, WP issued $150 million of 4.22% FMBs due 2059. Proceeds were used to refinance existing indebtedness, fund capital expenditures and for other general corporate purposes. On November 14, 2019, MP issued $155 million of 3.23% FMBs due 2029 and $45 million of 3.93% FMBs due 2049. Proceeds were used to refinance existing debt, to fund capital expenditures, and for other general corporate purposes. Cash Flows From Investing Activities Cash used for investing activities in 2019 principally represented cash used for property additions. The following table summarizes investing activities for 2019, 2018 and 2017: Cash Used for Investing Activities 2019 2018 2017 For the Years Ended December 31, Property Additions: Regulated Distribution Regulated Transmission Corporate/Other Nuclear fuel Proceeds from asset sales Investments Notes receivable from affiliated companies Asset removal costs Other (In millions) $ 1,473 $ 1,411 $ 1,090 1,104 102 — (47) 38 — 217 — 160 — (425) 54 500 218 (4) 1,191 1,030 366 254 (388) 98 — 172 — Preferred stock dividend payments (6) $ (61) $ — $ 2,873 $ 3,018 $ 2,723 Common stock dividend payments (814) $ (711) $ (639) 2019 compared with 2018 On January 10, 2019, ME issued $500 million of 4.30% senior notes due 2029. Proceeds from the issuance of senior notes were primarily used to refinance existing indebtedness, including ME’s $300 million of 7.70% senior notes due 2019, and borrowings outstanding under the FE regulated utility money pool and the FE Facility, to fund capital expenditures, and for other general corporate purposes. Cash used for investing activities in 2019 decreased $145 million compared to 2018, primarily due to the decrease in notes receivable from affiliated companies resulting from FES's borrowings from the committed line of credit available under the secured credit facility with FE during the first quarter of 2018 and investments, partially offset by lower proceeds from asset sales. 25 26 FirstEnergy's Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of investing cash flow items from discontinued operations for the years ended December 31, 2019, 2018 and 2017: (In millions) For the Years Ended December 31, 2017 2018 2019 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions Nuclear fuel Sales of investment securities held in trusts Purchases of investment securities held in trusts $ — $ — — — (27) $ — 109 (122) (317) (254) 940 (999) REGULATORY ASSETS AND LIABILITIES Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy, the Utilities and the Transmission Companies net their regulatory assets and liabilities based on federal and state jurisdictions. Management assesses the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Management applies judgment in evaluating the evidence available to assess the probability of recovery of regulatory assets from customers, including, but not limited to evaluating evidence related to precedent for similar items at the Company and information on comparable companies within similar jurisdictions, as well as assessing progress of communications between the Company and regulators. Certain of these regulatory assets, totaling approximately $111 million as of December 31, 2019, are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific order. The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2019 and December 31, 2018, and the changes during the year ended December 31, 2019: Nuclear decommissioning and spent fuel disposal costs - Reflects a regulatory liability representing amounts collected from customers and placed in external trusts including income, losses and changes in fair value thereon (as well as accretion of the related ARO) primarily for the future decommissioning of TMI-2. Asset removal costs - Primarily represents the rates charged to customers that include a provision for the cost of future activities to remove assets, including obligations for which an ARO has been recognized, that are expected to be incurred at the time of retirement. Deferred transmission costs - Principally represents differences between revenues earned based on actual costs for the formula-rate Transmission Companies and the amounts billed. Amounts are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods. Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain electric customer heating discounts, fuel and purchased power regulatory assets at the Ohio Companies (amortized through 2034) as well as the ENEC at MP and PE. 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. The ENEC rate is updated Deferred distribution costs - Primarily relates to the Ohio Companies' deferral of certain expenses resulting from distribution and reliability related expenditures, including interest, and are amortized through 2036. Contract valuations - Includes the changes in fair value of PN above-market NUG costs and the amortization of purchase accounting adjustments at MP and PE which were recorded in connection with the AE merger representing the fair value of NUG purchased power contracts (amortized over the life of the contracts with various end dates from 2034 through annually. 2036). Storm-related costs - Relates to the recovery of storm costs, which vary by jurisdiction. Approximately $193 million and $232 million are currently being recovered through rates as of December 31, 2019 and 2018, respectively. The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2019 and 2018, of which approximately $228 million and $290 million, respectively, are currently being recovered through rates over varying periods depending on the nature of the deferral and the jurisdiction. Net Regulatory Assets (Liabilities) by Source December 31, 2019 December 31, 2018 Change Regulatory Assets by Source Not Earning a December 31, December 31, Current Return 2019 2018 Change Regulatory transition costs Customer payables for future income taxes Nuclear decommissioning and spent fuel disposal costs Asset removal costs Deferred transmission costs Deferred generation costs Deferred distribution costs Contract valuations Storm-related costs Other (In millions) $ (8) $ 49 $ (2,605) (197) (756) 298 214 155 51 551 36 (2,725) (148) (787) 170 202 208 72 500 52 Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (2,261) $ (2,407) $ The following is a description of the regulatory assets and liabilities described above: (57) 120 (49) 31 128 12 (53) (21) 51 (16) 146 Regulatory transition costs - Includes the recovery of PN above-market NUG costs; JCP&L costs incurred during the transition to a competitive retail market and under-recovered during the period from August 1, 1999 through July 31, 2003; and JCP&L costs associated with BGS, capacity and ancillary services, net of all revenues from the sale of the committed supply in the wholesale market. Amounts are amortized primarily through 2021. Customer payables for future income taxes - Reflects amounts to be recovered or refunded through future rates to pay income taxes that become payable when rate revenue is provided to recover items such as AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes such as tax reform. These amounts are being amortized over the period in which the related deferred tax assets reverse, which is generally over the expected life of the underlying asset. Regulatory transition costs Deferred transmission costs Deferred generation costs Storm-related costs Other (in millions) $ 7 $ $ 27 15 471 25 10 80 8 363 42 (3) (53) 7 108 (17) 42 Regulatory Assets Not Earning a Current Return $ 545 $ 503 $ 27 28 Nuclear decommissioning and spent fuel disposal costs - Reflects a regulatory liability representing amounts collected from customers and placed in external trusts including income, losses and changes in fair value thereon (as well as accretion of the related ARO) primarily for the future decommissioning of TMI-2. Asset removal costs - Primarily represents the rates charged to customers that include a provision for the cost of future activities to remove assets, including obligations for which an ARO has been recognized, that are expected to be incurred at the time of retirement. Deferred transmission costs - Principally represents differences between revenues earned based on actual costs for the formula-rate Transmission Companies and the amounts billed. Amounts are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods. Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain electric customer heating discounts, fuel and purchased power regulatory assets at the Ohio Companies (amortized through 2034) as well as the ENEC at MP and PE. 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. The ENEC rate is updated annually. Deferred distribution costs - Primarily relates to the Ohio Companies' deferral of certain expenses resulting from distribution and reliability related expenditures, including interest, and are amortized through 2036. Contract valuations - Includes the changes in fair value of PN above-market NUG costs and the amortization of purchase accounting adjustments at MP and PE which were recorded in connection with the AE merger representing the fair value of NUG purchased power contracts (amortized over the life of the contracts with various end dates from 2034 through 2036). Storm-related costs - Relates to the recovery of storm costs, which vary by jurisdiction. Approximately $193 million and $232 million are currently being recovered through rates as of December 31, 2019 and 2018, respectively. The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2019 and 2018, of which approximately $228 million and $290 million, respectively, are currently being recovered through rates over varying periods depending on the nature of the deferral and the jurisdiction. Regulatory Assets by Source Not Earning a Current Return December 31, 2019 December 31, 2018 Change Regulatory transition costs Deferred transmission costs Deferred generation costs Storm-related costs Other $ 7 $ 27 15 471 25 (in millions) $ 10 80 8 363 42 Regulatory Assets Not Earning a Current Return $ 545 $ 503 $ (3) (53) 7 108 (17) 42 FirstEnergy's Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of investing cash flow items from discontinued operations for the years ended December 31, 2019, 2018 and 2017: (In millions) Property additions Nuclear fuel CASH FLOWS FROM INVESTING ACTIVITIES: Sales of investment securities held in trusts Purchases of investment securities held in trusts For the Years Ended December 31, 2019 2018 2017 $ — $ (27) $ — — — — 109 (122) (317) (254) 940 (999) REGULATORY ASSETS AND LIABILITIES Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy, the Utilities and the Transmission Companies net their regulatory assets and liabilities based on federal and state jurisdictions. Management assesses the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Management applies judgment in evaluating the evidence available to assess the probability of recovery of regulatory assets from customers, including, but not limited to evaluating evidence related to precedent for similar items at the Company and information on comparable companies within similar jurisdictions, as well as assessing progress of communications between the Company and regulators. Certain of these regulatory assets, totaling approximately $111 million as of December 31, 2019, are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific order. The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2019 and December 31, 2018, and the changes during the year ended December 31, 2019: Net Regulatory Assets (Liabilities) by Source Regulatory transition costs Customer payables for future income taxes Nuclear decommissioning and spent fuel disposal costs Asset removal costs Deferred transmission costs Deferred generation costs Deferred distribution costs Contract valuations Storm-related costs Other December 31, December 31, 2019 2018 Change (In millions) $ (8) $ 49 $ (2,605) (197) (756) 298 214 155 51 551 36 (2,725) (148) (787) 170 202 208 72 500 52 (57) 120 (49) 31 128 12 (53) (21) 51 (16) 146 Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (2,261) $ (2,407) $ The following is a description of the regulatory assets and liabilities described above: Regulatory transition costs - Includes the recovery of PN above-market NUG costs; JCP&L costs incurred during the transition to a competitive retail market and under-recovered during the period from August 1, 1999 through July 31, 2003; and JCP&L costs associated with BGS, capacity and ancillary services, net of all revenues from the sale of the committed supply in the wholesale market. Amounts are amortized primarily through 2021. Customer payables for future income taxes - Reflects amounts to be recovered or refunded through future rates to pay income taxes that become payable when rate revenue is provided to recover items such as AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes such as tax reform. These amounts are being amortized over the period in which the related deferred tax assets reverse, which is generally over the expected life of the underlying asset. 27 28 CONTRACTUAL OBLIGATIONS As of December 31, 2019, FirstEnergy's estimated undiscounted cash payments under existing contractual obligations that it considers firm obligations are as follows: indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments FirstEnergy and its subsidiaries could be required to make under these guarantees as of December 31, 2019, was approximately $1.6 billion, as summarized below: Contractual Obligations Total 2020 2021-2022 2023-2024 Thereafter Guarantees and Other Assurances Long-term debt(1) Short-term borrowings Interest on long-term debt(2) Operating leases(3) Finance leases(3) Fuel and purchased power(4) Capital expenditures(5) Pension funding FES bankruptcy settlement agreement(6) Intercompany tax allocation agreement(7) Total $ 20,066 $ 364 $ 2,024 $ 2,440 $ 15,238 (In millions) 1,000 12,131 339 80 1,687 1,445 1,385 853 100 1,000 928 40 20 540 503 — 853 100 — 1,781 80 32 770 573 159 — — — 1,581 65 12 377 369 721 — — — 7,841 154 16 — — 505 — — $ 39,086 $ 4,348 $ 5,419 $ 5,565 $ 23,754 (1) (2) (3) Excludes unamortized discounts and premiums, fair value accounting adjustments and finance leases. Interest on variable-rate debt based on rates as of December 31, 2019. See Note 8, "Leases," of the Notes to Consolidated Financial Statements. Amounts under contract with fixed or minimum quantities based on estimated annual requirements. (4) (5) Amounts represent committed capital expenditures as of December 31, 2019. (6) Assumes FES Debtors emergence in 2020, see Note 1, "Organization and Basis of Presentation," of the Notes to Consolidated Financial Statements for further discussion on settlement. (7) Estimated amounts owed to the FES Debtors under the intercompany tax allocation agreement for the 2018 and 2019 tax returns, see Note 1, "Organization and Basis of Presentation," of the Notes to Consolidated Financial Statements for further discussion on tax sharing agreement with the FES Debtors. Excluded from the table above are estimates for the cash outlays from power purchase contracts entered into by most of the Utilities and under which they procure the power supply necessary to provide generation service to their customers who do not choose an alternative supplier. Although actual amounts will be determined by future customer behavior and consumption levels, management currently estimates these cash outlays will be approximately $2.6 billion in 2020. The table above also excludes regulatory liabilities (see Note 14, "Regulatory Matters"), AROs (see Note 13, "Asset Retirement Obligations"), reserves for litigation, injuries and damages, environmental remediation, and annual insurance premiums, including nuclear insurance (see Note 15, "Commitments, Guarantees and Contingencies") since the amount and timing of the cash payments are uncertain. The table also excludes accumulated deferred income taxes and investment tax credits since cash payments for income taxes are determined based primarily on taxable income for each applicable fiscal year. NUCLEAR INSURANCE JCP&L, ME and PN maintain property damage insurance provided by NEIL for their interest in the retired TMI- 2 nuclear facility, a permanently shut down and defueled facility. Under these arrangements, up to $150 million of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. JCP&L, ME and PN pay annual premiums and are subject to retrospective premium assessments of up to approximately $1.2 million during a policy year. JCP&L, ME and PN intend to maintain insurance against nuclear risks as long as it is available. To the extent that property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of JCP&L, ME or PN’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by JCP&L, ME or PN’s insurance policies, or to the extent such insurance becomes unavailable in the future, JCP&L, ME or PN would remain at risk for such costs. The Price-Anderson Act limits public liability relative to a single incident at a nuclear power plant. In connection with TMI-2, JCP&L, ME and PN carry the required ANI third party liability coverage and also have coverage under a Price Anderson indemnity agreement issued by the NRC. The total available coverage in the event of a nuclear incident is $560 million, which is also the limit of public liability for any nuclear incident involving TMI-2. GUARANTEES AND OTHER ASSURANCES FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and 29 FE's Guarantees on Behalf of the FES Debtors Surety Bonds - FG(1) Deferred compensation arrangements FE's Guarantees on Behalf of its Consolidated Subsidiaries AE Supply asset sales(2) Deferred compensation arrangements Fuel related contracts and other FE's Guarantees on Other Assurances Global Holding Facility Surety Bonds LOCs and other Maximum Exposure (In millions) $ 200 150 350 555 466 10 114 135 16 265 1,031 Total Guarantees and Other Assurances $ 1,646 (1) FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield's Ferry CCR disposal site, respectively. (2) As a condition to closing AE Supply's sale of four natural gas generating plants in December 2017, FE provided the purchaser two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC. In connection with the FES Bankruptcy settlement agreement, FirstEnergy has provided certain additional guarantees to FG for retained environmental liabilities of AE Supply related to the Pleasants Power Station and the McElroy's Run CCR disposal facility. Collateral and Contingent-Related Features In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on AE Supply's power portfolio exposure as of December 31, 2019, AE Supply has posted no collateral. The Utilities and Transmission Companies have posted no collateral. These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of December 31, 2019: Potential Collateral Obligations Contractual Obligations for Additional Collateral At Current Credit Rating Upon Further Downgrade Surety Bonds (Collateralized Amount)(1) Total Exposure from Contractual Obligations AE Supply Utilities and FET FE Total (In millions) 1 — — 1 $ $ — $ — $ 36 63 99 $ — 257 257 $ 1 36 320 357 $ $ 30 As of December 31, 2019, FirstEnergy's estimated undiscounted cash payments under existing contractual obligations that it indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments FirstEnergy and its subsidiaries could be required to make under these guarantees as of December 31, 2019, was approximately $1.6 billion, as summarized below: Contractual Obligations Total 2020 2021-2022 2023-2024 Thereafter Guarantees and Other Assurances Maximum Exposure (In millions) FE's Guarantees on Behalf of the FES Debtors Surety Bonds - FG(1) Deferred compensation arrangements $ FE's Guarantees on Behalf of its Consolidated Subsidiaries AE Supply asset sales(2) Deferred compensation arrangements Fuel related contracts and other FE's Guarantees on Other Assurances Global Holding Facility Surety Bonds LOCs and other 200 150 350 555 466 10 1,031 114 135 16 265 Total Guarantees and Other Assurances $ 1,646 FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield's Ferry CCR disposal site, respectively. (2) As a condition to closing AE Supply's sale of four natural gas generating plants in December 2017, FE provided the purchaser two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC. In connection with the FES Bankruptcy settlement agreement, FirstEnergy has provided certain additional guarantees to FG for retained environmental liabilities of AE Supply related to the Pleasants Power Station and the McElroy's Run CCR disposal facility. Total (1) (2) (3) (4) Excludes unamortized discounts and premiums, fair value accounting adjustments and finance leases. Interest on variable-rate debt based on rates as of December 31, 2019. See Note 8, "Leases," of the Notes to Consolidated Financial Statements. Amounts under contract with fixed or minimum quantities based on estimated annual requirements. (5) Amounts represent committed capital expenditures as of December 31, 2019. (6) Assumes FES Debtors emergence in 2020, see Note 1, "Organization and Basis of Presentation," of the Notes to Consolidated Financial (1) CONTRACTUAL OBLIGATIONS considers firm obligations are as follows: Long-term debt(1) Short-term borrowings Interest on long-term debt(2) Operating leases(3) Finance leases(3) Fuel and purchased power(4) Capital expenditures(5) Pension funding FES bankruptcy settlement agreement(6) Intercompany tax allocation agreement(7) $ 20,066 $ 364 $ 2,024 $ 2,440 $ 15,238 (In millions) 1,000 12,131 339 80 1,687 1,445 1,385 853 100 1,000 928 40 20 540 503 — 853 100 — 1,781 80 32 770 573 159 — — — 1,581 65 12 377 369 721 — — — 7,841 154 16 — — 505 — — $ 39,086 $ 4,348 $ 5,419 $ 5,565 $ 23,754 Statements for further discussion on settlement. (7) Estimated amounts owed to the FES Debtors under the intercompany tax allocation agreement for the 2018 and 2019 tax returns, see Note 1, "Organization and Basis of Presentation," of the Notes to Consolidated Financial Statements for further discussion on tax sharing agreement with the FES Debtors. Excluded from the table above are estimates for the cash outlays from power purchase contracts entered into by most of the Utilities and under which they procure the power supply necessary to provide generation service to their customers who do not choose an alternative supplier. Although actual amounts will be determined by future customer behavior and consumption levels, management currently estimates these cash outlays will be approximately $2.6 billion in 2020. The table above also excludes regulatory liabilities (see Note 14, "Regulatory Matters"), AROs (see Note 13, "Asset Retirement Obligations"), reserves for litigation, injuries and damages, environmental remediation, and annual insurance premiums, including nuclear insurance (see Note 15, "Commitments, Guarantees and Contingencies") since the amount and timing of the cash payments are uncertain. The table also excludes accumulated deferred income taxes and investment tax credits since cash payments for income taxes are determined based primarily on taxable income for each applicable fiscal year. NUCLEAR INSURANCE JCP&L, ME and PN maintain property damage insurance provided by NEIL for their interest in the retired TMI- 2 nuclear facility, a permanently shut down and defueled facility. Under these arrangements, up to $150 million of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. JCP&L, ME and PN pay annual premiums and are subject to retrospective premium assessments of up to approximately $1.2 million during a policy year. JCP&L, ME and PN intend to maintain insurance against nuclear risks as long as it is available. To the extent that property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of JCP&L, ME or PN’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by JCP&L, ME or PN’s insurance policies, or to the extent such insurance becomes unavailable in the future, JCP&L, ME or PN would remain at risk for such costs. Collateral and Contingent-Related Features In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on AE Supply's power portfolio exposure as of December 31, 2019, AE Supply has posted no collateral. The Utilities and Transmission Companies have posted no collateral. These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of December 31, 2019: The Price-Anderson Act limits public liability relative to a single incident at a nuclear power plant. In connection with TMI-2, JCP&L, ME and PN carry the required ANI third party liability coverage and also have coverage under a Price Anderson indemnity agreement Contractual Obligations for Additional Collateral issued by the NRC. The total available coverage in the event of a nuclear incident is $560 million, which is also the limit of public At Current Credit Rating Potential Collateral Obligations liability for any nuclear incident involving TMI-2. GUARANTEES AND OTHER ASSURANCES FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and 29 Upon Further Downgrade Surety Bonds (Collateralized Amount)(1) Total Exposure from Contractual Obligations AE Supply Utilities and FET FE Total (In millions) 1 — — 1 $ $ — $ — $ 36 63 99 $ — 257 257 $ 1 36 320 357 $ $ 30 (1) Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield's Ferry CCR disposal site, respectively. Interest Rate Risk Other Commitments and Contingencies FE is a guarantor under a $120 million syndicated senior secured term loan facility due November 12, 2024, under which Global Holding's outstanding principal balance is $114 million as of December 31, 2019. In addition to FE, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several guaranties of the obligations of Global Holding under the facility. new debt securities. Comparison of Carrying Value to Fair Value Year of Maturity 2020 2021 2022 2023 2024 There- after Total Fair Value (In millions) In connection with the facility, 69.99% of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral. Assets: Investments Other Than Cash and Cash Equivalents: FirstEnergy’s exposure to fluctuations in market interest rates is reduced since a significant portion of debt has fixed interest rates, as noted in the table below. FirstEnergy is subject to the inherent interest rate risks related to refinancing maturing debt by issuing MARKET RISK INFORMATION FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company. Commodity Price Risk FirstEnergy has limited exposure to financial risks resulting from fluctuating commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy's Risk Management Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. The valuation of derivative contracts is based on observable market information. As of December 31, 2019, FirstEnergy has a net liability of $13 million in non-hedge derivative contracts that are primarily related to NUG contracts at certain of the Utilities. NUG contracts are subject to regulatory accounting and do not impact earnings. Equity Price Risk As of December 31, 2019, the FirstEnergy pension plan assets were allocated approximately as follows: 29% in equity securities, 36% in fixed income securities, 9% in hedge funds, 2% in insurance-linked securities, 7% in real estate, 4% in private equity and 13% in cash and short-term securities. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. FirstEnergy expects no required contributions through 2021. See Note 5, "Pension and Other Postemployment Benefits," of the Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension and OPEB plans. Through December 31, 2019, FirstEnergy's pension plan assets have earned approximately 20.3% as compared to an annual expected return on plan assets of 7.50%. As of December 31, 2019, FirstEnergy's OPEB plans were invested in fixed income and equity securities. Through December 31, 2019, FirstEnergy's OPEB plans have earned approximately 18.1% as compared to an annual expected return on plan assets of 7.50%. NDT funds have been established to satisfy JCP&L, ME and PN's nuclear decommissioning obligations associated with TMI-2. As of December 31, 2019, approximately 15% and 85% of the funds were invested in fixed income securities and short-term investments, respectively, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $135 million and $763 million for fixed income securities and short-term investments, respectively, as of December 31, 2019, excluding $16 million of net receivables, payables and accrued income. A decline in the value of JCP&L, ME and PN’s NDTs or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2019, JCP&L, ME and PN made no contributions to the NDTs. Fixed Income $ — $ — $ — $ — $ — $ 401 $ 401 $ 401 Average interest rate —% —% —% —% —% 3.0% 3.0% Liabilities: Long-term Debt: Fixed rate CREDIT RISK 364 $ 132 $ 1,142 $ 1,194 $ 1,246 $ 15,238 $ 19,316 $22,178 Average interest rate 5.4% 3.7% 4.1% 4.1% 4.7% 4.9% 4.8% Variable rate — $ 750 $ — $ — $ — $ — $ 750 $ 750 Average interest rate —% 2.5% —% —% —% —% 2.5% $ $ FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. A primary factor contributing to these actuarial gains and losses are changes in the discount rates used to value pension and OPEB obligations as of the measurement date and the difference between expected and actual returns on the plans’ assets. Upon the FES Debtors' emergence from bankruptcy, FirstEnergy will perform a remeasurement of the pension and OPEB plans. Assuming an emergence in the first quarter of 2020, FirstEnergy anticipates an after-tax mark-to-market loss to be up to $400 million assuming a discount rate of approximately 3.10% to 3.35% and a return on the pension and OPEB plans’ assets based on actual investment performance through January 31, 2020. Credit risk is the risk that FirstEnergy would incur a loss as a result of nonperformance by counterparties of their contractual obligations. FirstEnergy maintains credit policies and procedures with respect to counterparty credit (including requirement that counterparties maintain specified credit ratings) and require other assurances in the form of credit support or collateral in certain circumstance in order to limit counterparty credit risk. However, FirstEnergy, as applicable, has concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact FirstEnergy's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. In the event an energy supplier of the Ohio Companies, Pennsylvania Companies, JCP&L or PE defaults on its obligation, the affected company would be required to seek replacement power in the market. In general, subject to regulatory review or other processes, appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities. FirstEnergy's credit policies to manage credit risk include the use of an established credit approval process, daily credit mitigation provisions, such as margin, prepayment or collateral requirements. FirstEnergy and its subsidiaries may request additional credit assurance, in certain circumstances, in the event that the counterparties' credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit. OUTLOOK 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. 31 32 (1) Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield's Ferry CCR disposal site, respectively. Other Commitments and Contingencies FE is a guarantor under a $120 million syndicated senior secured term loan facility due November 12, 2024, under which Global Holding's outstanding principal balance is $114 million as of December 31, 2019. In addition to FE, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several guaranties of the obligations of Global Holding under the facility. In connection with the facility, 69.99% of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral. FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company. MARKET RISK INFORMATION Commodity Price Risk FirstEnergy has limited exposure to financial risks resulting from fluctuating commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy's Risk Management Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. The valuation of derivative contracts is based on observable market information. As of December 31, 2019, FirstEnergy has a net liability of $13 million in non-hedge derivative contracts that are primarily related to NUG contracts at certain of the Utilities. NUG contracts are subject to regulatory accounting and do not impact earnings. Equity Price Risk As of December 31, 2019, the FirstEnergy pension plan assets were allocated approximately as follows: 29% in equity securities, 36% in fixed income securities, 9% in hedge funds, 2% in insurance-linked securities, 7% in real estate, 4% in private equity and 13% in cash and short-term securities. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. FirstEnergy expects no required contributions through 2021. See Note 5, "Pension and Other Postemployment Benefits," of the Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension and OPEB plans. Through December 31, 2019, FirstEnergy's pension plan assets have earned approximately 20.3% as compared to an annual expected return on plan assets of 7.50%. As of December 31, 2019, FirstEnergy's OPEB plans were invested in fixed income and equity securities. Through December 31, 2019, FirstEnergy's OPEB plans have earned approximately 18.1% as compared to an annual expected return on plan assets of 7.50%. NDT funds have been established to satisfy JCP&L, ME and PN's nuclear decommissioning obligations associated with TMI-2. As of December 31, 2019, approximately 15% and 85% of the funds were invested in fixed income securities and short-term investments, respectively, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $135 million and $763 million for fixed income securities and short-term investments, respectively, as of Interest Rate Risk FirstEnergy’s exposure to fluctuations in market interest rates is reduced since a significant portion of debt has fixed interest rates, as noted in the table below. FirstEnergy is subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. Comparison of Carrying Value to Fair Value Year of Maturity 2020 2021 2022 2023 2024 There- after Total Fair Value (In millions) Assets: Investments Other Than Cash and Cash Equivalents: Fixed Income Average interest rate Liabilities: Long-term Debt: Fixed rate Average interest rate Variable rate Average interest rate $ $ $ — $ —% — $ —% — $ —% — $ —% — $ —% $ 401 3.0% 401 3.0% $ 401 $ 364 5.4% — $ —% 132 3.7% 750 2.5% $ 1,142 $ 1,194 $ 1,246 $ 15,238 $ 19,316 $22,178 $ 4.1% — $ —% 4.1% — $ —% 4.7% — $ —% 4.9% — $ —% 4.8% 750 2.5% $ 750 FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. A primary factor contributing to these actuarial gains and losses are changes in the discount rates used to value pension and OPEB obligations as of the measurement date and the difference between expected and actual returns on the plans’ assets. Upon the FES Debtors' emergence from bankruptcy, FirstEnergy will perform a remeasurement of the pension and OPEB plans. Assuming an emergence in the first quarter of 2020, FirstEnergy anticipates an after-tax mark-to-market loss to be up to $400 million assuming a discount rate of approximately 3.10% to 3.35% and a return on the pension and OPEB plans’ assets based on actual investment performance through January 31, 2020. CREDIT RISK Credit risk is the risk that FirstEnergy would incur a loss as a result of nonperformance by counterparties of their contractual obligations. FirstEnergy maintains credit policies and procedures with respect to counterparty credit (including requirement that counterparties maintain specified credit ratings) and require other assurances in the form of credit support or collateral in certain circumstance in order to limit counterparty credit risk. However, FirstEnergy, as applicable, has concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact FirstEnergy's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. In the event an energy supplier of the Ohio Companies, Pennsylvania Companies, JCP&L or PE defaults on its obligation, the affected company would be required to seek replacement power in the market. In general, subject to regulatory review or other processes, appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities. FirstEnergy's credit policies to manage credit risk include the use of an established credit approval process, daily credit mitigation provisions, such as margin, prepayment or collateral requirements. FirstEnergy and its subsidiaries may request additional credit assurance, in certain circumstances, in the event that the counterparties' credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit. December 31, 2019, excluding $16 million of net receivables, payables and accrued income. A decline in the value of JCP&L, ME OUTLOOK and PN’s NDTs or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2019, JCP&L, ME and PN made no contributions to the NDTs. 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. 31 32 The following table summarizes the key terms of distribution rate orders in effect for the Utilities: Company CEI ME(1) MP JCP&L OE PE (West Virginia) PE (Maryland) PN(1) Penn(1) TE WP(1) (1) Reflects filed debt/equity as final settlement/orders do not specifically include capital structure. (2) Commission-approved settlement agreements did not disclose ROE rates. Rates Effective May 2009 January 2017 February 2015 January 2017 January 2009 February 2015 March 2019 January 2017 January 2017 January 2009 January 2017 Allowed Debt/ Equity 51% / 49% 48.8% / 51.2% 54% / 46% 55% / 45% 51% / 49% 54% / 46% 47% / 53% 47.4% / 52.6% 49.9% / 50.1% 51% / 49% 49.7% / 50.3% Allowed ROE 10.5% Settled(2) Settled(2) 9.6% 10.5% Settled(2) 9.65% Settled(2) Settled(2) 10.5% Settled(2) 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. 33 34 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 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 was refunded to customers in 2019. 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 JCP&L expects to file a distribution base rate case in New Jersey in February 2020, which will seek to recover certain costs associated with providing safe and reliable electric service to JCP&L customers, along with recovery of previously incurred storm modification. costs. OHIO The Ohio Companies operate under base distribution rates approved by the PUCO effective in 2009. The Ohio Companies’ residential and commercial base distribution revenues are decoupled, through a mechanism that took effect on February 1, 2020, to the base distribution revenue and lost distribution revenue associated with energy efficiency and peak demand reduction programs recovered as of the twelve-month period ending on December 31, 2018. The Ohio Companies currently operate under ESP IV effective June 1, 2016, and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (3) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low- income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio. ESP IV further provided for the Ohio Companies to collect through 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. On October 1, 2019, the Ohio The following table summarizes the key terms of distribution rate orders in effect for the Utilities: Company CEI ME(1) MP JCP&L OE PN(1) Penn(1) TE WP(1) PE (West Virginia) PE (Maryland) MARYLAND Rates Effective Allowed Debt/ Equity Allowed ROE May 2009 51% / 49% January 2017 48.8% / 51.2% February 2015 January 2017 January 2009 February 2015 March 2019 54% / 46% 55% / 45% 51% / 49% 54% / 46% 47% / 53% January 2017 47.4% / 52.6% January 2017 49.9% / 50.1% January 2009 51% / 49% January 2017 49.7% / 50.3% 10.5% Settled(2) Settled(2) 9.6% 10.5% Settled(2) 9.65% Settled(2) Settled(2) 10.5% Settled(2) (1) Reflects filed debt/equity as final settlement/orders do not specifically include capital structure. (2) Commission-approved settlement agreements did not disclose ROE rates. 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 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 was refunded to customers in 2019. 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. JCP&L expects to file a distribution base rate case in New Jersey in February 2020, which will seek to recover certain costs associated with providing safe and reliable electric service to JCP&L customers, along with recovery of previously incurred storm costs. OHIO The Ohio Companies operate under base distribution rates approved by the PUCO effective in 2009. The Ohio Companies’ residential and commercial base distribution revenues are decoupled, through a mechanism that took effect on February 1, 2020, to the base distribution revenue and lost distribution revenue associated with energy efficiency and peak demand reduction programs recovered as of the twelve-month period ending on December 31, 2018. The Ohio Companies currently operate under ESP IV effective June 1, 2016, and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (3) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low- income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio. ESP IV further provided for the Ohio Companies to collect through 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. On October 1, 2019, the Ohio 33 34 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. PENNSYLVANIA 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 are contesting 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. Opponents to the legislation sought to submit it to a statewide referendum, and stay its effect unless and until approved by a majority of Ohio voters. Petitioners filed a lawsuit in the U.S. District Court for the Southern District of Ohio seeking additional time to gather signatures in support of a referendum. Petitioners failed to file the necessary number of petition signatures, and the legislation took effect on October 22, 2019. On October 23, 2019, the U.S. District Court denied petitioners’ request for more time, and certified questions of state law to the SCOH to answer. Petitioners appealed the U.S. District Court’s decision to the U.S. Court of Appeals for the Sixth Circuit. The Petitioners ended their challenge to the legislation voluntarily at the end of January 2020 causing the dismissal of the appeal, the lawsuit before the U.S District Court, and the proceedings before the SCOH. On November 21, 2019, the Ohio Companies applied to the PUCO for approval of a decoupling mechanism, which would set residential and commercial base distribution related revenues at the levels collected in 2018. As such, those base distribution revenues would no longer be based on electric consumption, which allows continued support of energy efficiency initiatives while also providing revenue certainty to the Ohio Companies. On January 15, 2020, the PUCO approved the Ohio Companies’ decoupling application, and the decoupling mechanism took effect on February 1, 2020. 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 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 had broad support, including PUCO Staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties. On July 17, 2019, the PUCO approved the settlement agreement with no material modifications. On September 11, 2019, the PUCO denied the application for rehearing of environmental advocates who were not parties to the settlement. 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. 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. 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. Following a periodic review of the LTIIPs in 2018 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 May 23, 2019, the PPUC approved the Pennsylvania Companies’ Modified LTIIPs that revised LTIIP spending in 2019 of approximately $45 million by ME, $25 million by PN, $26 million by Penn and $51 million by WP, and terminating at the end of 2019. On August 30, 2019, the Pennsylvania Companies filed 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 January 16, 2020, the PPUC approved the LTIIPs without modification, as well as directed the Pennsylvania Companies to submit corrective action plans by March 16, 2020, which outline how they will reduce their pole replacement backlogs over a five-year period to a rolling two-year backlog. 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. The parties to the DSIC proceeding submitted a Joint Settlement that resolved the issues that were pending from the order issued on June 9, 2016, and 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. The Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the PPUC’s decision, and the Pennsylvania Companies contested the appeal. The Commonwealth Court reversed the PPUC’s decision of April 19, 2018 and remanded the matter to the PPUC to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. The Commonwealth Court denied Applications for Reargument in the Court’s July 11, 2019 Opinion and Order filed by the PPUC and the Pennsylvania Companies. 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, the PPUC’s Bureau of Investigation, and the Pennsylvania OCA opposed Penn’s Petition. On January 17, 2020, the parties filed a petition seeking approval of settlement that provides for a temporary increase in the recoverability cap from 5% to 7.5%, which will expire on the earlier of the effective date of new base rates following Penn’s next base rate case or the expiration of its LTIIP II program. The settlement is subject to PPUC approval. WEST VIRGINIA annually. 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 35 36 Companies implemented PUCO approved tariffs to refund approximately $28 million to customers, including Rider DMR revenues PENNSYLVANIA 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 are contesting 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. Opponents to the legislation sought to submit it to a statewide referendum, and stay its effect unless and until approved by a majority of Ohio voters. Petitioners filed a lawsuit in the U.S. District Court for the Southern District of Ohio seeking additional time to gather signatures in support of a referendum. Petitioners failed to file the necessary number of petition signatures, and the legislation took effect on October 22, 2019. On October 23, 2019, the U.S. District Court denied petitioners’ request for more time, and certified questions of state law to the SCOH to answer. Petitioners appealed the U.S. District Court’s decision to the U.S. Court of Appeals for the Sixth Circuit. The Petitioners ended their challenge to the legislation voluntarily at the end of January 2020 causing the dismissal of the appeal, the lawsuit before the U.S District Court, and the proceedings before the SCOH. On November 21, 2019, the Ohio Companies applied to the PUCO for approval of a decoupling mechanism, which would set residential and commercial base distribution related revenues at the levels collected in 2018. As such, those base distribution revenues would no longer be based on electric consumption, which allows continued support of energy efficiency initiatives while also providing revenue certainty to the Ohio Companies. On January 15, 2020, the PUCO approved the Ohio Companies’ decoupling application, and the decoupling mechanism took effect on February 1, 2020. 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 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 had broad support, including PUCO Staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties. On July 17, 2019, the PUCO approved the settlement agreement with no material modifications. On September 11, 2019, the PUCO denied the application for rehearing of environmental advocates who were not parties to the settlement. 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. 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. 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. Following a periodic review of the LTIIPs in 2018 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 May 23, 2019, the PPUC approved the Pennsylvania Companies’ Modified LTIIPs that revised LTIIP spending in 2019 of approximately $45 million by ME, $25 million by PN, $26 million by Penn and $51 million by WP, and terminating at the end of 2019. On August 30, 2019, the Pennsylvania Companies filed 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 January 16, 2020, the PPUC approved the LTIIPs without modification, as well as directed the Pennsylvania Companies to submit corrective action plans by March 16, 2020, which outline how they will reduce their pole replacement backlogs over a five-year period to a rolling two-year backlog. 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. The parties to the DSIC proceeding submitted a Joint Settlement that resolved the issues that were pending from the order issued on June 9, 2016, and 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. The Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the PPUC’s decision, and the Pennsylvania Companies contested the appeal. The Commonwealth Court reversed the PPUC’s decision of April 19, 2018 and remanded the matter to the PPUC to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. The Commonwealth Court denied Applications for Reargument in the Court’s July 11, 2019 Opinion and Order filed by the PPUC and the Pennsylvania Companies. 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, the PPUC’s Bureau of Investigation, and the Pennsylvania OCA opposed Penn’s Petition. On January 17, 2020, the parties filed a petition seeking approval of settlement that provides for a temporary increase in the recoverability cap from 5% to 7.5%, which will expire on the earlier of the effective date of new base rates following Penn’s next base rate case or the expiration of its LTIIP II program. The settlement is subject to PPUC approval. 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. 35 36 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. An order was issued on December 20, 2019, approving the ENEC settlement and termination of the PPA with Morgantown Energy Associates. 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. All the parties reached a settlement in the case, and the WVPSC issued its order approving the settlement without change on December 20, 2019. 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 REGULATORY MATTERS FERC Actions on Tax Act 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. The following table summarizes the key terms of rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities: Company ATSI JCP&L MP PE WP MAIT TrAIL Rates Effective Capital Structure Allowed ROE January 1, 2015 June 1, 2017(1) March 21, 2018(2) March 21, 2018(2) March 21, 2018(2) July 1, 2017 Actual (13 month average) Settled(1)(3) Settled(3) Settled(3) Settled(3) Lower of Actual (13 month average) or 60% 10.38% Settled(1)(3) Settled(3) Settled(3) Settled(3) 10.3% July 1, 2008 Actual (year-end) 12.7% (TrAIL the Line & Black Oak SVC) 11.7% (All other projects) (1) Effective on January 1, 2020, JCP&L has implemented a forward-looking formula rate, which has been accepted by FERC, subject to refund, pending further hearing and settlement proceedings. (2) See FERC Actions on Tax Act below. (3) FERC-approved settlement agreements did not specify. 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 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 864). Order 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. Alternatively, formula rate utilities can demonstrate to FERC that their formula rate template already achieves these outcomes. Utilities with transmission stated rates are required to address these new requirements as part of their next transmission rate case. 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. FirstEnergy’s formula rate transmission utilities will make the required filings on or before the deadlines established in FERC’s order. FirstEnergy’s stated rate transmission utilities will address the requirements as part of their next transmission rate case. JCP&L is addressing the requirements in the course of its pending transmission rate case. Transmission ROE Methodology FERC’s methodology for calculating electric transmission utility ROE has been in transition as a result of an April 14, 2017 ruling by the D.C. Circuit that vacated FERC’s then-effective methodology. On October 16, 2018, FERC issued an order in which it proposed a revised ROE methodology. FERC proposed that, for complaint proceedings alleging that an existing ROE is not just and reasonable, FERC will 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. On November 21, 2019, FERC announced in a complaint proceeding involving MISO utilities that FERC would rely on the discounted cash flow and capital-asset pricing models as the basis for establishing ROE. It is not clear at this time whether FERC’s November ruling will be applied more broadly. 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 FERC dockets where the ROE methodology is being reviewed, and on December 23, 2019, JCP&L filed a request for rehearing of FERC’s November decision in the MISO utilities docket. JCP&L Transmission Formula Rate negotiations. ENVIRONMENTAL MATTERS 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 is engaged in settlement Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy's environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and 37 38 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 ENEC rates into 2020, and supports the termination of the Morgantown Energy Associates PPA, was filed with the WVPSC on October 18, 2019. An order was issued on December 20, 2019, approving the ENEC settlement and termination of the PPA with Morgantown Energy Associates. 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. All the parties reached a settlement in the case, and the WVPSC issued its order approving the settlement without change on December 20, 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 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. The following table summarizes the key terms of rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities: Company ATSI JCP&L MP PE WP MAIT TrAIL Rates Effective Capital Structure Allowed ROE January 1, 2015 Actual (13 month average) June 1, 2017(1) March 21, 2018(2) March 21, 2018(2) March 21, 2018(2) Settled(1)(3) Settled(3) Settled(3) Settled(3) July 1, 2017 Lower of Actual (13 month average) or 60% 10.38% Settled(1)(3) Settled(3) Settled(3) Settled(3) 10.3% (1) Effective on January 1, 2020, JCP&L has implemented a forward-looking formula rate, which has been accepted by FERC, subject to July 1, 2008 Actual (year-end) 12.7% (TrAIL the Line & Black Oak SVC) 11.7% (All other projects) refund, pending further hearing and settlement proceedings. (2) See FERC Actions on Tax Act below. (3) FERC-approved settlement agreements did not specify. 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 NUG entity. A settlement between MP, PE, and the majority of the intervenors fully resolving the ENEC case, which maintains 2019 RTO Realignment 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. FERC REGULATORY MATTERS FERC Actions on Tax Act On March 15, 2018, FERC initiated proceedings on the question of how to address possible changes to ADIT and bonus depreciation as a result of the Tax Act. Such possible changes could impact FERC-jurisdictional rates, including transmission rates. On November 21, 2019, FERC issued a final rule (Order 864). Order 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. Alternatively, formula rate utilities can demonstrate to FERC that their formula rate template already achieves these outcomes. Utilities with transmission stated rates are required to address these new requirements as part of their next transmission rate case. 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. FirstEnergy’s formula rate transmission utilities will make the required filings on or before the deadlines established in FERC’s order. FirstEnergy’s stated rate transmission utilities will address the requirements as part of their next transmission rate case. JCP&L is addressing the requirements in the course of its pending transmission rate case. Transmission ROE Methodology FERC’s methodology for calculating electric transmission utility ROE has been in transition as a result of an April 14, 2017 ruling by the D.C. Circuit that vacated FERC’s then-effective methodology. On October 16, 2018, FERC issued an order in which it proposed a revised ROE methodology. FERC proposed that, for complaint proceedings alleging that an existing ROE is not just and reasonable, FERC will 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. On November 21, 2019, FERC announced in a complaint proceeding involving MISO utilities that FERC would rely on the discounted cash flow and capital-asset pricing models as the basis for establishing ROE. It is not clear at this time whether FERC’s November ruling will be applied more broadly. 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 FERC dockets where the ROE methodology is being reviewed, and on December 23, 2019, JCP&L filed a request for rehearing of FERC’s November decision in the MISO utilities docket. JCP&L Transmission Formula Rate On October 30, 2019, JCP&L filed tariff amendments with FERC to convert JCP&L’s existing stated transmission rate to a forward- looking formula transmission rate. JCP&L requested that the tariff amendments become effective January 1, 2020. On December 19, 2019, FERC issued its initial order in the case, allowing JCP&L to transition to a forward-looking formula rate as of January 1, 2020 as requested, subject to refund, pending further hearing and settlement proceedings. JCP&L is engaged in settlement negotiations. ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy's environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and 37 38 potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition. Clean Air Act FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances. CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry's bid for a lengthy pause in the litigation and set a briefing schedule. On September 13, 2019, the D.C. Circuit remanded the CSAPR update rule to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may materially impact FirstEnergy's operations, cash flows and financial condition. In February 2019, the EPA announced its final decision to retain without changes the NAAQS for SO2, specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB. As of September 30, 2019, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA. In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility's NOx emissions significantly contribute to Delaware's inability to attain the ozone NAAQS. The petition sought a short-term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3 and Pleasants Units 1 and 2, significantly contribute to Maryland's inability to attain the ozone NAAQS. The petition sought NOx emission rate limits for the 36 EGUs by May 1, 2017. On September 14, 2018, the EPA denied both the States of Delaware and Maryland's petitions under CAA Section 126. In October 2018, Delaware and Maryland appealed the denials of their petitions to the D.C. Circuit. In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including Ohio, Pennsylvania and West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. On May 3, 2018, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to November 9, 2018. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss. Climate Change There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation. At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide GHG emissions by 26 to 28 percent below 2005 levels by 2025. In 2015, FirstEnergy set a goal of reducing company-wide CO2 emissions by at least 90 percent below 2005 levels by 2045. As of December 31, 2018, FirstEnergy has reduced its CO2 emissions by approximately 62 percent. In September 2016, the U.S. joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHG under the Clean Air Act,” concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. The EPA released its final CPP regulations in August 2015 to reduce CO2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. To replace the CPP, the EPA proposed the ACE rule on August 21, 2018, which would establish emission guidelines for states to develop plans to address GHG emissions from existing coal-fired power plants. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that establishes guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired power plants. Depending on the outcomes of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material. Clean Water Act Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material. On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations phase-in as permits are renewed on a five-year cycle from 2018 to 2023. On April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On November 4, 2019, the EPA issued a proposed rule revising the effluent limits for discharges from wet scrubber systems and extending the deadline for compliance to December 31, 2025. The EPA’s proposed rule retains the zero discharge standard and 2023 compliance date for ash transport water, but adds some allowances for discharge under certain circumstances. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's operations may result. On September 29, 2016, FirstEnergy received a request from the EPA for information pursuant to CWA Section 308(a) for information concerning boron exceedances of effluent limitations established in the NPDES Permit for the former Mitchell Power Station’s Mingo landfill, owned by WP. On November 1, 2016, WP provided an initial response that contained information related to a similar boron issue at the former Springdale Power Station’s landfill. The EPA requested additional information regarding the Springdale landfill and on November 15, 2016, WP provided a response and intends to fully comply with the Section 308(a) information request. On March 3, 2017, WP proposed to the PA DEP a re-route of its wastewater discharge to eliminate potential boron exceedances at the Springdale landfill. On January 29, 2018, WP submitted an NPDES permit renewal application to PA DEP proposing to re-route its wastewater discharge to eliminate potential boron exceedances at the Mingo landfill. On February 20, 2018, the DOJ issued a letter and tolling agreement on behalf of EPA alleging violations of the CWA at the Mingo landfill while seeking to enter settlement negotiations in lieu of filing a complaint. On November 4, 2019, the EPA proposed a penalty of nearly $1.3 million to settle alleged past boron exceedances at the Mingo and Springdale landfills. On December 17, 2019, WP responded to the EPA's settlement proposal but is unable to predict the outcome of this matter. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 17, 2018, the EPA Administrator signed a final rule extending the deadline for certain CCR facilities to cease disposal and commence closure activities, as well as, establishing less stringent groundwater monitoring and protection requirements. On August 21, 2018, the D.C. Circuit remanded sections of the CCR Rule to the EPA to provide additional safeguards for unlined CCR impoundments that are more protective of human health and the environment. On November 4, 2019, the EPA issued a proposed rule accelerating the 39 40 potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition. Clean Air Act FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances. CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO2 emissions from upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry's bid for a lengthy pause in the litigation and set a briefing schedule. On September 13, 2019, the D.C. Circuit remanded the CSAPR update rule to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may materially impact FirstEnergy's operations, cash flows and financial condition. In February 2019, the EPA announced its final decision to retain without changes the NAAQS for SO2, specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB. As of September 30, 2019, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA. In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility's NOx emissions significantly contribute to Delaware's inability to attain the ozone NAAQS. The petition sought a short-term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3 and Pleasants Units 1 and 2, significantly contribute to Maryland's inability to attain the ozone NAAQS. The petition sought NOx emission rate limits for the 36 EGUs by May 1, 2017. On September 14, 2018, the EPA denied both the States of Delaware and Maryland's petitions under CAA Section 126. In October 2018, Delaware and Maryland appealed the denials of their petitions to the D.C. Circuit. In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including Ohio, Pennsylvania and West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. On May 3, 2018, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to November 9, 2018. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss. Climate Change There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation. At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide GHG emissions by 26 to 28 percent below 2005 levels by 2025. In 2015, FirstEnergy set a goal of reducing company-wide CO2 emissions by at least 90 percent below 2005 levels by 2045. As of December 31, 2018, FirstEnergy has reduced its CO2 emissions by approximately 62 percent. In September 2016, the U.S. joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHG under the Clean Air Act,” concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally Clean Water Act the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. The EPA released its final CPP regulations in August 2015 to reduce CO2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. To replace the CPP, the EPA proposed the ACE rule on August 21, 2018, which would establish emission guidelines for states to develop plans to address GHG emissions from existing coal-fired power plants. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that establishes guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired power plants. Depending on the outcomes of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material. Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material. On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations phase-in as permits are renewed on a five-year cycle from 2018 to 2023. On April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On November 4, 2019, the EPA issued a proposed rule revising the effluent limits for discharges from wet scrubber systems and extending the deadline for compliance to December 31, 2025. The EPA’s proposed rule retains the zero discharge standard and 2023 compliance date for ash transport water, but adds some allowances for discharge under certain circumstances. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's operations may result. On September 29, 2016, FirstEnergy received a request from the EPA for information pursuant to CWA Section 308(a) for information concerning boron exceedances of effluent limitations established in the NPDES Permit for the former Mitchell Power Station’s Mingo landfill, owned by WP. On November 1, 2016, WP provided an initial response that contained information related to a similar boron issue at the former Springdale Power Station’s landfill. The EPA requested additional information regarding the Springdale landfill and on November 15, 2016, WP provided a response and intends to fully comply with the Section 308(a) information request. On March 3, 2017, WP proposed to the PA DEP a re-route of its wastewater discharge to eliminate potential boron exceedances at the Springdale landfill. On January 29, 2018, WP submitted an NPDES permit renewal application to PA DEP proposing to re-route its wastewater discharge to eliminate potential boron exceedances at the Mingo landfill. On February 20, 2018, the DOJ issued a letter and tolling agreement on behalf of EPA alleging violations of the CWA at the Mingo landfill while seeking to enter settlement negotiations in lieu of filing a complaint. On November 4, 2019, the EPA proposed a penalty of nearly $1.3 million to settle alleged past boron exceedances at the Mingo and Springdale landfills. On December 17, 2019, WP responded to the EPA's settlement proposal but is unable to predict the outcome of this matter. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 17, 2018, the EPA Administrator signed a final rule extending the deadline for certain CCR facilities to cease disposal and commence closure activities, as well as, establishing less stringent groundwater monitoring and protection requirements. On August 21, 2018, the D.C. Circuit remanded sections of the CCR Rule to the EPA to provide additional safeguards for unlined CCR impoundments that are more protective of human health and the environment. On November 4, 2019, the EPA issued a proposed rule accelerating the 39 40 date that certain CCR impoundments must cease accepting waste and initiate closure to August 31, 2020. The proposed rule, which includes a 60-day comment period, provides exceptions, which could allow extensions to closure dates. Revenue Recognition FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 2019, based on estimates of the total costs of cleanup, FirstEnergy's proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $109 million have been accrued through December 31, 2019. Included in the total are accrued liabilities of approximately $77 million for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time. OTHER LEGAL PROCEEDINGS Nuclear Plant Matters Under NRC regulations, JCP&L, ME and PN must ensure that adequate funds will be available to decommission their retired nuclear facility, TMI-2. As of December 31, 2019, JCP&L, ME and PN had in total approximately $882 million invested in external trusts to be used for the decommissioning and environmental remediation of their retired TMI-2 nuclear generating facility. The values of these NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, the obligation to JCP&L, ME and PN to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs. On October 15, 2019, JCP&L, ME, PN and GPUN executed an asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of EnergySolutions, LLC, concerning the transfer and dismantlement of TMI-2. This transfer of TMI-2 to TMI-2 Solutions, LLC will include the transfer of: (i) the ownership and operating NRC licenses for TMI-2; (ii) the external trusts for the decommissioning and environmental remediation of TMI-2; and (iii) related liabilities of approximately $900 million as of December 31, 2019. There can be no assurance that the transfer will receive the required regulatory approvals and, even if approved, whether the conditions to the closing of the transfer will be satisfied. On November 12, 2019, JCP&L filed a Petition with the NJBPU seeking approval of the transfer and sale of JCP&L’s entire 25% interest in TMI-2 to TMI-2 Solutions, LLC. Also on November 12, 2019, JCP&L, ME, PN, GPUN and TMI-2 Solutions, LLC filed an application with the NRC seeking approval to transfer the NRC license for TMI-2 to TMI-2 Solutions, LLC. Both proceedings are ongoing. FES Bankruptcy FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales and revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, applicable billing demands, weather-related impacts, number of days unbilled and tariff rates in effect within each customer class. In connection with adopting the new revenue recognition guidance in 2018, FirstEnergy has elected the optional invoice practical expedient for most of its revenues and, with the exception of JCP&L transmission revenues, utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations. See Note 2, "Revenue," for additional information. Regulatory Accounting FirstEnergy’s Regulated Distribution and Regulated Transmission segments are subject to regulations that set the prices (rates) the Utilities and the Transmission Companies are permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows. Management applies judgment in evaluating the evidence available to assess the probability of recovery of regulatory assets from customers, including, but not limited to evaluating evidence related to precedent for similar items experienced at the Company and comparable companies within similar jurisdictions, as well as assessing progress of communications between the Company and regulators. Certain regulatory assets are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific rate order. FirstEnergy regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. See Note 14, "Regulatory Matters," for additional information. FirstEnergy reviews the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur. Similarly, FirstEnergy records regulatory liabilities when a determination is made that a refund is probable or when ordered by a commission. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. If recovery of a regulatory asset is no longer probable, FirstEnergy will write off that regulatory asset as a charge against earnings. FirstEnergy considers the entire regulatory asset balance as the unit of account for the purposes of balance sheet classification rather than the next years recovery and as such net regulatory assets and liabilities are presented in the non-current section on the FirstEnergy Consolidated Balance Sheets. On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FGMUC, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. See Note 3, "Discontinued Operations," for additional information. Pension and OPEB Accounting FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non- qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 14, "Regulatory Matters." FirstEnergy provides some non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits and/or subsidies to purchase health insurance, which include certain employee contributions, deductibles and co-payments, may also be available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related levels. benefits. FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE's or its subsidiaries' financial condition, results of operations and cash flows. CRITICAL ACCOUNTING POLICIES AND ESTIMATES FirstEnergy prepares consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. FirstEnergy's accounting policies require significant judgment regarding estimates and assumptions underlying the amounts included in the financial statements. Additional information regarding the application of accounting policies is included in the Notes to Consolidated Financial Statements. FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The remaining components of pension and OPEB expense, primarily service costs, interest on obligations, assumed return on assets and prior service costs, are recorded on a monthly basis. The pre-tax pension and OPEB mark-to-market adjustment charged to earnings for the years ended December 31, 2019, 2018, and 2017, were $676 million, $145 million, and $141 million, respectively, of these amounts, approximately $2 million, $1 million, and $39 million are included in discontinued operations. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed discount rates for pension were 3.34%, 4.44% and 3.75% as of December 31, 2019, 2018 and 2017, respectively. The assumed discount rates for OPEB were 3.18%, 4.30% and 3.50% as of December 31, 2019, 2018 and 2017, respectively. Effective in 2019, FirstEnergy changed the approach utilized to estimate the service cost and interest cost components of net periodic benefit cost for pension and OPEB plans. Historically, FirstEnergy estimated these components utilizing a single, weighted average discount rate derived from the yield curve used to measure the benefit obligation. FirstEnergy has elected to use a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the 41 42 date that certain CCR impoundments must cease accepting waste and initiate closure to August 31, 2020. The proposed rule, which Revenue Recognition includes a 60-day comment period, provides exceptions, which could allow extensions to closure dates. FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 2019, based on estimates of the total costs of cleanup, FirstEnergy's proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $109 million have been accrued through December 31, 2019. Included in the total are accrued liabilities of approximately $77 million for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time. OTHER LEGAL PROCEEDINGS Nuclear Plant Matters Under NRC regulations, JCP&L, ME and PN must ensure that adequate funds will be available to decommission their retired nuclear facility, TMI-2. As of December 31, 2019, JCP&L, ME and PN had in total approximately $882 million invested in external trusts to be used for the decommissioning and environmental remediation of their retired TMI-2 nuclear generating facility. The values of these NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, the obligation to JCP&L, ME and PN to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs. On October 15, 2019, JCP&L, ME, PN and GPUN executed an asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of EnergySolutions, LLC, concerning the transfer and dismantlement of TMI-2. This transfer of TMI-2 to TMI-2 Solutions, LLC will include the transfer of: (i) the ownership and operating NRC licenses for TMI-2; (ii) the external trusts for the decommissioning and environmental remediation of TMI-2; and (iii) related liabilities of approximately $900 million as of December 31, 2019. There can be no assurance that the transfer will receive the required regulatory approvals and, even if approved, whether the conditions to the closing of the transfer will be satisfied. On November 12, 2019, JCP&L filed a Petition with the NJBPU seeking approval of the transfer and sale of JCP&L’s entire 25% interest in TMI-2 to TMI-2 Solutions, LLC. Also on November 12, 2019, JCP&L, ME, PN, GPUN and TMI-2 Solutions, LLC filed an application with the NRC seeking approval to transfer the NRC license for TMI-2 to TMI-2 Solutions, LLC. Both proceedings are ongoing. On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FGMUC, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. See Note 3, "Discontinued Operations," for additional information. FES Bankruptcy Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 14, "Regulatory Matters." FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE's or its subsidiaries' financial condition, results of operations and cash flows. CRITICAL ACCOUNTING POLICIES AND ESTIMATES FirstEnergy prepares consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. FirstEnergy's accounting policies require significant judgment regarding estimates and assumptions underlying the amounts included in the financial statements. Additional information regarding the application of accounting policies is included in the Notes to Consolidated Financial Statements. FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales and revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, applicable billing demands, weather-related impacts, number of days unbilled and tariff rates in effect within each customer class. In connection with adopting the new revenue recognition guidance in 2018, FirstEnergy has elected the optional invoice practical expedient for most of its revenues and, with the exception of JCP&L transmission revenues, utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations. See Note 2, "Revenue," for additional information. Regulatory Accounting FirstEnergy’s Regulated Distribution and Regulated Transmission segments are subject to regulations that set the prices (rates) the Utilities and the Transmission Companies are permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows. Management applies judgment in evaluating the evidence available to assess the probability of recovery of regulatory assets from customers, including, but not limited to evaluating evidence related to precedent for similar items experienced at the Company and comparable companies within similar jurisdictions, as well as assessing progress of communications between the Company and regulators. Certain regulatory assets are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific rate order. FirstEnergy regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. See Note 14, "Regulatory Matters," for additional information. FirstEnergy reviews the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur. Similarly, FirstEnergy records regulatory liabilities when a determination is made that a refund is probable or when ordered by a commission. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. If recovery of a regulatory asset is no longer probable, FirstEnergy will write off that regulatory asset as a charge against earnings. FirstEnergy considers the entire regulatory asset balance as the unit of account for the purposes of balance sheet classification rather than the next years recovery and as such net regulatory assets and liabilities are presented in the non-current section on the FirstEnergy Consolidated Balance Sheets. Pension and OPEB Accounting FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non- qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. FirstEnergy provides some non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits and/or subsidies to purchase health insurance, which include certain employee contributions, deductibles and co-payments, may also be available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits. FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The remaining components of pension and OPEB expense, primarily service costs, interest on obligations, assumed return on assets and prior service costs, are recorded on a monthly basis. The pre-tax pension and OPEB mark-to-market adjustment charged to earnings for the years ended December 31, 2019, 2018, and 2017, were $676 million, $145 million, and $141 million, respectively, of these amounts, approximately $2 million, $1 million, and $39 million are included in discontinued operations. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed discount rates for pension were 3.34%, 4.44% and 3.75% as of December 31, 2019, 2018 and 2017, respectively. The assumed discount rates for OPEB were 3.18%, 4.30% and 3.50% as of December 31, 2019, 2018 and 2017, respectively. Effective in 2019, FirstEnergy changed the approach utilized to estimate the service cost and interest cost components of net periodic benefit cost for pension and OPEB plans. Historically, FirstEnergy estimated these components utilizing a single, weighted average discount rate derived from the yield curve used to measure the benefit obligation. FirstEnergy has elected to use a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the 41 42 relevant projected cash flows, as this provides a better estimate of service and interest costs by improving the correlation between projected benefit cash flows to the corresponding spot yield curve rates. This election is considered a change in estimate and, accordingly, accounted for prospectively, and did not have a material impact on FirstEnergy's financial statements. FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2019, FirstEnergy’s qualified pension and OPEB plan assets experienced gains of $1,492 million or 20.2%, compared to losses of $371 million, or (4)% in 2018, and gains of $999 million, or 15.1% in 2017 and assumed a 7.50% rate of return on plan assets in 2019, 2018 and 2017, which generated $569 million, $605 million and $478 million of expected returns on plan assets, respectively. The expected return on pension and OPEB assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets will decrease or increase future net periodic pension and OPEB cost as the difference is recognized annually in the fourth quarter of each fiscal year or whenever a plan is determined to qualify for remeasurement. The expected return on plan assets for 2020 is 7.50%. During 2019, the Society of Actuaries published new mortality tables that include more current data than the RP-2014 tables as well as new improvement scales. An analysis of FirstEnergy pension and OPEB plan mortality data indicated the use of the Pri-2012 mortality table with projection scale MP-2019 was most appropriate. As such, the Pri-2012 mortality table with projection scale MP-2019 was utilized to determine the 2019 benefit cost and obligation as of December 31, 2019 for the FirstEnergy pension and OPEB plans. The impact of using the Pri-2012 mortality table with projection scale MP-2019 resulted in a decrease to the projected benefit obligation approximately $29 million and $3 million for the pension and OPEB plans, respectively, and was included in the 2019 pension and OPEB mark-to-market adjustment. Based on discount rates of 3.34% for pension, 3.18% for OPEB and an estimated return on assets of 7.50%, FirstEnergy expects its 2020 pre-tax net periodic benefit credit to be approximately $108 million (excluding any actuarial mark-to-market adjustments that would be recognized in 2020 or impacts resulting from FES' emergence from bankruptcy). Upon the FES Debtors' emergence from bankruptcy, FirstEnergy will perform a remeasurement of the pension and OPEB plans. Assuming an emergence in the first quarter of 2020, FirstEnergy anticipates an after-tax mark-to-market loss to be up to $400 million assuming a discount rate of approximately 3.10% to 3.35% and a return on the pension and OPEB plans’ assets based on actual investment performance through January 31, 2020. The following table reflects the portion of pension and OPEB costs that were charged to expense, including any pension and OPEB mark-to-market adjustments, in the three years ended December 31, 2019, 2018, and 2017: Postemployment Benefits Expense (Credits) 2019 2018 2017 Pension OPEB Total (In millions) 622 $ 200 $ (21) 601 $ (158) 42 $ $ $ 247 (45) 202 Health care cost trends continue to increase and will affect future OPEB costs. The composite health care trend rate assumptions were approximately 6.0-5.5% in 2019 and 2018, gradually decreasing to 4.5% in later years. In determining FirstEnergy’s trend rate assumptions, included are the specific provisions of FirstEnergy’s health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in FirstEnergy’s health care plans, and projections of future medical trend rates. The effects on 2020 pension and OPEB net periodic benefit costs from changes in key assumptions are as follows: Increase in Net Periodic Benefit Costs from Adverse Changes in Key Assumptions Assumption Adverse Change Pension OPEB Total (In millions) Discount rate Decrease by 0.25% Long-term return on assets Decrease by 0.25% $ $ Health care trend rate Increase by 1.0% 360 20 $ $ N/A $ 16 1 20 $ $ $ 376 21 20 and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. FirstEnergy accounts for uncertainty in income taxes in its financial statements using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. FirstEnergy recognizes interest expense or income related to uncertain tax positions by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken, or expected to be taken, on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. See Note 7, "Taxes," for additional information on FirstEnergy income taxes. NEW ACCOUNTING PRONOUNCEMENTS ASU 2016-02, "Leases (Topic 842)" (Issued February 2016 and subsequently updated to address implementation questions): The new guidance requires organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets, as well as new qualitative and quantitative disclosures. FirstEnergy implemented a third-party software tool that assisted with the initial adoption and will assist with ongoing compliance. FirstEnergy chose to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Upon adoption, on January 1, 2019, FirstEnergy increased assets and liabilities by $186 million, with no impact to results of operations or cash flows. See Note 8, "Leases," for additional information on FirstEnergy's leases. Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (issued June 2016 and subsequently updated): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for expected credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. FirstEnergy has analyzed its financial instruments within the scope of this guidance, primarily trade receivables, AFS debt securities and certain third-party guarantees and does not expect a material impact to its financial statements upon adoption in 2020. ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" (Issued August 2018): ASU 2018-15 requires implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. FirstEnergy does not expect a material impact to its financial statements upon adoption in 2020. ASU 2019-12, "Simplifying the Accounting for Income Taxes" (Issued in December 2019): ASU 2019-12 enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information relating to market risk is set forth in "Management's Discussion and Analysis of Financial Condition and Results of See Note 5, "Pension and Other Postemployment Benefits," for additional information. Operations." Income Taxes FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences 43 44 accordingly, accounted for prospectively, and did not have a material impact on FirstEnergy's financial statements. FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2019, FirstEnergy’s qualified pension and OPEB plan assets experienced gains of $1,492 million or 20.2%, compared to losses of $371 million, or (4)% in 2018, and gains of $999 million, or 15.1% in 2017 and assumed a 7.50% rate of return on plan assets in 2019, 2018 and 2017, which generated $569 million, $605 million and $478 million of expected returns on plan assets, respectively. The expected return on pension and OPEB assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets will decrease or increase future net periodic pension and OPEB cost as the difference is recognized annually in the fourth quarter of each fiscal year or whenever a plan is determined well as new improvement scales. An analysis of FirstEnergy pension and OPEB plan mortality data indicated the use of the Pri-2012 mortality table with projection scale MP-2019 was most appropriate. As such, the Pri-2012 mortality table with projection scale MP-2019 was utilized to determine the 2019 benefit cost and obligation as of December 31, 2019 for the FirstEnergy pension and OPEB plans. The impact of using the Pri-2012 mortality table with projection scale MP-2019 resulted in a decrease to the projected benefit obligation approximately $29 million and $3 million for the pension and OPEB plans, respectively, and was included in the 2019 pension and OPEB mark-to-market adjustment. Based on discount rates of 3.34% for pension, 3.18% for OPEB and an estimated return on assets of 7.50%, FirstEnergy expects its 2020 pre-tax net periodic benefit credit to be approximately $108 million (excluding any actuarial mark-to-market adjustments that would be recognized in 2020 or impacts resulting from FES' emergence from bankruptcy). Upon the FES Debtors' emergence from bankruptcy, FirstEnergy will perform a remeasurement of the pension and OPEB plans. Assuming an emergence in the first quarter of 2020, FirstEnergy anticipates an after-tax mark-to-market loss to be up to $400 million assuming a discount rate of approximately 3.10% to 3.35% and a return on the pension and OPEB plans’ assets based on actual investment performance through January 31, 2020. The following table reflects the portion of pension and OPEB costs that were charged to expense, including any pension and OPEB mark-to-market adjustments, in the three years ended December 31, 2019, 2018, and 2017: Postemployment Benefits Expense (Credits) 2019 2018 2017 Pension OPEB Total (In millions) 622 $ 200 $ (21) 601 $ (158) 42 $ 247 (45) 202 Health care cost trends continue to increase and will affect future OPEB costs. The composite health care trend rate assumptions were approximately 6.0-5.5% in 2019 and 2018, gradually decreasing to 4.5% in later years. In determining FirstEnergy’s trend rate assumptions, included are the specific provisions of FirstEnergy’s health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in FirstEnergy’s health care plans, and projections of future medical trend rates. The effects on 2020 pension and OPEB net periodic benefit costs from changes in key assumptions are as follows: Increase in Net Periodic Benefit Costs from Adverse Changes in Key Assumptions Assumption Adverse Change Pension OPEB Total Discount rate Decrease by 0.25% Long-term return on assets Decrease by 0.25% Health care trend rate Increase by 1.0% (In millions) 360 20 $ $ N/A $ 16 1 20 $ $ $ 376 21 20 $ $ $ $ See Note 5, "Pension and Other Postemployment Benefits," for additional information. Income Taxes FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences relevant projected cash flows, as this provides a better estimate of service and interest costs by improving the correlation between projected benefit cash flows to the corresponding spot yield curve rates. This election is considered a change in estimate and, and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. FirstEnergy accounts for uncertainty in income taxes in its financial statements using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. FirstEnergy recognizes interest expense or income related to uncertain tax positions by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken, or expected to be taken, on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. to qualify for remeasurement. The expected return on plan assets for 2020 is 7.50%. See Note 7, "Taxes," for additional information on FirstEnergy income taxes. During 2019, the Society of Actuaries published new mortality tables that include more current data than the RP-2014 tables as NEW ACCOUNTING PRONOUNCEMENTS ASU 2016-02, "Leases (Topic 842)" (Issued February 2016 and subsequently updated to address implementation questions): The new guidance requires organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets, as well as new qualitative and quantitative disclosures. FirstEnergy implemented a third-party software tool that assisted with the initial adoption and will assist with ongoing compliance. FirstEnergy chose to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Upon adoption, on January 1, 2019, FirstEnergy increased assets and liabilities by $186 million, with no impact to results of operations or cash flows. See Note 8, "Leases," for additional information on FirstEnergy's leases. Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (issued June 2016 and subsequently updated): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for expected credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. FirstEnergy has analyzed its financial instruments within the scope of this guidance, primarily trade receivables, AFS debt securities and certain third-party guarantees and does not expect a material impact to its financial statements upon adoption in 2020. ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" (Issued August 2018): ASU 2018-15 requires implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. FirstEnergy does not expect a material impact to its financial statements upon adoption in 2020. ASU 2019-12, "Simplifying the Accounting for Income Taxes" (Issued in December 2019): ASU 2019-12 enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information relating to market risk is set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operations." 43 44 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Report of Independent Registered Public Accounting Firm Management’s Report on Internal Control Over Financial Reporting To the Stockholders and Board of Directors of FirstEnergy Corp. Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework published in 2013, management conducted an evaluation of the effectiveness of their internal control over financial reporting under the supervision of the chief executive officer and chief financial officer. Based on that evaluation, management concluded that FirstEnergy's internal control over financial reporting was effective as of December 31, 2019. The effectiveness of FirstEnergy’s internal control over financial reporting, as of December 31, 2019, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included herein. Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the accompanying consolidated balance sheets of FirstEnergy Corp. and its subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of income (loss), of comprehensive income (loss), of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2019, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. Basis for Opinions The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken 45 46 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Report of Independent Registered Public Accounting Firm Management’s Report on Internal Control Over Financial Reporting To the Stockholders and Board of Directors of FirstEnergy Corp. Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework published in 2013, management conducted an evaluation of the effectiveness of their internal control over financial reporting under the supervision of the chief executive officer and chief financial officer. Based on that evaluation, management concluded that FirstEnergy's internal control over financial reporting was effective as of December 31, 2019. The effectiveness of FirstEnergy’s internal control over financial reporting, as of December 31, 2019, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included herein. Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the accompanying consolidated balance sheets of FirstEnergy Corp. and its subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of income (loss), of comprehensive income (loss), of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2019, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. Basis for Opinions The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken 45 46 as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME (LOSS) Recoverability of Regulatory Assets That Do Not Have an Order for Recovery As described in Note 1 to the consolidated financial statements, the Company accounts for the effects of regulation through the application of regulatory accounting to its regulated distribution and transmission subsidiaries as their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be charged to and collected from customers. This ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows. Management assesses the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Management applies judgment in evaluating the evidence available to assess the probability of recovery of regulatory assets from customers and certain of these assets, totaling approximately $111 million as of December 31, 2019, have been recorded based on precedent and rate making premises without a specific order. The principal considerations for our determination that performing procedures relating to the Company’s recoverability of regulatory assets that do not have an order for recovery is a critical audit matter are there was significant judgment by management when assessing the probability of recovery of these regulatory assets from customers. This led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the recoverability of these regulatory assets. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the Company’s regulatory accounting process, including controls over management’s assessment of the recoverability of regulatory assets that do not have an order for recovery. These procedures also included evaluating the reasonableness of management’s assessment of recoverability of regulatory assets which involved evaluating evidence related to precedent for similar items at the Company and information on comparable companies within similar regulatory jurisdictions as well as assessing progress of communications between management and regulators. /s/ PricewaterhouseCoopers LLP Cleveland, Ohio February 10, 2020 We have served as the Company’s auditor since 2002. Amortization (deferral) of regulatory assets, net (In millions, except per share amounts) REVENUES: Distribution services and retail generation Transmission Other Total revenues(1) OPERATING EXPENSES: Fuel Purchased power Other operating expenses Provision for depreciation General taxes Total operating expenses OPERATING INCOME OTHER INCOME (EXPENSE): Miscellaneous income, net Interest expense Capitalized financing costs Total other expense Pension and OPEB mark-to-market adjustment INCOME (LOSS) FROM CONTINUING OPERATIONS INCOME BEFORE INCOME TAXES INCOME TAXES Discontinued operations (Note 3)(2) NET INCOME (LOSS) For the Years Ended December 31, 2019 2018 2017 $ $ $ 8,720 1,510 805 11,035 497 2,927 2,952 1,220 (79) 1,008 8,525 2,510 243 (674) (1,033) 71 (1,393) 1,117 213 904 8 4 1.69 0.01 1.70 1.67 0.01 1.68 535 542 $ $ $ $ $ $ 8,937 1,335 989 11,261 538 3,109 3,133 1,136 (150) 993 8,759 2,502 205 (144) (1,116) 65 (990) 1,512 490 1,022 326 $ $ $ $ $ $ $ $ 1.33 0.66 1.99 1.33 0.66 1.99 492 494 8,685 1,307 936 10,928 497 2,926 2,802 1,027 308 940 8,500 2,428 53 (102) (1,005) 52 (1,002) 1,426 1,715 (289) (1,435) (0.65) (3.23) (3.88) (0.65) (3.23) (3.88) 444 444 INCOME ALLOCATED TO PREFERRED STOCKHOLDERS (Note 1) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS 908 $ 981 $ (1,724) 912 $ 1,348 $ (1,724) 367 — EARNINGS (LOSS) PER SHARE OF COMMON STOCK: Basic - Continuing Operations Basic - Discontinued Operations Basic - Net Income (Loss) Attributable to Common Stockholders Diluted - Continuing Operations Diluted - Discontinued Operations Diluted - Net Income (Loss) Attributable to Common Stockholders WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: Basic Diluted (1) Includes excise and gross receipts tax collections of $373 million, $386 million and $370 million in 2019, 2018 and 2017, respectively. (2) Net of income tax benefit of $5 million, $1,251 million, and $820 million in 2019, 2018 and 2017, respectively. The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. 47 48 as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME (LOSS) Recoverability of Regulatory Assets That Do Not Have an Order for Recovery As described in Note 1 to the consolidated financial statements, the Company accounts for the effects of regulation through the application of regulatory accounting to its regulated distribution and transmission subsidiaries as their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be charged to and collected from customers. This ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows. Management assesses the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Management applies judgment in evaluating the evidence available to assess the probability of recovery of regulatory assets from customers and certain of these assets, totaling approximately $111 million as of December 31, 2019, have been recorded based on precedent and rate making premises without a specific order. The principal considerations for our determination that performing procedures relating to the Company’s recoverability of regulatory assets that do not have an order for recovery is a critical audit matter are there was significant judgment by management when assessing the probability of recovery of these regulatory assets from customers. This led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the recoverability of these regulatory assets. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the Company’s regulatory accounting process, including controls over management’s assessment of the recoverability of regulatory assets that do not have an order for recovery. These procedures also included evaluating the reasonableness of management’s assessment of recoverability of regulatory assets which involved evaluating evidence related to precedent for similar items at the Company and information on comparable companies within similar regulatory jurisdictions as well as assessing progress of communications between management and regulators. /s/ PricewaterhouseCoopers LLP Cleveland, Ohio February 10, 2020 We have served as the Company’s auditor since 2002. (In millions, except per share amounts) REVENUES: Distribution services and retail generation Transmission Other Total revenues(1) OPERATING EXPENSES: Fuel Purchased power Other operating expenses Provision for depreciation Amortization (deferral) of regulatory assets, net General taxes Total operating expenses OPERATING INCOME OTHER INCOME (EXPENSE): Miscellaneous income, net Pension and OPEB mark-to-market adjustment Interest expense Capitalized financing costs Total other expense INCOME BEFORE INCOME TAXES INCOME TAXES INCOME (LOSS) FROM CONTINUING OPERATIONS Discontinued operations (Note 3)(2) NET INCOME (LOSS) INCOME ALLOCATED TO PREFERRED STOCKHOLDERS (Note 1) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS EARNINGS (LOSS) PER SHARE OF COMMON STOCK: Basic - Continuing Operations Basic - Discontinued Operations Basic - Net Income (Loss) Attributable to Common Stockholders Diluted - Continuing Operations Diluted - Discontinued Operations Diluted - Net Income (Loss) Attributable to Common Stockholders WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: Basic Diluted For the Years Ended December 31, 2017 2018 2019 $ $ 8,720 1,510 805 11,035 $ 8,937 1,335 989 11,261 8,685 1,307 936 10,928 497 2,927 2,952 1,220 (79) 1,008 8,525 2,510 243 (674) (1,033) 71 (1,393) 1,117 213 904 8 538 3,109 3,133 1,136 (150) 993 8,759 2,502 205 (144) (1,116) 65 (990) 1,512 490 1,022 326 497 2,926 2,802 1,027 308 940 8,500 2,428 53 (102) (1,005) 52 (1,002) 1,426 1,715 (289) (1,435) $ $ $ $ $ $ 912 $ 1,348 $ (1,724) 4 367 — 908 $ 981 $ (1,724) $ $ $ $ 1.69 0.01 1.70 1.67 0.01 1.68 535 542 $ $ $ $ 1.33 0.66 1.99 1.33 0.66 1.99 492 494 (0.65) (3.23) (3.88) (0.65) (3.23) (3.88) 444 444 (1) Includes excise and gross receipts tax collections of $373 million, $386 million and $370 million in 2019, 2018 and 2017, respectively. (2) Net of income tax benefit of $5 million, $1,251 million, and $820 million in 2019, 2018 and 2017, respectively. The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. 47 48 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS (In millions) NET INCOME (LOSS) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs Amortized losses on derivative hedges Change in unrealized gains on available-for-sale securities Other comprehensive loss Income tax benefits on other comprehensive loss Other comprehensive loss, net of tax For the Years Ended December 31, 2019 2018 2017 $ 912 $ 1,348 $ (1,724) (In millions, except share amounts) ASSETS CURRENT ASSETS: Cash and cash equivalents Restricted cash Receivables- December 31, December 31, 2019 2018 $ $ 627 52 (31) 2 — (29) (8) (21) (83) 21 (106) (168) (67) (101) (85) 10 22 (53) (21) (32) Customers, net of allowance for uncollectible accounts of $46 in 2019 and $50 in 2018 Affiliated companies, net of allowance for uncollectible accounts of $1,063 in 2019 and $920 in 2018 Other, net of allowance for uncollectible accounts of $21 in 2019 and $2 in 2018 COMPREHENSIVE INCOME (LOSS) $ 891 $ 1,247 $ (1,756) The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. Materials and supplies, at average cost Prepaid taxes and other Current assets - discontinued operations PROPERTY, PLANT AND EQUIPMENT: In service Less — Accumulated provision for depreciation Construction work in progress INVESTMENTS: Nuclear plant decommissioning trusts Nuclear fuel disposal trust Other Investments - held for sale (Note 15) DEFERRED CHARGES AND OTHER ASSETS: Goodwill Regulatory assets Other CURRENT LIABILITIES: Currently payable long-term debt Short-term borrowings Accounts payable Accounts payable - affiliated companies Accrued interest Accrued taxes Other Accrued compensation and benefits CAPITALIZATION: Stockholders’ equity- outstanding as of December 31, 2018 Other paid-in capital Accumulated other comprehensive income Accumulated deficit Total stockholders' equity Long-term debt and other long-term obligations NONCURRENT LIABILITIES: Accumulated deferred income taxes Retirement benefits Regulatory liabilities Asset retirement obligations Adverse power contract liability Other Noncurrent liabilities - held for sale (Note 15) LIABILITIES AND CAPITALIZATION $ $ Common stock, $0.10 par value, authorized 700,000,000 shares - 540,652,222 and 511,915,450 shares outstanding as of December 31, 2019 and December 31, 2018, respectively Preferred stock, $100 par value, authorized 5,000,000 shares, of which 1,616,000 are designated Series A Convertible Preferred - none outstanding as of December 31, 2019, and 704,589 shares 1,221 367 62 20 270 252 175 25 2,392 39,469 10,793 28,676 1,235 29,911 790 256 253 — 1,299 5,618 91 752 6,461 40,063 503 1,250 965 — 243 533 318 822 4,634 51 71 41 11,530 (4,879) 6,814 17,751 24,565 2,502 2,906 2,498 812 89 2,057 — 10,864 1,091 — 203 281 157 33 2,444 41,767 11,427 30,340 1,310 31,650 — 270 299 882 1,451 5,618 99 1,039 6,756 42,301 $ 380 1,000 $ 918 87 249 545 258 1,425 4,862 54 — 20 10,868 (3,967) 6,975 19,618 26,593 2,849 3,065 2,360 165 49 1,667 691 10,846 COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 15) $ 42,301 $ 40,063 The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. 49 50 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) FIRSTENERGY CORP. FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS For the Years Ended December 31, 2019 2018 2017 $ 912 $ 1,348 $ (1,724) (In millions, except share amounts) ASSETS CURRENT ASSETS: Cash and cash equivalents Restricted cash Receivables- Customers, net of allowance for uncollectible accounts of $46 in 2019 and $50 in 2018 Affiliated companies, net of allowance for uncollectible accounts of $1,063 in 2019 and $920 in 2018 Other, net of allowance for uncollectible accounts of $21 in 2019 and $2 in 2018 December 31, 2019 December 31, 2018 $ $ 627 52 (In millions) NET INCOME (LOSS) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs Amortized losses on derivative hedges Change in unrealized gains on available-for-sale securities Other comprehensive loss Income tax benefits on other comprehensive loss Other comprehensive loss, net of tax (31) 2 — (29) (8) (21) (83) 21 (106) (168) (67) (101) (85) 10 22 (53) (21) (32) COMPREHENSIVE INCOME (LOSS) $ 891 $ 1,247 $ (1,756) The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. Materials and supplies, at average cost Prepaid taxes and other Current assets - discontinued operations PROPERTY, PLANT AND EQUIPMENT: In service Less — Accumulated provision for depreciation Construction work in progress INVESTMENTS: Nuclear plant decommissioning trusts Nuclear fuel disposal trust Other Investments - held for sale (Note 15) DEFERRED CHARGES AND OTHER ASSETS: Goodwill Regulatory assets Other $ $ LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt Short-term borrowings Accounts payable Accounts payable - affiliated companies Accrued interest Accrued taxes Accrued compensation and benefits Other CAPITALIZATION: Stockholders’ equity- Common stock, $0.10 par value, authorized 700,000,000 shares - 540,652,222 and 511,915,450 shares outstanding as of December 31, 2019 and December 31, 2018, respectively Preferred stock, $100 par value, authorized 5,000,000 shares, of which 1,616,000 are designated Series A Convertible Preferred - none outstanding as of December 31, 2019, and 704,589 shares outstanding as of December 31, 2018 Other paid-in capital Accumulated other comprehensive income Accumulated deficit Total stockholders' equity Long-term debt and other long-term obligations NONCURRENT LIABILITIES: Accumulated deferred income taxes Retirement benefits Regulatory liabilities Asset retirement obligations Adverse power contract liability Other Noncurrent liabilities - held for sale (Note 15) 367 62 1,221 20 270 252 175 25 2,392 39,469 10,793 28,676 1,235 29,911 790 256 253 — 1,299 5,618 91 752 6,461 40,063 503 1,250 965 — 243 533 318 822 4,634 51 71 11,530 41 (4,879) 6,814 17,751 24,565 2,502 2,906 2,498 812 89 2,057 — 10,864 $ $ 1,091 — 203 281 157 33 2,444 41,767 11,427 30,340 1,310 31,650 — 270 299 882 1,451 5,618 99 1,039 6,756 42,301 380 1,000 918 87 249 545 258 1,425 4,862 54 — 10,868 20 (3,967) 6,975 19,618 26,593 2,849 3,065 2,360 165 49 1,667 691 10,846 COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 15) $ 42,301 $ 40,063 The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. 49 50 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS Series A Convertible Preferred Stock Common Stock (In millions) Shares Amount Shares Amount OPIC AOCI Accumulated Deficit Total Stockholders' Equity Balance, January 1, 2017 — $ — 442 $ 44 $ 10,555 $ 174 $ (4,532) $ Net loss Other comprehensive loss, net of tax Stock-based compensation Cash dividends declared on common stock Stock Investment Plan and certain share-based benefit plans Reclass to liability awards Share-based compensation accounting change (1,724) (32) 3 36 (639) 56 (7) Balance, December 31, 2017 — — 445 44 10,001 142 Net income Other comprehensive loss, net of tax Stock-based compensation Cash dividends declared on common stock Cash dividends declared on preferred stock Stock Investment Plan and certain share-based benefit plans Stock issuance (Note 11)(1) Conversion of Series A Convertible Stock (Note 11) Impact of adopting new accounting pronouncements (101) 60 (906) (71) 61 2,297 88 1.6 (0.9) 162 (91) 4 30 33 1 3 3 Balance, December 31, 2018 0.7 71 512 51 11,530 41 Net income Other comprehensive loss, net of tax Stock-based compensation Cash dividends declared on common stock Cash dividends declared on preferred stock Stock Investment Plan and certain share-based benefit plans Conversion of Series A Convertible Stock (Note 11) (21) 41 (824) (3) 56 68 (0.7) (71) 3 26 3 (6) (6,262) 1,348 35 (4,879) 912 6,241 (1,724) (32) 36 (639) 56 (7) (6) 3,925 1,348 (101) 60 (906) (71) 62 2,462 — 35 6,814 912 (21) 41 (824) (3) 56 — Balance, December 31, 2019 — $ — 541 $ 54 $ 10,868 $ 20 $ (3,967) $ 6,975 (1) The Preferred Stock included an embedded conversion option at a price that is below the fair value of the Common Stock on the commitment date. This beneficial conversion feature (BCF), which was approximately $296 million, was recorded to OPIC as well as the amortization of the BCF (deemed dividend) through the period from the issue date to the first allowable conversion date (July 22, 2018) and as such there is no net impact to OPIC for the year ended December 31, 2018. See Note 1, "Organization and Basis of Presentation - Earnings per share," and Note 11, "Capitalization" for additional information on the BCF and the equity issuance. Dividends declared for each share of common stock and as-converted share of preferred stock was $1.53 during 2019, $1.82 during 2018, and $1.44 during 2017. The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. 51 52 Adjustments to reconcile net income (loss) to net cash from operating activities- Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt- (In millions) Net income (loss) CASH FLOWS FROM OPERATING ACTIVITIES: Gain on disposal, net of tax (Note 3) related costs Impairment of assets and related charges Pension trust contributions Retirement benefits, net of payments Pension and OPEB mark-to-market adjustment Deferred income taxes and investment tax credits, net Asset removal costs charged to income Unrealized (gain) loss on derivative transactions Gain on sale of investment securities held in trusts Changes in current assets and liabilities- Receivables Materials and supplies Prepaid taxes and other Accounts payable Accrued taxes Accrued interest Accrued compensation and benefits Other current liabilities Other Net cash provided from operating activities CASH FLOWS FROM FINANCING ACTIVITIES: New financing- Long-term debt Short-term borrowings, net Preferred stock issuance Common stock issuance Redemptions and repayments- Long-term debt Short-term borrowings, net Tender premiums paid on debt redemptions Preferred stock dividend payments Common stock dividend payments Other Net cash provided from (used for) financing activities CASH FLOWS FROM INVESTING ACTIVITIES: Property additions Nuclear fuel Proceeds from asset sales Sales of investment securities held in trusts Purchases of investment securities held in trusts Notes receivable from affiliated companies Asset removal costs Other Net cash used for investing activities For the Years Ended December 31, 2019 2018 2017 $ 912 $ 1,348 $ (1,724) (59) 1,217 — (500) (108) 676 252 28 — — 271 (37) 10 (49) 12 6 (60) (21) (83) 2,467 2,300 — — — — — (6) (814) (35) 656 — 47 1,637 (1,675) (217) — — (435) 1,384 — (1,250) (137) 144 485 42 (5) (9) (248) 24 (61) 109 — (25) 37 (121) 128 1,410 1,474 950 1,616 850 — (89) (61) (711) (27) 1,394 — 425 909 (963) (500) (218) 4 (789) (2,608) (2,665) (2,675) — 1,700 2,399 — 29 141 839 22 81 (63) (39) (6) 30 72 (9) 55 (27) (35) 343 3,808 4,675 — — — (2,291) (2,375) — — (639) (72) (702) (2,587) (254) 388 2,170 (2,268) (172) — — 383 260 643 — — Net change in cash, cash equivalents and restricted cash Cash, cash equivalents, and restricted cash at beginning of period Cash, cash equivalents, and restricted cash at end of period SUPPLEMENTAL CASH FLOW INFORMATION: Non-cash transaction: beneficial conversion feature (Note1) Non-cash transaction: deemed dividend convertible preferred stock (Note 1) Cash paid during the year- Interest (net of amounts capitalized) Income taxes, net of refunds (2,873) (3,018) (2,723) 250 429 679 $ (214) 643 429 $ — $ — $ 296 $ (296) $ 960 12 $ $ 1,071 49 $ $ 1,039 53 $ $ $ $ $ The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS Accumulated Stockholders' Total Equity CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) Adjustments to reconcile net income (loss) to net cash from operating activities- (In millions) Gain on disposal, net of tax (Note 3) Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt- related costs Impairment of assets and related charges Pension trust contributions Retirement benefits, net of payments Pension and OPEB mark-to-market adjustment Deferred income taxes and investment tax credits, net Asset removal costs charged to income Unrealized (gain) loss on derivative transactions Gain on sale of investment securities held in trusts Changes in current assets and liabilities- Receivables Materials and supplies Prepaid taxes and other Accounts payable Accrued taxes Accrued interest Accrued compensation and benefits Other current liabilities Other Net cash provided from operating activities CASH FLOWS FROM FINANCING ACTIVITIES: New financing- Long-term debt Short-term borrowings, net Preferred stock issuance Common stock issuance Redemptions and repayments- Long-term debt Short-term borrowings, net Tender premiums paid on debt redemptions Preferred stock dividend payments Common stock dividend payments Other Net cash provided from (used for) financing activities CASH FLOWS FROM INVESTING ACTIVITIES: Property additions Nuclear fuel Proceeds from asset sales Sales of investment securities held in trusts Purchases of investment securities held in trusts Notes receivable from affiliated companies Asset removal costs Other Net cash used for investing activities (0.7) (71) 3 Balance, December 31, 2019 — $ — 541 $ 54 $ 10,868 $ 20 $ (3,967) $ 6,975 (1) The Preferred Stock included an embedded conversion option at a price that is below the fair value of the Common Stock on the commitment date. This beneficial conversion feature (BCF), which was approximately $296 million, was recorded to OPIC as well as the amortization of the BCF (deemed dividend) through the period from the issue date to the first allowable conversion date (July 22, 2018) and as such there is no net impact to OPIC for the year ended December 31, 2018. See Note 1, "Organization and Basis of Presentation - Earnings per share," and Note 11, "Capitalization" for additional information on the BCF and the equity issuance. Net change in cash, cash equivalents and restricted cash Cash, cash equivalents, and restricted cash at beginning of period Cash, cash equivalents, and restricted cash at end of period SUPPLEMENTAL CASH FLOW INFORMATION: Non-cash transaction: beneficial conversion feature (Note1) Non-cash transaction: deemed dividend convertible preferred stock (Note 1) Cash paid during the year- Interest (net of amounts capitalized) Income taxes, net of refunds For the Years Ended December 31, 2019 2018 2017 $ 912 $ 1,348 $ (1,724) (59) 1,217 — (500) (108) 676 252 28 — — 271 (37) 10 (49) 12 6 (60) (21) (83) 2,467 2,300 — — — (789) — — (6) (814) (35) 656 (2,665) — 47 1,637 (1,675) — (217) — (2,873) (435) 1,384 — (1,250) (137) 144 485 42 (5) (9) (248) 24 (61) 109 — (25) 37 (121) 128 1,410 1,474 950 1,616 850 (2,608) — (89) (61) (711) (27) 1,394 (2,675) — 425 909 (963) (500) (218) 4 (3,018) 250 429 679 $ (214) 643 429 $ — $ — $ 296 $ (296) $ — 1,700 2,399 — 29 141 839 22 81 (63) (39) (6) 30 72 (9) 55 (27) (35) 343 3,808 4,675 — — — (2,291) (2,375) — — (639) (72) (702) (2,587) (254) 388 2,170 (2,268) — (172) — (2,723) 383 260 643 — — 960 12 $ $ 1,071 49 $ $ 1,039 53 $ $ $ $ $ Dividends declared for each share of common stock and as-converted share of preferred stock was $1.53 during 2019, $1.82 during The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. 2018, and $1.44 during 2017. The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. 52 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FIRSTENERGY CORP. Series A Convertible Preferred Stock Common Stock (In millions) Shares Amount Shares Amount OPIC AOCI Deficit Balance, January 1, 2017 — $ — 442 $ 44 $ 10,555 $ 174 $ (4,532) $ (1,724) (32) Balance, December 31, 2017 — — 445 44 10,001 142 1.6 (0.9) 162 (91) 1 3 3 Balance, December 31, 2018 0.7 71 512 51 11,530 41 Net loss Other comprehensive loss, net of tax Stock-based compensation Cash dividends declared on common stock Stock Investment Plan and certain share-based benefit plans Reclass to liability awards Share-based compensation accounting change Net income Other comprehensive loss, net of tax Stock-based compensation Cash dividends declared on common stock Cash dividends declared on preferred stock Stock Investment Plan and certain share-based benefit plans Stock issuance (Note 11)(1) Conversion of Series A Convertible Stock (Note 11) Impact of adopting new accounting pronouncements Net income Other comprehensive loss, net of tax Stock-based compensation Cash dividends declared on common stock Cash dividends declared on preferred stock Stock Investment Plan and certain share-based benefit plans Conversion of Series A Convertible Stock (Note 11) 36 (639) 56 (7) 60 (906) (71) 61 2,297 88 41 (824) (3) 56 68 (101) (21) (6) (6,262) 1,348 35 (4,879) 912 6,241 (1,724) (32) 36 (639) 56 (7) (6) 3,925 1,348 (101) 60 (906) (71) 62 2,462 — 35 6,814 912 (21) 41 (824) (3) 56 — 3 4 30 33 3 26 51 FIRSTENERGY CORP. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND BASIS OF PRESENTATION Note Number Page Number of Terms. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Organization and Basis of Presentation Revenue Discontinued Operations Accumulated Other Comprehensive Income Pension and Other Postemployment Benefits Stock-Based Compensation Plans Taxes Leases Intangible Assets Fair Value Measurements Capitalization Short-Term Borrowings and Bank Lines of Credit Asset Retirement Obligations Regulatory Matters Commitments, Guarantees and Contingencies Transactions with Affiliated Companies Segment Information Summary of Quarterly Financial Data (Unaudited) 54 62 65 68 69 75 77 80 83 84 87 91 92 92 99 103 103 105 Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary FE was incorporated under Ohio law in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding equity of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, AE Supply, MP, AGC, PE, WP, and FET and its principal subsidiaries (ATSI, MAIT and TrAIL). In addition, FE holds all of the outstanding equity of other direct subsidiaries including: AESC, FirstEnergy Properties, Inc., FEV, FELHC, Inc., GPUN, Allegheny Ventures, Inc., and Suvon, LLC doing business as both FirstEnergy Home and FirstEnergy Advisors. FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include approximately 24,500 miles of lines and two regional transmission operation centers. AGC, JCP&L and MP control 3,790 MWs of total capacity. FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the NRC, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued. FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate and permitted pursuant to GAAP. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see below). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). Certain prior year amounts have been reclassified to conform to the current year presentation. FES and FENOC Chapter 11 Filing On March 31, 2018, the FES Debtors announced that, in order to facilitate an orderly financial restructuring, they filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code with the Bankruptcy Court (which is referred to throughout as the FES Bankruptcy). As a result of the bankruptcy filings, FirstEnergy concluded that it no longer had a controlling interest in the FES Debtors as the entities are subject to the jurisdiction of the Bankruptcy Court and, accordingly, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy’s consolidated financial statements. Since such time, FE has accounted and will account for its investments in the FES Debtors at fair values of zero. FE concluded that in connection with the disposal, FES and FENOC became discontinued operations. See Note 3, "Discontinued Operations," for additional information. On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, and includes the following terms, among others: FE will pay certain pre-petition FES Debtors employee-related obligations, which include unfunded pension obligations and other employee benefits. FE will waive all pre-petition claims (other than those claims under the Tax Allocation Agreement for the 2018 tax year) and certain post-petition claims, against the FES Debtors related to the FES Debtors and their businesses, including the full borrowings by FES under the $500 million secured credit facility, the $200 million credit agreement being used to support surety bonds, the BNSF Railway Company/CSX Transportation, Inc. rail settlement guarantee, and the FES Debtors' unfunded pension The nonconsensual release of all claims against FirstEnergy by the FES Debtors' creditors, which was subsequently waived • • • obligations. pursuant to the Waiver Agreement, discussed below. • A $225 million cash payment from FirstEnergy. • An additional $628 million cash payment from FirstEnergy, which may be decreased by the amount, if any, of cash paid by FirstEnergy to the FES Debtors under the Intercompany Income Tax Allocation Agreement for the tax benefits related to the sale or deactivation of certain plants. On November 21, 2019, FirstEnergy, the FES Debtors, the UCC, and the FES Key Creditors Group entered into an amendment to the settlement agreement, which among other things, changed the $628 million 53 54 FIRSTENERGY CORP. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND BASIS OF PRESENTATION Note Number Page Number 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Organization and Basis of Presentation Revenue Discontinued Operations Accumulated Other Comprehensive Income Pension and Other Postemployment Benefits Stock-Based Compensation Plans Taxes Leases Intangible Assets Fair Value Measurements Capitalization Short-Term Borrowings and Bank Lines of Credit Asset Retirement Obligations Regulatory Matters Commitments, Guarantees and Contingencies Transactions with Affiliated Companies Segment Information Summary of Quarterly Financial Data (Unaudited) 54 62 65 68 69 75 77 80 83 84 87 91 92 92 99 103 103 105 Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms. FE was incorporated under Ohio law in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding equity of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, AE Supply, MP, AGC, PE, WP, and FET and its principal subsidiaries (ATSI, MAIT and TrAIL). In addition, FE holds all of the outstanding equity of other direct subsidiaries including: AESC, FirstEnergy Properties, Inc., FEV, FELHC, Inc., GPUN, Allegheny Ventures, Inc., and Suvon, LLC doing business as both FirstEnergy Home and FirstEnergy Advisors. FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include approximately 24,500 miles of lines and two regional transmission operation centers. AGC, JCP&L and MP control 3,790 MWs of total capacity. FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the NRC, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued. FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate and permitted pursuant to GAAP. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see below). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). Certain prior year amounts have been reclassified to conform to the current year presentation. FES and FENOC Chapter 11 Filing On March 31, 2018, the FES Debtors announced that, in order to facilitate an orderly financial restructuring, they filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code with the Bankruptcy Court (which is referred to throughout as the FES Bankruptcy). As a result of the bankruptcy filings, FirstEnergy concluded that it no longer had a controlling interest in the FES Debtors as the entities are subject to the jurisdiction of the Bankruptcy Court and, accordingly, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy’s consolidated financial statements. Since such time, FE has accounted and will account for its investments in the FES Debtors at fair values of zero. FE concluded that in connection with the disposal, FES and FENOC became discontinued operations. See Note 3, "Discontinued Operations," for additional information. On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, and includes the following terms, among others: • • • FE will pay certain pre-petition FES Debtors employee-related obligations, which include unfunded pension obligations and other employee benefits. FE will waive all pre-petition claims (other than those claims under the Tax Allocation Agreement for the 2018 tax year) and certain post-petition claims, against the FES Debtors related to the FES Debtors and their businesses, including the full borrowings by FES under the $500 million secured credit facility, the $200 million credit agreement being used to support surety bonds, the BNSF Railway Company/CSX Transportation, Inc. rail settlement guarantee, and the FES Debtors' unfunded pension obligations. The nonconsensual release of all claims against FirstEnergy by the FES Debtors' creditors, which was subsequently waived pursuant to the Waiver Agreement, discussed below. • A $225 million cash payment from FirstEnergy. • An additional $628 million cash payment from FirstEnergy, which may be decreased by the amount, if any, of cash paid by FirstEnergy to the FES Debtors under the Intercompany Income Tax Allocation Agreement for the tax benefits related to the sale or deactivation of certain plants. On November 21, 2019, FirstEnergy, the FES Debtors, the UCC, and the FES Key Creditors Group entered into an amendment to the settlement agreement, which among other things, changed the $628 million 53 54 • • note issuance, into a cash payment to be made upon emergence. The amendment was approved by the Bankruptcy Court on December 16, 2019. Transfer of the Pleasants Power Station and related assets, including the economic interests therein as of January 1, 2019, and a requirement that FE continues to provide access to the McElroy's Run CCR Impoundment Facility, which is not being transferred. In addition, FE provides guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. On January 21, 2020, AE Supply, FG and a newly formed subsidiary of FG, entered into a letter agreement authorizing the transfer of Pleasants Power Station prior to the FES Debtors’ emergence from bankruptcy. The letter agreement was approved by the Bankruptcy Court on January 28, 2020. The transfer of the Pleasants Power Station was completed on January 30, 2020. FirstEnergy agrees to waive all pre-petition claims related to shared services and credit for nine months of the FES Debtors' shared service costs beginning as of April 1, 2018 through December 31, 2018, in an amount not to exceed $112.5 million, and FirstEnergy agrees to extend the availability of shared services until no later than June 30, 2020. • • Subject to a cap, FirstEnergy has agreed to fund a pension enhancement through its pension plan for voluntary enhanced retirement packages offered to certain FES employees, as well as offer certain other employee benefits (approximately $14 million recognized for the year ending December 31, 2019). FirstEnergy agrees to perform under the Intercompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million for 2018. Based on the 2018 federal tax return filed in September 2019, FirstEnergy owes the FES debtors approximately $31 million associated with 2018, which will be paid upon emergence. Based on current estimates for the 2019 tax return to be filed in 2020, FirstEnergy estimates that it owes the FES Debtors approximately $83 million of which FirstEnergy has paid $14 million as of December 31, 2019. The estimated amounts owed to the FES Debtors for 2018 and 2019 tax returns excludes amounts allocated for non-deductible interest as discussed in Note 3, "Discontinued Operations." FirstEnergy is currently reconciling tax matters under the Intercompany Tax Allocation Agreement with the FES Debtors. The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements. In connection with the FES Bankruptcy settlement agreement, FirstEnergy entered into a separation agreement with the FES Debtors to implement the separation of the FES Debtors and their businesses from FirstEnergy. A business separation committee was established between FirstEnergy and the FES Debtors to review and determine issues that arise in the context of the separation of the FES Debtors’ businesses from those of FirstEnergy. As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply operated Pleasants until it transferred, which, as discussed above, occurred on January 30, 2020. After closing, AE Supply will continue to provide access to the McElroy's Run CCR Impoundment Facility, which was not transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. On April 11, 2019, the Bankruptcy Court entered an order denying the FES Debtors’ disclosure statement approval motion. The Bankruptcy Court concluded that the nonconsensual third-party releases proposed under the plan of reorganization, which were a condition under the FES Bankruptcy settlement agreement for FirstEnergy’s benefit, were legally impermissible and rendered the plan unconfirmable. On April 18, 2019, FirstEnergy consented to the waiver of the condition. Additionally, the FES Debtors agreed to provide FirstEnergy with the same third-party release provided in favor of certain other parties in any plan of reorganization and to pay FirstEnergy approximately $60 million in cash (paid during the second quarter of 2019) to resolve certain outstanding pension and service charges totaling $87 million, which resulted in FirstEnergy recognizing a $27 million pre-tax charge to income in the first quarter of 2019 ($17 million of which was recognized in continuing operations). Further, the FES Debtors agreed to initiate negotiations with the EPA, OEPA, PA DEP and the NRC to obtain those parties’ cooperation with the FES Debtors’ revised plan of reorganization. FirstEnergy may choose to participate in those negotiations at its option. On May 20, 2019, the Bankruptcy Court approved the waiver and a revised disclosure statement. In August 2019, the Bankruptcy Court held hearings to consider whether to confirm the FES Debtors’ plan of reorganization. Upon the conclusion of the hearing, the Bankruptcy Court ruled against the objections of several parties, including FERC and OVEC. However, the Bankruptcy Court ruled in favor of the objections made by certain of the FES Debtors’ unions regarding their collective bargaining agreements. The Bankruptcy Court adjourned the hearing without ruling on confirmation and explained that the only issue to be resolved was the acceptance or rejection by the FES Debtors of the collective bargaining agreements at issue. In October 2019, the FES Debtors and the unions objecting to confirmation of the plan of reorganization reached an agreement framework and the unions agreed to withdraw their objections to the plan of reorganization. On October 15, 2019, the Bankruptcy Court held a hearing to confirm the FES Debtors’ plan of reorganization, and on October 16, 2019, entered a final order confirming the FES Debtors' plan of reorganization. On October 29, 2019, several parties, including FERC, filed notices of appeal with the United States District Court for the Northern District of Ohio appealing the Bankruptcy Court’s final order approving FES Debtors’ plan of reorganization. On December 3, 2019, the NRC provided its approval. The emergence of the FES Debtors from bankruptcy pursuant to the confirmed plan of reorganization is subject to the satisfaction of certain conditions, including approvals from the FERC. Restricted Cash Restricted cash primarily relates to the consolidated VIE's discussed below. The cash collected from JCP&L, MP, PE and the Ohio Companies' customers is used to service debt of their respective funding companies. ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities and the Transmission Companies since their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost- based and can be charged to and collected from customers. FirstEnergy records regulatory assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These assets and liabilities are amortized in the Consolidated Statements of Income (Loss) concurrent with the recovery or refund through customer rates. FirstEnergy believes that it is probable that its regulatory assets and liabilities will be recovered and settled, respectively, through future rates. FirstEnergy, the Utilities and the Transmission Companies net their regulatory assets and liabilities based on federal and state jurisdictions. Management assesses the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Management applies judgment in evaluating the evidence available to assess the probability of recovery of regulatory assets from customers, including, but not limited to evaluating evidence related to precedent for similar items at the Company and information on comparable companies within similar jurisdictions, as well as assessing progress of communications between the Company and regulators. Certain of these regulatory assets, totaling approximately $111 million as of December 31, 2019, are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific order. The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2019 and December 31, 2018, and the changes during the year ended December 31, 2019: Net Regulatory Assets (Liabilities) by Source Regulatory transition costs Customer payables for future income taxes Nuclear decommissioning and spent fuel disposal costs Asset removal costs Deferred transmission costs Deferred generation costs Deferred distribution costs Contract valuations Storm-related costs Other December 31, December 31, 2019 2018 Change (In millions) $ (8) $ 49 $ (2,605) (197) (756) 298 214 155 51 551 36 (2,725) (148) (787) 170 202 208 72 500 52 (57) 120 (49) 31 128 12 (53) (21) 51 (16) 146 Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (2,261) $ (2,407) $ The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2019 and 2018, of which approximately $228 million and $290 million, respectively, are currently being recovered through rates over varying periods depending on the nature of the deferral and the jurisdiction. Regulatory Assets by Source Not Earning a December 31, December 31, Current Return 2019 2018 Change Regulatory transition costs Deferred transmission costs Deferred generation costs Storm-related costs Other (in millions) $ 7 $ $ 27 15 471 25 10 80 8 363 42 (3) (53) 7 108 (17) 42 Regulatory Assets Not Earning a Current Return $ 545 $ 503 $ 55 56 note issuance, into a cash payment to be made upon emergence. The amendment was approved by the Bankruptcy Court on December 16, 2019. • • • Transfer of the Pleasants Power Station and related assets, including the economic interests therein as of January 1, 2019, and a requirement that FE continues to provide access to the McElroy's Run CCR Impoundment Facility, which is not being transferred. In addition, FE provides guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. On January 21, 2020, AE Supply, FG and a newly formed subsidiary of FG, entered into a letter agreement authorizing the transfer of Pleasants Power Station prior to the FES Debtors’ emergence from bankruptcy. The letter agreement was approved by the Bankruptcy Court on January 28, 2020. The transfer of the Pleasants Power Station was completed on January 30, 2020. FirstEnergy agrees to waive all pre-petition claims related to shared services and credit for nine months of the FES Debtors' shared service costs beginning as of April 1, 2018 through December 31, 2018, in an amount not to exceed $112.5 million, and FirstEnergy agrees to extend the availability of shared services until no later than June 30, 2020. • Subject to a cap, FirstEnergy has agreed to fund a pension enhancement through its pension plan for voluntary enhanced retirement packages offered to certain FES employees, as well as offer certain other employee benefits (approximately $14 million recognized for the year ending December 31, 2019). FirstEnergy agrees to perform under the Intercompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million for 2018. Based on the 2018 federal tax return filed in September 2019, FirstEnergy owes the FES debtors approximately $31 million associated with 2018, which will be paid upon emergence. Based on current estimates for the 2019 tax return to be filed in 2020, FirstEnergy estimates that it owes the FES Debtors approximately $83 million of which FirstEnergy has paid $14 million as of December 31, 2019. The estimated amounts owed to the FES Debtors for 2018 and 2019 tax returns excludes amounts allocated for non-deductible interest as discussed in Note 3, "Discontinued Operations." FirstEnergy is currently reconciling tax matters under the Intercompany Tax Allocation Agreement with the FES Debtors. The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements. In connection with the FES Bankruptcy settlement agreement, FirstEnergy entered into a separation agreement with the FES Debtors to implement the separation of the FES Debtors and their businesses from FirstEnergy. A business separation committee was established between FirstEnergy and the FES Debtors to review and determine issues that arise in the context of the separation of the FES Debtors’ businesses from those of FirstEnergy. As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply operated Pleasants until it transferred, which, as discussed above, occurred on January 30, 2020. After closing, AE Supply will continue to provide access to the McElroy's Run CCR Impoundment Facility, which was not transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. On April 11, 2019, the Bankruptcy Court entered an order denying the FES Debtors’ disclosure statement approval motion. The Bankruptcy Court concluded that the nonconsensual third-party releases proposed under the plan of reorganization, which were a condition under the FES Bankruptcy settlement agreement for FirstEnergy’s benefit, were legally impermissible and rendered the plan unconfirmable. On April 18, 2019, FirstEnergy consented to the waiver of the condition. Additionally, the FES Debtors agreed to provide FirstEnergy with the same third-party release provided in favor of certain other parties in any plan of reorganization and to pay FirstEnergy approximately $60 million in cash (paid during the second quarter of 2019) to resolve certain outstanding pension and service charges totaling $87 million, which resulted in FirstEnergy recognizing a $27 million pre-tax charge to income in the first quarter of 2019 ($17 million of which was recognized in continuing operations). Further, the FES Debtors agreed to initiate negotiations with the EPA, OEPA, PA DEP and the NRC to obtain those parties’ cooperation with the FES Debtors’ revised plan of reorganization. FirstEnergy may choose to participate in those negotiations at its option. On May 20, 2019, the Bankruptcy Court approved the waiver and a revised disclosure statement. In August 2019, the Bankruptcy Court held hearings to consider whether to confirm the FES Debtors’ plan of reorganization. Upon the conclusion of the hearing, the Bankruptcy Court ruled against the objections of several parties, including FERC and OVEC. However, the Bankruptcy Court ruled in favor of the objections made by certain of the FES Debtors’ unions regarding their collective bargaining agreements. The Bankruptcy Court adjourned the hearing without ruling on confirmation and explained that the only issue to be resolved was the acceptance or rejection by the FES Debtors of the collective bargaining agreements at issue. In October 2019, the FES Debtors and the unions objecting to confirmation of the plan of reorganization reached an agreement framework and the unions agreed to withdraw their objections to the plan of reorganization. On October 15, 2019, the Bankruptcy Court held a hearing to confirm the FES Debtors’ plan of reorganization, and on October 16, 2019, entered a final order confirming the FES Debtors' plan of reorganization. On October 29, 2019, several parties, including FERC, filed notices of appeal with the United States District Court for the Northern District of Ohio appealing the Bankruptcy Court’s final order approving FES Debtors’ plan of reorganization. On December 3, 2019, the NRC provided its approval. The emergence of the FES Debtors from bankruptcy pursuant to the confirmed plan of reorganization is subject to the satisfaction of certain conditions, including approvals from the FERC. Restricted Cash Restricted cash primarily relates to the consolidated VIE's discussed below. The cash collected from JCP&L, MP, PE and the Ohio Companies' customers is used to service debt of their respective funding companies. ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities and the Transmission Companies since their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost- based and can be charged to and collected from customers. FirstEnergy records regulatory assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These assets and liabilities are amortized in the Consolidated Statements of Income (Loss) concurrent with the recovery or refund through customer rates. FirstEnergy believes that it is probable that its regulatory assets and liabilities will be recovered and settled, respectively, through future rates. FirstEnergy, the Utilities and the Transmission Companies net their regulatory assets and liabilities based on federal and state jurisdictions. Management assesses the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Management applies judgment in evaluating the evidence available to assess the probability of recovery of regulatory assets from customers, including, but not limited to evaluating evidence related to precedent for similar items at the Company and information on comparable companies within similar jurisdictions, as well as assessing progress of communications between the Company and regulators. Certain of these regulatory assets, totaling approximately $111 million as of December 31, 2019, are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific order. The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2019 and December 31, 2018, and the changes during the year ended December 31, 2019: Net Regulatory Assets (Liabilities) by Source December 31, 2019 December 31, 2018 Change Regulatory transition costs Customer payables for future income taxes Nuclear decommissioning and spent fuel disposal costs Asset removal costs Deferred transmission costs Deferred generation costs Deferred distribution costs Contract valuations Storm-related costs Other (In millions) $ (8) $ 49 $ (2,605) (197) (756) 298 214 155 51 551 36 (2,725) (148) (787) 170 202 208 72 500 52 Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (2,261) $ (2,407) $ (57) 120 (49) 31 128 12 (53) (21) 51 (16) 146 The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2019 and 2018, of which approximately $228 million and $290 million, respectively, are currently being recovered through rates over varying periods depending on the nature of the deferral and the jurisdiction. Regulatory Assets by Source Not Earning a Current Return December 31, 2019 December 31, 2018 Change Regulatory transition costs Deferred transmission costs Deferred generation costs Storm-related costs Other $ 7 $ 27 15 471 25 (in millions) $ 10 80 8 363 42 Regulatory Assets Not Earning a Current Return $ 545 $ 503 $ (3) (53) 7 108 (17) 42 55 56 CUSTOMER RECEIVABLES Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers for the Utilities. There was no material concentration of receivables as of December 31, 2019 and 2018, with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2019 and 2018, net of allowance for uncollectible accounts, are included below. The allowance for uncollectible customer receivables is based on historical loss information comprised of a rolling 36-month average net write-off percentage of revenues. Customer Receivables December 31, 2019 December 31, 2018 Billed Unbilled Total $ $ (In millions) $ 564 527 1,091 $ 686 535 1,221 EARNINGS (LOSS) PER SHARE OF COMMON STOCK The convertible preferred stock issued in January 2018 (see Note 11, "Capitalization") is considered participating securities since these shares participate in dividends on common stock on an "as-converted" basis. As a result, EPS of common stock is computed using the two-class method required for participating securities. The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders. Under the two-class method, net income attributable to common stockholders is derived by subtracting the following from income from continuing operations: • • • preferred stock dividends, deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the preferred stock (if any), and an allocation of undistributed earnings between the common stock and the participating securities (convertible preferred stock) based on their respective rights to receive dividends. Net losses are not allocated to the convertible preferred stock as they do not have a contractual obligation to share in the losses of FirstEnergy. FirstEnergy allocates undistributed earnings based upon income from continuing operations. The preferred stock included an embedded conversion option at a price that was below the fair value of the common stock on the commitment date. This beneficial conversion feature, which was approximately $296 million, represents the difference between the fair value per share of the common stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature was amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature was reflected in net income attributable to common stockholders as a deemed dividend and was fully amortized in 2018. Basic EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Participating securities are excluded from basic weighted average ordinary shares outstanding. Diluted EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding, including all potentially dilutive common shares, if the effect of such common shares is dilutive. Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible shares of preferred stock. The dilutive effect of outstanding share-based awards is computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period. The dilutive effect of the convertible preferred stock is computed using the if-converted method, which assumes conversion of the convertible preferred stock at the beginning of the period, giving income recognition for the add-back of the preferred share dividends, amortization of beneficial conversion feature, and undistributed earnings allocated to preferred stockholders. Reconciliation of Basic and Diluted EPS of Common Stock 2019 2018 2017 Year Ended December 31, Income (loss) attributable to common stockholders, basic 908 $ 981 $ (1,724) Income allocated to preferred stockholders, preferred dilutive (2) N/A N/A Income (loss) attributable to common stockholders, dilutive 912 $ 981 $ (1,724) (In millions, except per share amounts) EPS of Common Stock Income from continuing operations Less: Preferred dividends Less: Amortization of beneficial conversion feature Less: Undistributed earnings allocated to preferred stockholders(1) Income (loss) from continuing operations available to common stockholders Discontinued operations, net of tax Less: Undistributed earnings allocated to preferred stockholders (1) Income (loss) from discontinued operations available to common stockholders Share Count information: Weighted average number of basic shares outstanding Assumed exercise of dilutive stock options and awards Assumed conversion of preferred stock Weighted average number of diluted shares outstanding Income (loss) attributable to common stockholders, per common share: Income from continuing operations, basic Discontinued operations, basic Income (loss) attributable to common stockholders, basic Income from continuing operations, diluted Discontinued operations, diluted Income (loss) attributable to common stockholders, diluted $ 904 $ 1,022 $ (289) (3) — (1) 900 8 — 8 4 535 3 4 542 1.69 0.01 1.70 1.67 0.01 1.68 $ $ $ $ (71) (296) — 655 326 — 326 — — — — (289) (1,435) (1,435) 492 2 — 494 1.33 0.66 1.99 1.33 0.66 1.99 $ $ $ $ 444 — — 444 (0.65) (3.23) (3.88) (0.65) (3.23) (3.88) $ $ $ $ $ $ (1) Undistributed earnings were not allocated to participating securities for the year ended December 31, 2018, as income from continuing operations less dividends declared (common and preferred) and deemed dividends were a net loss. Undistributed earning allocated to participating securities for the year ended December 31, 2019 were immaterial. (2) The shares of common stock issuable upon conversion of the preferred shares (26 million shares) were not included for 2018 as their inclusion would be anti-dilutive to basic EPS from continuing operations. Amounts allocated to preferred stockholders of $4 million for the year ended December 31,2019 are included within Income from continuing operations available to common stockholders for diluted earnings. For the years ended December 31, 2018 and 2017, approximately 1 million and 3 million shares from stock options and awards were excluded from the calculation of diluted shares outstanding, respectively, as their inclusion would be antidilutive, and, in the case of 2017, a result of the net loss for the period. For the year ended December 31, 2019, no shares from stock options or awards were excluded from the calculation of diluted shares. 57 58 CUSTOMER RECEIVABLES Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers for the Utilities. There was no material concentration of receivables as of December 31, 2019 and 2018, with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2019 and 2018, net of allowance for uncollectible accounts, are included below. The allowance for uncollectible customer receivables is based on historical loss information comprised of a rolling 36-month average net write-off percentage of revenues. Customer Receivables December 31, December 31, 2019 2018 Billed Unbilled Total $ $ (In millions) $ 564 527 1,091 $ 686 535 1,221 EARNINGS (LOSS) PER SHARE OF COMMON STOCK The convertible preferred stock issued in January 2018 (see Note 11, "Capitalization") is considered participating securities since these shares participate in dividends on common stock on an "as-converted" basis. As a result, EPS of common stock is computed using the two-class method required for participating securities. Reconciliation of Basic and Diluted EPS of Common Stock 2019 2018 2017 Year Ended December 31, (In millions, except per share amounts) EPS of Common Stock Income from continuing operations Less: Preferred dividends Less: Amortization of beneficial conversion feature Less: Undistributed earnings allocated to preferred stockholders(1) Income (loss) from continuing operations available to common stockholders Discontinued operations, net of tax Less: Undistributed earnings allocated to preferred stockholders (1) Income (loss) from discontinued operations available to common stockholders Income (loss) attributable to common stockholders, basic Income allocated to preferred stockholders, preferred dilutive (2) Income (loss) attributable to common stockholders, dilutive The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders. Under the two-class method, net income attributable to common Share Count information: stockholders is derived by subtracting the following from income from continuing operations: preferred stock dividends, (if any), and • • • deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the preferred stock an allocation of undistributed earnings between the common stock and the participating securities (convertible preferred stock) based on their respective rights to receive dividends. Net losses are not allocated to the convertible preferred stock as they do not have a contractual obligation to share in the losses of FirstEnergy. FirstEnergy allocates undistributed earnings based upon income from continuing operations. Weighted average number of basic shares outstanding Assumed exercise of dilutive stock options and awards Assumed conversion of preferred stock Weighted average number of diluted shares outstanding Income (loss) attributable to common stockholders, per common share: Income from continuing operations, basic Discontinued operations, basic Income (loss) attributable to common stockholders, basic The preferred stock included an embedded conversion option at a price that was below the fair value of the common stock on the commitment date. This beneficial conversion feature, which was approximately $296 million, represents the difference between the fair value per share of the common stock and the conversion price, multiplied by the number of common shares issuable upon Income from continuing operations, diluted Discontinued operations, diluted conversion. The beneficial conversion feature was amortized as a deemed dividend over the period from the issue date to the first Income (loss) attributable to common stockholders, diluted $ 904 $ 1,022 $ (289) (3) — (1) 900 8 — 8 (71) (296) — 655 326 — 326 — — — (289) (1,435) — (1,435) 908 $ 981 $ (1,724) 4 N/A N/A 912 $ 981 $ (1,724) 535 3 4 542 1.69 0.01 1.70 1.67 0.01 1.68 $ $ $ $ 492 2 — 494 1.33 0.66 1.99 1.33 0.66 1.99 $ $ $ $ 444 — — 444 (0.65) (3.23) (3.88) (0.65) (3.23) (3.88) $ $ $ $ $ $ allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature was reflected in net income attributable to common stockholders as a deemed dividend and was fully amortized in 2018. Basic EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Participating securities are excluded from basic weighted average ordinary shares outstanding. Diluted EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding, including all potentially dilutive common shares, if the effect of such common shares is dilutive. Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible shares of preferred stock. The dilutive effect of outstanding share-based awards is computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period. The dilutive effect of the convertible preferred stock is computed using the if-converted method, which assumes conversion of the convertible preferred stock at the beginning of the period, giving income recognition for the add-back of the preferred share dividends, amortization of beneficial conversion feature, and undistributed earnings allocated to preferred stockholders. (1) Undistributed earnings were not allocated to participating securities for the year ended December 31, 2018, as income from continuing operations less dividends declared (common and preferred) and deemed dividends were a net loss. Undistributed earning allocated to participating securities for the year ended December 31, 2019 were immaterial. The shares of common stock issuable upon conversion of the preferred shares (26 million shares) were not included for 2018 as their inclusion would be anti-dilutive to basic EPS from continuing operations. Amounts allocated to preferred stockholders of $4 million for the year ended December 31,2019 are included within Income from continuing operations available to common stockholders for diluted earnings. (2) For the years ended December 31, 2018 and 2017, approximately 1 million and 3 million shares from stock options and awards were excluded from the calculation of diluted shares outstanding, respectively, as their inclusion would be antidilutive, and, in the case of 2017, a result of the net loss for the period. For the year ended December 31, 2019, no shares from stock options or awards were excluded from the calculation of diluted shares. 57 58 PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred. Property, plant and equipment balances by segment as of December 31, 2019 and 2018, were as follows: Property, Plant and Equipment In Service(1) Accum. Depr. Net Plant CWIP Total December 31, 2019 Regulated Distribution Regulated Transmission Corporate/Other Total Property, Plant and Equipment Regulated Distribution Regulated Transmission Corporate/Other Total $ $ $ $ (In millions) 28,735 $ (8,540) $ 20,195 $ 12,023 1,009 (2,383) (504) 9,640 505 $ 744 526 40 41,767 $ (11,427) $ 30,340 $ 1,310 $ 20,939 10,166 545 31,650 In Service(1) Accum. Depr. Net Plant CWIP Total December 31, 2018 (In millions) 27,520 $ (8,132) $ 19,388 $ 11,041 908 (2,210) (451) 8,831 457 628 545 62 $ 20,016 9,376 519 39,469 $ (10,793) $ 28,676 $ 1,235 $ 29,911 (1) Includes finance leases of $163 million and $173 million as of December 31, 2019 and 2018, respectively. The major classes of Property, plant and equipment are largely consistent with the segment disclosures above. Regulated Distribution has approximately $2 billion of total regulated generation property, plant and equipment. FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite depreciation rates for FirstEnergy were 2.7%, 2.6% and 2.4% in 2019, 2018 and 2017, respectively. For the years ended December 31, 2019, 2018 and 2017, capitalized financing costs on FirstEnergy's Consolidated Statements of Income (Loss) include $45 million, $46 million and $35 million, respectively, of allowance for equity funds used during construction and $26 million, $19 million and $17 million, respectively, of capitalized interest. INVENTORY Jointly Owned Plants FE, through its subsidiary, AGC, owns an undivided 16.25% interest (487 MWs) in a 3,003 MW pumped storage, hydroelectric station in Bath County, Virginia, operated by the 60% owner, VEPCO, a non-affiliated utility. Net Property, plant and equipment includes $161 million representing AGC's share in this facility as of December 31, 2019. AGC is obligated to pay its share of the costs of this jointly-owned facility in the same proportion as its ownership interests using its own financing. AGC's share of direct expenses of the joint plant is included in FE's operating expenses on the Consolidated Statements of Income (Loss). AGC provides the generation capacity from this facility to its owner, MP. DERIVATIVES Asset Retirement Obligations FE recognizes an ARO for the future decommissioning of its TMI-2 nuclear power plant and future remediation of other environmental liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation AROs, considering the expected timing of settlement of the ARO based on the expected economic useful life of associated asset and/or regulatory requirements. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. In certain circumstances, FirstEnergy has recovery of asset retirement costs and, as such, certain accretion and depreciation is offset against regulatory assets. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the AROs as of December 31, 2019, are described further in Note 13, "Asset Retirement Obligations." FirstEnergy evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate the carrying value of the long-lived assets may not be recoverable. First, the estimated undiscounted future cash flows attributable to the assets is compared with the carrying value of the assets. If the carrying value is greater than the undiscounted future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated liability recognition. Asset Impairments fair value. GOODWILL In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50%) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value or bypasses the qualitative assessment, then the quantitative goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any. FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution and Regulated Transmission. The following table presents goodwill by reporting unit as of December 31, 2019: Goodwill $ 5,004 $ 614 $ 5,618 Regulated Distribution Regulated Transmission Consolidated (In millions) As of July 31, 2019, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial performance. Key factors used in the assessment include: growth rates, interest rates, expected capital expenditures, utility sector market performance and other market considerations. It was determined that the fair values of these reporting units were, more likely than not, greater than their carrying values and a quantitative analysis was not necessary. Materials and supplies inventory includes fuel inventory and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory. Materials are generally charged to inventory at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed. Fuel inventory is accounted for at weighted average cost when purchased, and recorded to fuel expense when consumed. FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy may use a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance. VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has: (i) the power to direct the activities of a VIE that most significantly 59 60 $ $ $ $ December 31, 2019 (In millions) December 31, 2018 (In millions) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred. Property, plant and equipment balances by segment as of December 31, 2019 and 2018, were as follows: Property, Plant and Equipment In Service(1) Accum. Depr. Net Plant CWIP Total Regulated Distribution Regulated Transmission Corporate/Other Total 28,735 $ (8,540) $ 20,195 $ 12,023 1,009 (2,383) (504) 9,640 505 $ 744 526 40 41,767 $ (11,427) $ 30,340 $ 1,310 $ 20,939 10,166 545 31,650 Property, Plant and Equipment In Service(1) Accum. Depr. Net Plant CWIP Total Regulated Distribution Regulated Transmission Corporate/Other Total 27,520 $ (8,132) $ 19,388 $ $ 20,016 11,041 908 (2,210) (451) 8,831 457 628 545 62 9,376 519 39,469 $ (10,793) $ 28,676 $ 1,235 $ 29,911 (1) Includes finance leases of $163 million and $173 million as of December 31, 2019 and 2018, respectively. The major classes of Property, plant and equipment are largely consistent with the segment disclosures above. Regulated Distribution has approximately $2 billion of total regulated generation property, plant and equipment. FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite depreciation rates for FirstEnergy were 2.7%, 2.6% and 2.4% in 2019, 2018 and 2017, respectively. For the years ended December 31, 2019, 2018 and 2017, capitalized financing costs on FirstEnergy's Consolidated Statements of Income (Loss) include $45 million, $46 million and $35 million, respectively, of allowance for equity funds used during construction and $26 million, $19 million and $17 million, respectively, of capitalized interest. Jointly Owned Plants FE, through its subsidiary, AGC, owns an undivided 16.25% interest (487 MWs) in a 3,003 MW pumped storage, hydroelectric station in Bath County, Virginia, operated by the 60% owner, VEPCO, a non-affiliated utility. Net Property, plant and equipment includes $161 million representing AGC's share in this facility as of December 31, 2019. AGC is obligated to pay its share of the costs of this jointly-owned facility in the same proportion as its ownership interests using its own financing. AGC's share of direct expenses of the joint plant is included in FE's operating expenses on the Consolidated Statements of Income (Loss). AGC provides the generation capacity from this facility to its owner, MP. Asset Retirement Obligations FE recognizes an ARO for the future decommissioning of its TMI-2 nuclear power plant and future remediation of other environmental liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation AROs, considering the expected timing of settlement of the ARO based on the expected economic useful life of associated asset and/or regulatory requirements. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. In certain circumstances, FirstEnergy has recovery of asset retirement costs and, as such, certain accretion and depreciation is offset against regulatory assets. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition. AROs as of December 31, 2019, are described further in Note 13, "Asset Retirement Obligations." Asset Impairments FirstEnergy evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate the carrying value of the long-lived assets may not be recoverable. First, the estimated undiscounted future cash flows attributable to the assets is compared with the carrying value of the assets. If the carrying value is greater than the undiscounted future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated fair value. GOODWILL In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50%) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value or bypasses the qualitative assessment, then the quantitative goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any. FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution and Regulated Transmission. The following table presents goodwill by reporting unit as of December 31, 2019: Goodwill $ 5,004 $ 614 $ 5,618 Regulated Distribution Regulated Transmission Consolidated (In millions) As of July 31, 2019, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial performance. Key factors used in the assessment include: growth rates, interest rates, expected capital expenditures, utility sector market performance and other market considerations. It was determined that the fair values of these reporting units were, more likely than not, greater than their carrying values and a quantitative analysis was not necessary. INVENTORY Materials and supplies inventory includes fuel inventory and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory. Materials are generally charged to inventory at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed. Fuel inventory is accounted for at weighted average cost when purchased, and recorded to fuel expense when consumed. DERIVATIVES FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy may use a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance. VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has: (i) the power to direct the activities of a VIE that most significantly 59 60 impact the entity’s economic performance; and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. NEW ACCOUNTING PRONOUNCEMENTS Recently Adopted Pronouncements In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance. Consolidated VIEs VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements): • Ohio Securitization - In June 2013, SPEs formed by the Ohio Companies issued approximately $445 million of pass- through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. JCP&L Securitization - JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. • ASU 2016-02, "Leases (Topic 842)" (Issued February 2016 and subsequently updated to address implementation questions): The new guidance requires organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets, as well as new qualitative and quantitative disclosures. FirstEnergy implemented a third-party software tool that assisted with the initial adoption and will assist with ongoing compliance. FirstEnergy chose to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Upon adoption, on January 1, 2019, FirstEnergy increased assets and liabilities by $186 million, with no impact to results of operations or cash flows. See Note 8, "Leases," for additional information on FirstEnergy's leases. Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact • MP and PE Environmental Funding Companies - Bankruptcy remote, special purpose limited liability companies that are FirstEnergy's financial reporting. indirect subsidiaries of MP and PE which issued environmental control bonds. See Note 11, “Capitalization,” for additional information on securitized bonds. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of the following VIEs: • Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint ventures economic performance. FEV's ownership interest is subject to the equity method of accounting. As of December 31, 2019, the carrying value of the equity method investment was $28 million. As discussed in Note 15, "Commitments, Guarantees and Contingencies," FE is the guarantor under Global Holding's $120 million syndicated senior secured term loan facility due November 12, 2024, under which Global Holding's outstanding principal balance is $114 million as of December 31, 2019. Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to be obligated under the provisions of its guarantee, resulting in consolidation of Global Holding by FE. • PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland which PJM cancelled in 2012, is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting. As of December 31, 2019, the carrying value of the equity method investment was $18 million. • Purchase Power Agreements - FirstEnergy evaluated its PPAs and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy maintains 10 long-term PPAs with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that for all but one of these NUG entities, it does not have a variable interest, or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities. Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contract that may contain a variable interest were $116 million and $108 million, respectively, during the years ended December 31, 2019 and 2018. • FES and FENOC - As a result of the Chapter 11 bankruptcy filing discussed in Note 3, "Discontinued Operations," FE evaluated its investments in FES and FENOC and determined they are VIEs. FE is not the primary beneficiary because it lacks a controlling interest in FES and FENOC, which are subject to the jurisdiction of the Bankruptcy Court as of March 31, 2018. The carrying values of the equity investments in FES and FENOC were zero at December 31, 2019. ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (issued June 2016 and subsequently updated): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for expected credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. FirstEnergy has analyzed its financial instruments within the scope of this guidance, primarily trade receivables, AFS debt securities and certain third-party guarantees and does not expect a material impact to its financial statements upon adoption in 2020. ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" (Issued August 2018): ASU 2018-15 requires implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. FirstEnergy does not expect a material impact to its financial statements upon adoption in 2020. ASU 2019-12, "Simplifying the Accounting for Income Taxes" (Issued in December 2019): ASU 2019-12 enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted. 2. REVENUE FirstEnergy accounts for revenues from contracts with customers under ASC 606, "Revenue from Contracts with Customers." Revenue from leases, financial instruments, other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the new standard and accounted for under other existing GAAP. FirstEnergy has elected to exclude sales taxes and other similar taxes collected on behalf of third parties from revenue as prescribed in the new standard. As a result, tax collections and remittances are excluded from recognition in the income statement and instead recorded through the balance sheet. Excise and gross receipts taxes that are assessed on FirstEnergy are not subject to the election and are included in revenue. FirstEnergy has elected the optional invoice practical expedient for most of its revenues and, with the exception of JCP&L transmission, utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations. 61 62 impact the entity’s economic performance; and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. NEW ACCOUNTING PRONOUNCEMENTS Recently Adopted Pronouncements In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance. Consolidated VIEs statements): VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial • Ohio Securitization - In June 2013, SPEs formed by the Ohio Companies issued approximately $445 million of pass- through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. • JCP&L Securitization - JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. • MP and PE Environmental Funding Companies - Bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE which issued environmental control bonds. See Note 11, “Capitalization,” for additional information on securitized bonds. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of the following VIEs: • Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint ventures economic performance. FEV's ownership interest is subject to the equity method of accounting. As of December 31, 2019, the carrying value of the equity method investment was $28 million. As discussed in Note 15, "Commitments, Guarantees and Contingencies," FE is the guarantor under Global Holding's $120 million syndicated senior secured term loan facility due November 12, 2024, under which Global Holding's outstanding principal balance is $114 million as of December 31, 2019. Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to be obligated under the provisions of its guarantee, resulting in consolidation of Global Holding by FE. • PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland which PJM cancelled in 2012, is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject • Purchase Power Agreements - FirstEnergy evaluated its PPAs and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy maintains 10 long-term PPAs with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that for all but one of these NUG entities, it does not have a variable interest, or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities. Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contract that may contain a variable interest were $116 million and $108 million, respectively, during the years ended December 31, 2019 and 2018. • FES and FENOC - As a result of the Chapter 11 bankruptcy filing discussed in Note 3, "Discontinued Operations," FE evaluated its investments in FES and FENOC and determined they are VIEs. FE is not the primary beneficiary because it lacks a controlling interest in FES and FENOC, which are subject to the jurisdiction of the Bankruptcy Court as of March 31, 2018. The carrying values of the equity investments in FES and FENOC were zero at December 31, 2019. ASU 2016-02, "Leases (Topic 842)" (Issued February 2016 and subsequently updated to address implementation questions): The new guidance requires organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets, as well as new qualitative and quantitative disclosures. FirstEnergy implemented a third-party software tool that assisted with the initial adoption and will assist with ongoing compliance. FirstEnergy chose to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Upon adoption, on January 1, 2019, FirstEnergy increased assets and liabilities by $186 million, with no impact to results of operations or cash flows. See Note 8, "Leases," for additional information on FirstEnergy's leases. Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (issued June 2016 and subsequently updated): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for expected credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. FirstEnergy has analyzed its financial instruments within the scope of this guidance, primarily trade receivables, AFS debt securities and certain third-party guarantees and does not expect a material impact to its financial statements upon adoption in 2020. ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" (Issued August 2018): ASU 2018-15 requires implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. FirstEnergy does not expect a material impact to its financial statements upon adoption in 2020. ASU 2019-12, "Simplifying the Accounting for Income Taxes" (Issued in December 2019): ASU 2019-12 enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted. to the equity method of accounting. As of December 31, 2019, the carrying value of the equity method investment was 2. REVENUE $18 million. FirstEnergy accounts for revenues from contracts with customers under ASC 606, "Revenue from Contracts with Customers." Revenue from leases, financial instruments, other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the new standard and accounted for under other existing GAAP. FirstEnergy has elected to exclude sales taxes and other similar taxes collected on behalf of third parties from revenue as prescribed in the new standard. As a result, tax collections and remittances are excluded from recognition in the income statement and instead recorded through the balance sheet. Excise and gross receipts taxes that are assessed on FirstEnergy are not subject to the election and are included in revenue. FirstEnergy has elected the optional invoice practical expedient for most of its revenues and, with the exception of JCP&L transmission, utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations. 61 62 FirstEnergy’s revenues are primarily derived from electric service provided by the Utilities and Transmission Companies. The following tables represent a disaggregation of revenue from contracts with customers for the year ended December 31, 2019, by type of service from each reportable segment: Revenues by Type of Service Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total Distribution services(2) Retail generation Wholesale sales(2) Transmission(2) Other $ 5,133 $ — $ (In millions) 3,727 411 — 150 — — 1,510 — (83) $ (57) 12 — 2 5,050 3,670 423 1,510 152 Total revenues from contracts with customers $ 9,421 $ 1,510 $ (126) $ 10,805 ARP Other non-customer revenue Total revenues 181 96 — 16 — (63) 181 49 $ 9,698 $ 1,526 $ (189) $ 11,035 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($16 million at Regulated Distribution and $19 million at Regulated Transmission). The following tables represent a disaggregation of revenue from contracts with customers for the year ended December 31, 2018, by type of service from each reportable segment: Revenues by Type of Service Distribution services(2) Retail generation Wholesale sales(2) Transmission(2) Other Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total $ 5,159 $ — $ (104) $ (In millions) 3,936 502 — 144 — — 1,335 — (54) 22 — 4 5,055 3,882 524 1,335 148 Total revenues from contracts with customers $ 9,741 $ 1,335 $ (132) $ 10,944 ARP Other non-customer revenue Total revenues 254 108 — 18 — (63) 254 63 $ 10,103 $ 1,353 $ (195) $ 11,261 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes $147 million in net reductions to revenue related to amounts subject to refund resulting from the Tax Act ($131 million at Regulated Distribution and $16 million at Regulated Transmission). Other non-customer revenue includes revenue from late payment charges of $37 million and $39 million, as well as revenue from derivatives of $8 million and $18 million, respectively, for the years ended December 31, 2019 and 2018. Regulated Distribution The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies and also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. Each of the Utilities earns revenue from state-regulated rate tariffs under which it provides distribution services to residential, commercial and industrial customers in its service territory. The Utilities are obligated under the regulated construct to deliver power to customers reliably, as it is needed, which creates an implied monthly contract with the end-use customer. See Note 14 "Regulatory Matters," for additional information on rate recovery mechanisms. Distribution and electric revenues are recognized over time as electricity is distributed and delivered to the customer and the customers consume the electricity immediately as delivery occurs. Retail generation sales relate to POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland, as well as generation sales in West Virginia that are regulated by the WVPSC. Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales varies depending on the level of shopping that occurs. Supply plans vary by state and by service territory. Default service for the Ohio Companies, Pennsylvania Companies, JCP&L and PE's Maryland jurisdiction are provided through a competitive procurement process approved by each state's respective commission. Retail generation revenues are recognized over time as electricity is delivered and consumed immediately by the customer. The following table represents a disaggregation of the Regulated Distribution segment revenue from contracts with distribution service and retail generation customers for the years ended December 31, 2019 and 2018, by class: Revenues by Customer Class 2019 2018 For the Years Ended December 31, Residential Commercial Industrial Other Total $ $ (In millions) 5,412 $ 2,252 1,106 90 8,860 $ 5,598 2,350 1,056 91 9,095 Wholesale sales primarily consist of generation and capacity sales into the PJM market from FirstEnergy's regulated electric generation capacity and NUGs. Certain of the Utilities may also purchase power in the PJM markets to supply power to their customers. Generally, these power sales from generation and purchases to serve load are netted hourly and reported gross as either revenues or purchased power on the Consolidated Statements of Income (Loss) based on whether the entity was a net seller or buyer each hour. Capacity revenues are recognized ratably over the PJM planning year at prices cleared in the annual PJM Reliability Pricing Model Based Residual Auction and incremental auctions. Capacity purchases and sales through PJM capacity auctions are reported within revenues on the Consolidated Statements of Income (Loss). Certain capacity income (bonuses) and charges (penalties) related to the availability of units that have cleared in the auctions are unknown and not recorded in revenue until, and unless, they occur. The Utilities’ distribution customers are metered on a cycle basis. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, the Utilities accrue the estimated unbilled amount as revenue and reverse the related prior period estimate. Customer payments vary by state but are generally due within 30 days. ASC 606 excludes industry-specific accounting guidance for recognizing revenue from ARPs as these programs represent contracts between the utility and its regulators, as opposed to customers. Therefore, revenue from these programs are not within the scope of ASC 606 and regulated utilities are permitted to continue to recognize such revenues in accordance with existing practice but are presented separately from revenue arising from contracts with customers. FirstEnergy currently has ARPs in Ohio, primarily under Rider DMR, and in New Jersey. Please see Note 14, "Regulatory Matters," for further discussion on Rider DMR. Regulated Transmission The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are primarily derived from forward-looking formula rates at the Transmission Companies, as well as stated transmission rates at JCP&L, MP, PE and WP. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. Revenue requirements under stated rates are calculated annually by multiplying the highest one-hour peak load in each respective transmission zone by the approved, stated rate in that zone. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time. Effective January 1, 2018, JCP&L is subject to a FERC-approved settlement agreement that provides an annual revenue requirement of $155 million, which is recognized ratably as revenue over time. Please see Note 14, "Regulatory Matters," for further discussion on tariff amendments approved by FERC on December 19, 2019, to convert JCP&L's existing stated transmission rate to a forward- looking formula transmission rate. 63 64 FirstEnergy’s revenues are primarily derived from electric service provided by the Utilities and Transmission Companies. The following tables represent a disaggregation of revenue from contracts with customers for the year ended December 31, 2019, by type of service from each reportable segment: Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total $ 5,133 $ — $ (In millions) Revenues by Type of Service Distribution services(2) Retail generation Wholesale sales(2) Transmission(2) Other ARP Other non-customer revenue Total revenues Revenues by Type of Service Distribution services(2) Retail generation Wholesale sales(2) Transmission(2) Other ARP Other non-customer revenue Total revenues Total revenues from contracts with customers $ 9,421 $ 1,510 $ (126) $ 10,805 $ 9,698 $ 1,526 $ (189) $ 11,035 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($16 million at Regulated Distribution and $19 million at Regulated Transmission). The following tables represent a disaggregation of revenue from contracts with customers for the year ended December 31, 2018, by type of service from each reportable segment: Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total $ 5,159 $ — $ (104) $ (In millions) 3,727 411 — 150 181 96 3,936 502 — 144 254 108 1,510 — — — — 16 1,335 — — — — 18 (83) $ (57) 12 — 2 — (63) 5,050 3,670 423 1,510 152 181 49 (54) 22 — 4 — (63) 5,055 3,882 524 1,335 148 254 63 Total revenues from contracts with customers $ 9,741 $ 1,335 $ (132) $ 10,944 $ 10,103 $ 1,353 $ (195) $ 11,261 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes $147 million in net reductions to revenue related to amounts subject to refund resulting from the Tax Act ($131 million at Regulated Distribution and $16 million at Regulated Transmission). Other non-customer revenue includes revenue from late payment charges of $37 million and $39 million, as well as revenue from derivatives of $8 million and $18 million, respectively, for the years ended December 31, 2019 and 2018. Regulated Distribution The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies and also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. Each of the Utilities earns revenue from state-regulated rate tariffs under which it provides distribution services to residential, commercial and industrial customers in its service territory. The Utilities are obligated under the regulated construct to deliver power to customers reliably, as it is needed, which creates an implied monthly contract with the end-use customer. See Note 14 "Regulatory Matters," for additional information on rate recovery mechanisms. Distribution and electric revenues are recognized over time as electricity is distributed and delivered to the customer and the customers consume the electricity immediately as delivery occurs. Retail generation sales relate to POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland, as well as generation sales in West Virginia that are regulated by the WVPSC. Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales varies depending on the level of shopping that occurs. Supply plans vary by state and by service territory. Default service for the Ohio Companies, Pennsylvania Companies, JCP&L and PE's Maryland jurisdiction are provided through a competitive procurement process approved by each state's respective commission. Retail generation revenues are recognized over time as electricity is delivered and consumed immediately by the customer. The following table represents a disaggregation of the Regulated Distribution segment revenue from contracts with distribution service and retail generation customers for the years ended December 31, 2019 and 2018, by class: Revenues by Customer Class 2019 2018 For the Years Ended December 31, Residential Commercial Industrial Other Total $ $ (In millions) 5,412 $ 2,252 1,106 90 8,860 $ 5,598 2,350 1,056 91 9,095 Wholesale sales primarily consist of generation and capacity sales into the PJM market from FirstEnergy's regulated electric generation capacity and NUGs. Certain of the Utilities may also purchase power in the PJM markets to supply power to their customers. Generally, these power sales from generation and purchases to serve load are netted hourly and reported gross as either revenues or purchased power on the Consolidated Statements of Income (Loss) based on whether the entity was a net seller or buyer each hour. Capacity revenues are recognized ratably over the PJM planning year at prices cleared in the annual PJM Reliability Pricing Model Based Residual Auction and incremental auctions. Capacity purchases and sales through PJM capacity auctions are reported within revenues on the Consolidated Statements of Income (Loss). Certain capacity income (bonuses) and charges (penalties) related to the availability of units that have cleared in the auctions are unknown and not recorded in revenue until, and unless, they occur. The Utilities’ distribution customers are metered on a cycle basis. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, the Utilities accrue the estimated unbilled amount as revenue and reverse the related prior period estimate. Customer payments vary by state but are generally due within 30 days. ASC 606 excludes industry-specific accounting guidance for recognizing revenue from ARPs as these programs represent contracts between the utility and its regulators, as opposed to customers. Therefore, revenue from these programs are not within the scope of ASC 606 and regulated utilities are permitted to continue to recognize such revenues in accordance with existing practice but are presented separately from revenue arising from contracts with customers. FirstEnergy currently has ARPs in Ohio, primarily under Rider DMR, and in New Jersey. Please see Note 14, "Regulatory Matters," for further discussion on Rider DMR. Regulated Transmission The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are primarily derived from forward-looking formula rates at the Transmission Companies, as well as stated transmission rates at JCP&L, MP, PE and WP. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. Revenue requirements under stated rates are calculated annually by multiplying the highest one-hour peak load in each respective transmission zone by the approved, stated rate in that zone. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time. Effective January 1, 2018, JCP&L is subject to a FERC-approved settlement agreement that provides an annual revenue requirement of $155 million, which is recognized ratably as revenue over time. Please see Note 14, "Regulatory Matters," for further discussion on tariff amendments approved by FERC on December 19, 2019, to convert JCP&L's existing stated transmission rate to a forward- looking formula transmission rate. 63 64 The following table represents a disaggregation of revenue from contracts with regulated transmission customers by transmission owner for the years ended December 31, 2019 and 2018 by transmission owner: recognized by FE and was included within the loss from discontinued operations as of December 31, 2018. The FES Debtors have paid approximately $152 million for the shared services for the year ended December 31, 2019. Transmission Owner 2019 2018 For the Years Ended December 31, ATSI TrAIL MAIT Other Total Revenues $ $ (In millions) $ 754 242 224 290 664 237 150 284 1,510 $ 1,335 3. DISCONTINUED OPERATIONS FES, FENOC, BSPC and a portion of AE Supply (including the Pleasants Power Station), representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, are presented as discontinued operations in FirstEnergy’s consolidated financial statements resulting from the FES Bankruptcy and actions taken as part of the strategic review to exit commodity-exposed generation, as discussed below. Prior period results have been reclassified to conform with such presentation as discontinued operations. respectively. Income Taxes FES and FENOC Chapter 11 Bankruptcy Filing As discussed in Note 1, "Organization and Basis of Presentation," on March 31, 2018, FES and FENOC announced the FES Bankruptcy. FirstEnergy concluded that it no longer had a controlling interest in the FES Debtors, as the entities are subject to the jurisdiction of the Bankruptcy Court and, accordingly, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy's consolidated financial statements, and FirstEnergy has accounted and will account for its investments in the FES Debtors at fair values of zero. In connection with the disposal and the FES Bankruptcy settlement agreement approved by the Bankruptcy Court in September 2018, as further discussed in Note 1, "Organization and Basis of Presentation," FE recorded an after-tax gain on disposal of $59 million and $435 million in 2019 and 2018, respectively. By eliminating a significant portion of its competitive generation fleet with the deconsolidation of the FES Debtors, FirstEnergy has concluded the FES Debtors meet the criteria for discontinued operations, as this represents a significant event in management’s strategic review to exit commodity-exposed generation and transition to a fully regulated company. FES Borrowings from FE On March 9, 2018, FES borrowed $500 million from FE under the secured credit facility, dated as of December 6, 2016, among FES, as borrower, FG and NG as guarantors, and FE, as lender, which fully utilized the committed line of credit available under the secured credit facility. Following deconsolidation of FES, FE fully reserved for the $500 million associated with the borrowings under the secured credit facility. Under the terms of the FES Bankruptcy settlement agreement, FE will release any and all claims against the FES Debtors with respect to the $500 million borrowed under the secured credit facility. On March 16, 2018, the FES Debtors withdrew from the unregulated companies' money pool, which included FE, and the FES Debtors. Under the terms of the FES Bankruptcy settlement agreement, FE reinstated $88 million for 2018 estimated payments for NOLs applied against the FES Debtor’s position in the unregulated companies’ money pool prior to their withdrawal on March 16, 2018, which increased the amount the FES Debtors owed FE under the money pool to $92 million. In addition, as of March 31, 2018, AE Supply had a $102 million outstanding unsecured promissory note owed from FES. Following deconsolidation of the FES Debtors on March 31, 2018, and given the terms of the FES Bankruptcy settlement agreement, FE fully reserved the $92 million associated with the outstanding unsecured borrowings under the unregulated companies' money pool and the $102 million associated with the AE Supply unsecured promissory note. Under the terms of the FES Bankruptcy settlement agreement, FirstEnergy will release any and all claims against the FES Debtors with respect to the $92 million owed under the unregulated money pool and $102 million unsecured promissory note. For the years ended December 31, 2019 and 2018, approximately $33 million and $24 million of interest was accrued and subsequently reserved, respectively. Services Agreements Pursuant to the FES Bankruptcy settlement agreement, FirstEnergy entered into an amended and restated shared services agreement with the FES Debtors to extend the availability of shared services until no later than June 30, 2020, subject to reductions in services if requested by the FES Debtors. Under the amended shared services agreement, and consistent with the prior shared services agreements, costs are directly billed or assigned at no more than cost. In addition to providing for certain notice requirements and other terms and conditions, the agreement provided for a credit to the FES Debtors in an amount up to $112.5 million for charges incurred for services provided under prior shared services agreements and the amended shared services agreement from April 1, 2018 through December 31, 2018. The entire credit for shared services provided to the FES Debtors ($112.5 million) has been FirstEnergy will retain certain obligations for the FES Debtors' employees for services provided prior to emergence from bankruptcy. The retention of this obligation at March 31, 2018, resulted in a net liability of $820 million (including EDCP, pension and OPEB) with a corresponding loss from discontinued operations. EDCP and pension/OPEB service costs earned by the FES Debtors' employees during bankruptcy are billed under the shared services agreement. As FE continues to provide pension benefits to FES/ FENOC employees, certain components of pension cost, including the mark to market, are seen as providing ongoing services and are reported in the continuing operations of FE, subsequent to the bankruptcy filing. FE has billed the FES Debtors approximately $37 million for their share of pension and OPEB service costs for the year ended December 31, 2019. Benefit Obligations Purchase Power FES at times provides power through affiliated company power sales to meet a portion of the Utilities' POLR and default service requirements and provides power to certain affiliates' facilities. As of December 31, 2019, the Utilities owed FES approximately $10 million related to these purchases. The terms and conditions of the power purchase agreements are generally consistent with industry practices and other similar third-party arrangements. The Utilities purchased and recognized in continuing operations approximately $171 million and $318 million of power purchases from FES for the years ended December 31, 2019 and 2018, For U.S. federal income taxes, until emergence from bankruptcy, the FES Debtors will continue to be consolidated in FirstEnergy’s tax return and taxable income will be determined based on the tax basis of underlying individual net assets. Deferred taxes previously recorded on the inside basis differences may not represent the actual tax consequence for the outside basis difference, causing a recharacterization of an existing consolidated-return NOL as a future worthless stock deduction. FirstEnergy currently estimates a future worthless stock deduction of approximately $4.8 billion ($1.0 billion, net of tax) and is net of unrecognized tax benefits of $448 million ($94 million, net of tax). The estimated worthless stock deduction is contingent upon the emergence of the FES Debtors from the FES Bankruptcy and such amounts may be materially impacted by future events. Additionally, the Tax Act amended Section 163(j) of the Code, limiting interest expense deductions for corporations but with exemption for certain regulated utilities. On November 26, 2018, the IRS issued proposed regulations implementing Section 163(j), including application to consolidated groups with both regulated utility and non-regulated members. Based on its interpretation of these proposed regulations, FirstEnergy has estimated the amount of deductible interest for its consolidated group in 2019 and 2018 and has recorded a deferred tax asset on the nondeductible portion as it is carried forward with an indefinite life. However, the deferred tax asset related to the carryforward of nondeductible interest has a full valuation allowance recorded against it as future profitability from sources other than regulated utility businesses is required for utilization. In 2019 and 2018, FirstEnergy recorded tax expense of $54 million and $60 million, respectively, resulting from the valuation allowance, of which $14 million and $27 million has been reflected as an uncertain tax position in 2019 and 2018, respectively. All tax expense related to nondeductible interest in 2019 and 2018 has been recorded in discontinued operations as it is entirely attributed to the inclusion of the FES Debtors in FirstEnergy's consolidated group and therefore, pursuant to the Intercompany Tax Sharing Agreement, has been allocated to the FES Debtors. FE has fully reserved the amount of non-deductible interest allocated to the FES Debtors in connection with the on-going reconciliations under the Intercompany Tax Allocation Agreement with the FES Debtors. See Note 1, "Organization and Basis of Presentation," for further discussion of the settlement among FirstEnergy, the FES Key Creditor Groups, the FES Debtors and the UCC. Competitive Generation Asset Sales FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement with a subsidiary of LS Power Equity Partners III, LP, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply's interest in the Buchanan Generating facility and approximately 59% of AGC's interest in Bath County (1,615 MWs of combined capacity). On December 13, 2017, AE Supply completed the sale of the natural gas generating plants. On March 1, 2018, AE Supply completed the sale of the Buchanan Generating Facility. On May 3, 2018, AE Supply and AGC completed the sale of approximately 59% of AGC's interest in Bath County. Also, on May 3, 2018, following the closing of the sale by AGC of a portion of its ownership interest in Bath County, AGC completed the redemption of AE Supply's shares in AGC and AGC became a wholly owned subsidiary On March 9, 2018, BSPC and FG entered into an asset purchase agreement with Walleye Power, LLC (formerly Walleye Energy, LLC), for the sale of the Bay Shore Generating Facility, including the 136 MW Bay Shore Unit 1 and other retired coal-fired generating equipment owned by FG. The Bankruptcy Court approved the sale on July 13, 2018, and the transaction was completed on July of MP. 31, 2018. As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply operated Pleasants 65 66 The following table represents a disaggregation of revenue from contracts with regulated transmission customers by transmission owner for the years ended December 31, 2019 and 2018 by transmission owner: recognized by FE and was included within the loss from discontinued operations as of December 31, 2018. The FES Debtors have paid approximately $152 million for the shared services for the year ended December 31, 2019. Transmission Owner 2019 2018 For the Years Ended December 31, ATSI TrAIL MAIT Other (In millions) $ 754 242 224 290 664 237 150 284 $ $ Total Revenues 1,510 $ 1,335 3. DISCONTINUED OPERATIONS FES, FENOC, BSPC and a portion of AE Supply (including the Pleasants Power Station), representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, are presented as discontinued operations in FirstEnergy’s consolidated financial statements resulting from the FES Bankruptcy and actions taken as part of the strategic review to exit commodity-exposed generation, as discussed below. Prior period results have been reclassified to conform with such presentation as discontinued operations. FES and FENOC Chapter 11 Bankruptcy Filing As discussed in Note 1, "Organization and Basis of Presentation," on March 31, 2018, FES and FENOC announced the FES Bankruptcy. FirstEnergy concluded that it no longer had a controlling interest in the FES Debtors, as the entities are subject to the jurisdiction of the Bankruptcy Court and, accordingly, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy's consolidated financial statements, and FirstEnergy has accounted and will account for its investments in the FES Debtors at fair values of zero. In connection with the disposal and the FES Bankruptcy settlement agreement approved by the Bankruptcy Court in September 2018, as further discussed in Note 1, "Organization and Basis of Presentation," FE recorded an after-tax gain on disposal of $59 million and $435 million in 2019 and 2018, respectively. By eliminating a significant portion of its competitive generation fleet with the deconsolidation of the FES Debtors, FirstEnergy has concluded the FES Debtors meet the criteria for discontinued operations, as this represents a significant event in management’s strategic review to exit commodity-exposed generation and transition to a fully regulated company. FES Borrowings from FE On March 9, 2018, FES borrowed $500 million from FE under the secured credit facility, dated as of December 6, 2016, among FES, as borrower, FG and NG as guarantors, and FE, as lender, which fully utilized the committed line of credit available under the secured credit facility. Following deconsolidation of FES, FE fully reserved for the $500 million associated with the borrowings under the secured credit facility. Under the terms of the FES Bankruptcy settlement agreement, FE will release any and all claims against the FES Debtors with respect to the $500 million borrowed under the secured credit facility. On March 16, 2018, the FES Debtors withdrew from the unregulated companies' money pool, which included FE, and the FES Debtors. Under the terms of the FES Bankruptcy settlement agreement, FE reinstated $88 million for 2018 estimated payments for NOLs applied against the FES Debtor’s position in the unregulated companies’ money pool prior to their withdrawal on March 16, 2018, which increased the amount the FES Debtors owed FE under the money pool to $92 million. In addition, as of March 31, 2018, AE Supply had a $102 million outstanding unsecured promissory note owed from FES. Following deconsolidation of the FES Debtors on March 31, 2018, and given the terms of the FES Bankruptcy settlement agreement, FE fully reserved the $92 million associated with the outstanding unsecured borrowings under the unregulated companies' money pool and the $102 million associated with the AE Supply unsecured promissory note. Under the terms of the FES Bankruptcy settlement agreement, FirstEnergy will release any and all claims against the FES Debtors with respect to the $92 million owed under the unregulated money pool and $102 million unsecured promissory note. For the years ended December 31, 2019 and 2018, approximately $33 million and $24 million of interest was accrued and subsequently reserved, respectively. Services Agreements Pursuant to the FES Bankruptcy settlement agreement, FirstEnergy entered into an amended and restated shared services agreement with the FES Debtors to extend the availability of shared services until no later than June 30, 2020, subject to reductions in services if requested by the FES Debtors. Under the amended shared services agreement, and consistent with the prior shared services agreements, costs are directly billed or assigned at no more than cost. In addition to providing for certain notice requirements and other terms and conditions, the agreement provided for a credit to the FES Debtors in an amount up to $112.5 million for charges incurred for services provided under prior shared services agreements and the amended shared services agreement from April 1, 2018 through December 31, 2018. The entire credit for shared services provided to the FES Debtors ($112.5 million) has been Benefit Obligations FirstEnergy will retain certain obligations for the FES Debtors' employees for services provided prior to emergence from bankruptcy. The retention of this obligation at March 31, 2018, resulted in a net liability of $820 million (including EDCP, pension and OPEB) with a corresponding loss from discontinued operations. EDCP and pension/OPEB service costs earned by the FES Debtors' employees during bankruptcy are billed under the shared services agreement. As FE continues to provide pension benefits to FES/ FENOC employees, certain components of pension cost, including the mark to market, are seen as providing ongoing services and are reported in the continuing operations of FE, subsequent to the bankruptcy filing. FE has billed the FES Debtors approximately $37 million for their share of pension and OPEB service costs for the year ended December 31, 2019. Purchase Power FES at times provides power through affiliated company power sales to meet a portion of the Utilities' POLR and default service requirements and provides power to certain affiliates' facilities. As of December 31, 2019, the Utilities owed FES approximately $10 million related to these purchases. The terms and conditions of the power purchase agreements are generally consistent with industry practices and other similar third-party arrangements. The Utilities purchased and recognized in continuing operations approximately $171 million and $318 million of power purchases from FES for the years ended December 31, 2019 and 2018, respectively. Income Taxes For U.S. federal income taxes, until emergence from bankruptcy, the FES Debtors will continue to be consolidated in FirstEnergy’s tax return and taxable income will be determined based on the tax basis of underlying individual net assets. Deferred taxes previously recorded on the inside basis differences may not represent the actual tax consequence for the outside basis difference, causing a recharacterization of an existing consolidated-return NOL as a future worthless stock deduction. FirstEnergy currently estimates a future worthless stock deduction of approximately $4.8 billion ($1.0 billion, net of tax) and is net of unrecognized tax benefits of $448 million ($94 million, net of tax). The estimated worthless stock deduction is contingent upon the emergence of the FES Debtors from the FES Bankruptcy and such amounts may be materially impacted by future events. Additionally, the Tax Act amended Section 163(j) of the Code, limiting interest expense deductions for corporations but with exemption for certain regulated utilities. On November 26, 2018, the IRS issued proposed regulations implementing Section 163(j), including application to consolidated groups with both regulated utility and non-regulated members. Based on its interpretation of these proposed regulations, FirstEnergy has estimated the amount of deductible interest for its consolidated group in 2019 and 2018 and has recorded a deferred tax asset on the nondeductible portion as it is carried forward with an indefinite life. However, the deferred tax asset related to the carryforward of nondeductible interest has a full valuation allowance recorded against it as future profitability from sources other than regulated utility businesses is required for utilization. In 2019 and 2018, FirstEnergy recorded tax expense of $54 million and $60 million, respectively, resulting from the valuation allowance, of which $14 million and $27 million has been reflected as an uncertain tax position in 2019 and 2018, respectively. All tax expense related to nondeductible interest in 2019 and 2018 has been recorded in discontinued operations as it is entirely attributed to the inclusion of the FES Debtors in FirstEnergy's consolidated group and therefore, pursuant to the Intercompany Tax Sharing Agreement, has been allocated to the FES Debtors. FE has fully reserved the amount of non-deductible interest allocated to the FES Debtors in connection with the on-going reconciliations under the Intercompany Tax Allocation Agreement with the FES Debtors. See Note 1, "Organization and Basis of Presentation," for further discussion of the settlement among FirstEnergy, the FES Key Creditor Groups, the FES Debtors and the UCC. Competitive Generation Asset Sales FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement with a subsidiary of LS Power Equity Partners III, LP, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply's interest in the Buchanan Generating facility and approximately 59% of AGC's interest in Bath County (1,615 MWs of combined capacity). On December 13, 2017, AE Supply completed the sale of the natural gas generating plants. On March 1, 2018, AE Supply completed the sale of the Buchanan Generating Facility. On May 3, 2018, AE Supply and AGC completed the sale of approximately 59% of AGC's interest in Bath County. Also, on May 3, 2018, following the closing of the sale by AGC of a portion of its ownership interest in Bath County, AGC completed the redemption of AE Supply's shares in AGC and AGC became a wholly owned subsidiary of MP. On March 9, 2018, BSPC and FG entered into an asset purchase agreement with Walleye Power, LLC (formerly Walleye Energy, LLC), for the sale of the Bay Shore Generating Facility, including the 136 MW Bay Shore Unit 1 and other retired coal-fired generating equipment owned by FG. The Bankruptcy Court approved the sale on July 13, 2018, and the transaction was completed on July 31, 2018. As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply operated Pleasants 65 66 until it transferred, which, as discussed above, occurred on January 30, 2020. After closing, AE Supply will continue to provide access to the McElroy's Run CCR Impoundment Facility, which was not transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. FirstEnergy's Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the years ended December 31, 2019, 2018 and 2017: Individually, the AE Supply and BSPC asset sales and Pleasants Power Station transfer did not qualify for reporting as discontinued operations. However, in the aggregate, the transactions were part of management’s strategic review to exit commodity-exposed generation and, when considered with FES' and FENOC’s bankruptcy filings on March 31, 2018, represent a collective elimination of substantially all of FirstEnergy’s competitive generation fleet and meet the criteria for discontinued operations. Summarized Results of Discontinued Operations Summarized results of discontinued operations for the years ended December 31, 2019, 2018, and 2017 were as follows: (In millions) Revenues Fuel Purchased power Other operating expenses Provision for depreciation General taxes Impairment of assets(1) Pleasants economic interest(2) Other expense, net Loss from discontinued operations, before tax Income tax expense (benefit) Loss from discontinued operations, net of tax Gain on disposal of FES and FENOC, net of tax Income (Loss) from discontinued operations For the Years Ended December 31, 2018 (3) 2017 (3) 2019 $ $ 188 (140) — (63) — (14) — 27 (2) (4) 47 (51) 59 8 $ $ 989 (304) (84) (435) (96) (35) — — (83) (48) 61 (109) 435 326 $ $ 3,055 (879) (268) (1,499) (109) (103) (2,358) — (94) (2,255) (820) (1,435) — (1,435) (1) Includes impairment of the FES nuclear facilities, the Pleasants Power Station ($120 million), and the competitive generation asset sale ($193 million). (2) Reflects the estimated amounts owed from FG for its economic interests in Pleasants effective January 1, 2019, as further discussed above. (3) Discontinued operations include results of FES and FENOC through March 31, 2018, when deconsolidated from FirstEnergy's financial statements. The gain on disposal that was recognized in the year ended December 31, 2019 and 2018, consisted of the following: (In millions) For the Years Ended December 31, 2019 2018 Removal of investment in FES and FENOC $ — $ 2,193 Assumption of benefit obligations retained at FE Guarantees and credit support provided by FE Reserve on receivables and allocated pension/OPEB mark-to-market Settlement consideration and services credit Loss on disposal of FES and FENOC, before tax Income tax benefit, including estimated worthless stock deduction Gain on disposal of FES and FENOC, net of tax $ — — — 7 7 52 59 $ (820) (139) (914) (1,197) (877) 1,312 435 As of December 31, 2019 and 2018, materials and supplies of $33 million and $25 million, respectively, are included in FirstEnergy's Consolidated Balance Sheets as Current assets - discontinued operations. 67 68 (In millions) CASH FLOWS FROM OPERATING ACTIVITIES: Income from discontinued operations Gain on disposal, net of tax Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs Deferred income taxes and investment tax credits, net Unrealized (gain) loss on derivative transactions CASH FLOWS FROM INVESTING ACTIVITIES: Property additions Nuclear fuel Sales of investment securities held in trusts Purchases of investment securities held in trusts 4. ACCUMULATED OTHER COMPREHENSIVE INCOME For the Years Ended December 31, 2019 2018 2017 $ 8 $ 326 $ (1,435) (59) (435) — — 47 — — — — — 110 61 (10) (27) — 109 (122) 333 (842) 81 (317) (254) 940 (999) The changes in AOCI for the years ended December 31, 2019, 2018 and 2017, for FirstEnergy are shown in the following table: AOCI Balance, January 1, 2017 $ (28) $ 52 $ 150 $ Gains & Losses on Cash Flow Hedges (1) Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, December 31, 2017 $ (22) $ 67 $ 97 $ Other comprehensive income before reclassifications Amounts reclassified from AOCI Other comprehensive income (loss) Income tax (benefits) on other comprehensive income (loss) Other comprehensive income (loss), net of tax Other comprehensive income before reclassifications Amounts reclassified from AOCI Deconsolidation of FES and FENOC Other comprehensive income (loss) Income tax (benefits) on other comprehensive income (loss) Other comprehensive income (loss), net of tax Other comprehensive income before reclassifications Amounts reclassified from AOCI Other comprehensive income (loss) Income tax (benefits) on other comprehensive income (loss) Other comprehensive income (loss), net of tax — 10 10 4 6 — 8 13 21 10 11 — 2 2 — 2 85 (63) 22 7 15 (97) (1) (8) (106) (39) (67) — — — — — AOCI Balance, December 31, 2018 $ (11) $ — $ 52 $ AOCI Balance, December 31, 2019 $ (9) $ — $ 29 $ (1) Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance. (11) (74) (85) (32) (53) (9) (74) — (83) (38) (45) (2) (29) (31) (8) (23) 174 74 (127) (53) (21) (32) 142 (106) (67) 5 (168) (67) (101) 41 (2) (27) (29) (8) (21) 20 until it transferred, which, as discussed above, occurred on January 30, 2020. After closing, AE Supply will continue to provide access to the McElroy's Run CCR Impoundment Facility, which was not transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. FirstEnergy's Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the years ended December 31, 2019, 2018 and 2017: 2017 2019 For the Years Ended December 31, 2018 $ 8 $ 326 $ (1,435) (59) (435) — — 47 — — — — — 110 61 (10) (27) — 109 (122) 333 (842) 81 (317) (254) 940 (999) (In millions) CASH FLOWS FROM OPERATING ACTIVITIES: Income from discontinued operations Gain on disposal, net of tax Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs Deferred income taxes and investment tax credits, net Unrealized (gain) loss on derivative transactions CASH FLOWS FROM INVESTING ACTIVITIES: Property additions Nuclear fuel Sales of investment securities held in trusts Purchases of investment securities held in trusts 4. ACCUMULATED OTHER COMPREHENSIVE INCOME Individually, the AE Supply and BSPC asset sales and Pleasants Power Station transfer did not qualify for reporting as discontinued operations. However, in the aggregate, the transactions were part of management’s strategic review to exit commodity-exposed generation and, when considered with FES' and FENOC’s bankruptcy filings on March 31, 2018, represent a collective elimination of substantially all of FirstEnergy’s competitive generation fleet and meet the criteria for discontinued operations. Summarized Results of Discontinued Operations Summarized results of discontinued operations for the years ended December 31, 2019, 2018, and 2017 were as follows: (In millions) Revenues Fuel Purchased power Other operating expenses Provision for depreciation General taxes Impairment of assets(1) Pleasants economic interest(2) Other expense, net For the Years Ended December 31, 2019 2018 (3) 2017 (3) $ 188 $ 989 $ 3,055 (140) — (63) — (14) — 27 (2) (4) 47 (51) 59 8 (304) (84) (435) (96) (35) — — (83) (48) 61 (109) 435 326 (879) (268) (1,499) (109) (103) (2,358) — (94) (2,255) (820) (1,435) — Loss from discontinued operations, before tax Income tax expense (benefit) Loss from discontinued operations, net of tax Gain on disposal of FES and FENOC, net of tax Income (Loss) from discontinued operations $ $ $ (1,435) million). (2) Reflects the estimated amounts owed from FG for its economic interests in Pleasants effective January 1, 2019, as further discussed above. (3) Discontinued operations include results of FES and FENOC through March 31, 2018, when deconsolidated from FirstEnergy's financial statements. The gain on disposal that was recognized in the year ended December 31, 2019 and 2018, consisted of the following: (In millions) Removal of investment in FES and FENOC $ — $ 2,193 Assumption of benefit obligations retained at FE Guarantees and credit support provided by FE Reserve on receivables and allocated pension/OPEB mark-to-market Settlement consideration and services credit Loss on disposal of FES and FENOC, before tax Income tax benefit, including estimated worthless stock deduction For the Years Ended December 31, 2019 2018 — — — 7 7 52 59 (820) (139) (914) (1,197) (877) 1,312 435 Consolidated Balance Sheets as Current assets - discontinued operations. The changes in AOCI for the years ended December 31, 2019, 2018 and 2017, for FirstEnergy are shown in the following table: Gains & Losses on Cash Flow Hedges (1) Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) (1) Includes impairment of the FES nuclear facilities, the Pleasants Power Station ($120 million), and the competitive generation asset sale ($193 AOCI Balance, January 1, 2017 $ (28) $ 52 $ 150 $ Other comprehensive income before reclassifications Amounts reclassified from AOCI Other comprehensive income (loss) Income tax (benefits) on other comprehensive income (loss) Other comprehensive income (loss), net of tax — 10 10 4 6 85 (63) 22 7 15 (11) (74) (85) (32) (53) AOCI Balance, December 31, 2017 $ (22) $ 67 $ 97 $ Other comprehensive income before reclassifications Amounts reclassified from AOCI Deconsolidation of FES and FENOC Other comprehensive income (loss) Income tax (benefits) on other comprehensive income (loss) Other comprehensive income (loss), net of tax — 8 13 21 10 11 (97) (1) (8) (106) (39) (67) (9) (74) — (83) (38) (45) Gain on disposal of FES and FENOC, net of tax $ $ AOCI Balance, December 31, 2018 $ (11) $ — $ 52 $ As of December 31, 2019 and 2018, materials and supplies of $33 million and $25 million, respectively, are included in FirstEnergy's Other comprehensive income before reclassifications Amounts reclassified from AOCI Other comprehensive income (loss) Income tax (benefits) on other comprehensive income (loss) Other comprehensive income (loss), net of tax — 2 2 — 2 — — — — — (2) (29) (31) (8) (23) 67 68 AOCI Balance, December 31, 2019 $ (9) $ — $ 29 $ (1) Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance. 174 74 (127) (53) (21) (32) 142 (106) (67) 5 (168) (67) (101) 41 (2) (27) (29) (8) (21) 20 The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2019, 2018 and 2017: FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2019, FirstEnergy’s pension and OPEB plan assets experienced gains of $1,492 million, or 20.2%, compared to losses of $371 million, or (4.0)%, in 2018 and gains of $999 million, or 15.1%, in 2017, and assumed a 7.50% rate of return for 2019, 2018 and 2017 which generated $569 million, $605 million and $478 million of expected returns on plan assets, respectively. The expected return on pension and OPEB assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets will decrease or increase future net periodic pension and OPEB cost as the difference is recognized annually in the fourth quarter of each fiscal year or whenever a plan is determined to qualify for remeasurement. During 2019, the Society of Actuaries published new mortality tables that include more current data than the RP-2014 tables as well as new improvement scales. An analysis of FirstEnergy pension and OPEB plan mortality data indicated the use of the Pri-2012 mortality table with projection scale MP-2019 was most appropriate. As such, the Pri-2012 mortality table with projection scale MP-2019 was utilized to determine the 2019 benefit cost and obligation as of December 31, 2019 for the FirstEnergy pension and OPEB plans. The impact of using the Pri-2012 mortality table with projection scale MP-2019 resulted in a decrease to the projected benefit obligation approximately $29 million and $3 million for the pension and OPEB plans, respectively, and was included in the 2019 pension and OPEB mark-to-market adjustment. Effective in 2019, FirstEnergy changed the approach utilized to estimate the service cost and interest cost components of net periodic benefit cost for pension and OPEB plans. Historically, FirstEnergy estimated these components utilizing a single, weighted average discount rate derived from the yield curve used to measure the benefit obligation. FirstEnergy has elected to use a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows, as this provides a better estimate of service and interest costs by improving the correlation between projected benefit cash flows to the corresponding spot yield curve rates. This election is considered a change in estimate and, accordingly, accounted for prospectively, and did not have a material impact on FirstEnergy's financial statements. Following adoption of ASU 2017-07, "Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" in 2018, service costs, net of capitalization, continue to be reported within Other operating expenses on the FirstEnergy Consolidated Statements of Income (Loss). Non-service costs are reported within Miscellaneous income, net, within Other Income (Expense). Reclassifications from AOCI (1) Gains & losses on cash flow hedges Commodity contracts Long-term debt Year Ended December 31, 2018 (2) 2017 2019 Affected Line Item in Consolidated Statements of Income (Loss) (In millions) $ — $ 2 — 2 $ 1 7 (2) $ 2 Other operating expenses 8 Interest expense (4) Income taxes $ 6 $ 6 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ — $ (1) $ (40) Discontinued operations Defined benefit pension and OPEB plans Prior-service costs $ $ (29) $ (74) $ (74) (3) 8 19 28 Income taxes (21) $ (55) $ (46) Net of tax (1) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. (2) Includes stranded tax amounts reclassified from AOCI in connection with the adoption of ASU 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income". (3) Prior-service costs are reported within Miscellaneous income, net within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income (Loss). Components are included in the computation of net periodic cost (credits), see Note 5, "Pension and Other Postemployment Benefits," for additional details. 5. PENSION AND OTHER POSTEMPLOYMENT BENEFITS FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non- qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. Under the cash-balance portion of the Pension Plan (for employees hired on or after January 1, 2014), FirstEnergy makes contributions to eligible employee retirement accounts based on a pay credit and an interest credit. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits. FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The remaining components of pension and OPEB expense, primarily service costs, interest on obligations, assumed return on assets and prior service costs, are recorded on a monthly basis. The pension and OPEB mark-to-market adjustment for the years ended December 31, 2019, 2018, and 2017 were $676 million, $145 million, and $141 million, respectively. Of these amounts, approximately $2 million, $1 million, and $39 million, are included in discontinued operations for the years ended December 31, 2019, 2018, and 2017, respectively. In 2019, the pension and OPEB mark-to-market adjustment primarily reflects a 110 bps decrease in the discount rate used to measure benefit obligations and higher than expected asset returns. FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. In January 2018, FirstEnergy satisfied its minimum required funding obligations to its qualified pension plan of $500 million and addressed anticipated required funding obligations through 2020 to its pension plan with an additional contribution of $750 million. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. FirstEnergy expects no required contributions through 2021. Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of the measurement date. 69 70 FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2019, FirstEnergy’s pension and OPEB plan assets experienced gains of $1,492 million, or 20.2%, compared to losses of $371 million, or (4.0)%, in 2018 and gains of $999 million, or 15.1%, in 2017, and assumed a 7.50% rate of return for 2019, 2018 and 2017 which generated $569 million, $605 million and $478 million of expected returns on plan assets, respectively. The expected return on pension and OPEB assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets will decrease or increase future net periodic pension and OPEB cost as the difference is recognized annually in the fourth quarter of each fiscal year or whenever a plan is determined to qualify for remeasurement. During 2019, the Society of Actuaries published new mortality tables that include more current data than the RP-2014 tables as well as new improvement scales. An analysis of FirstEnergy pension and OPEB plan mortality data indicated the use of the Pri-2012 mortality table with projection scale MP-2019 was most appropriate. As such, the Pri-2012 mortality table with projection scale MP-2019 was utilized to determine the 2019 benefit cost and obligation as of December 31, 2019 for the FirstEnergy pension and OPEB plans. The impact of using the Pri-2012 mortality table with projection scale MP-2019 resulted in a decrease to the projected benefit obligation approximately $29 million and $3 million for the pension and OPEB plans, respectively, and was included in the 2019 pension and OPEB mark-to-market adjustment. Effective in 2019, FirstEnergy changed the approach utilized to estimate the service cost and interest cost components of net periodic benefit cost for pension and OPEB plans. Historically, FirstEnergy estimated these components utilizing a single, weighted average discount rate derived from the yield curve used to measure the benefit obligation. FirstEnergy has elected to use a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows, as this provides a better estimate of service and interest costs by improving the correlation between projected benefit cash flows to the corresponding spot yield curve rates. This election is considered a change in estimate and, accordingly, accounted for prospectively, and did not have a material impact on FirstEnergy's financial statements. Following adoption of ASU 2017-07, "Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" in 2018, service costs, net of capitalization, continue to be reported within Other operating expenses on the FirstEnergy Consolidated Statements of Income (Loss). Non-service costs are reported within Miscellaneous income, net, within Other Income (Expense). The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2019, 2018 and 2017: Reclassifications from AOCI (1) Year Ended December 31, 2019 2018 (2) Affected Line Item in Consolidated 2017 Statements of Income (Loss) Gains & losses on cash flow hedges Commodity contracts Long-term debt $ — $ $ 2 Other operating expenses (In millions) 1 7 (2) 2 — 2 8 Interest expense (4) Income taxes $ 6 $ 6 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ — $ (1) $ (40) Discontinued operations Defined benefit pension and OPEB plans Prior-service costs (29) $ (74) $ (74) (3) 8 19 28 Income taxes (21) $ (55) $ (46) Net of tax $ $ $ (1) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. (2) Includes stranded tax amounts reclassified from AOCI in connection with the adoption of ASU 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income". (3) Prior-service costs are reported within Miscellaneous income, net within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income (Loss). Components are included in the computation of net periodic cost (credits), see Note 5, "Pension and Other Postemployment Benefits," for additional details. 5. PENSION AND OTHER POSTEMPLOYMENT BENEFITS FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non- qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. Under the cash-balance portion of the Pension Plan (for employees hired on or after January 1, 2014), FirstEnergy makes contributions to eligible employee retirement accounts based on a pay credit and an interest credit. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits. FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The remaining components of pension and OPEB expense, primarily service costs, interest on obligations, assumed return on assets and prior service costs, are recorded on a monthly basis. The pension and OPEB mark-to-market adjustment for the years ended December 31, 2019, 2018, and 2017 were $676 million, $145 million, and $141 million, respectively. Of these amounts, approximately $2 million, $1 million, and $39 million, are included in discontinued operations for the years ended December 31, 2019, 2018, and 2017, respectively. In 2019, the pension and OPEB mark-to-market adjustment primarily reflects a 110 bps decrease in the discount rate used to measure benefit obligations and higher than expected asset returns. FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. In January 2018, FirstEnergy satisfied its minimum required funding obligations to its qualified pension plan of $500 million and addressed anticipated required funding obligations through 2020 to its pension plan with an additional contribution of $750 million. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. FirstEnergy expects no required contributions through 2021. Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of the measurement date. 69 70 Obligations and Funded Status - Qualified and Non-Qualified Plans 2019 2018 2019 2018 Pension OPEB Components of Net Periodic Benefit Costs for the Years Ended December 31, 2019 2018 2017 2019 2017 OPEB 2018 Pension Service cost Interest cost Expected return on plan assets Amortization of prior service costs (credits) Special termination costs (1) Pension & OPEB mark-to-market adjustment Net periodic benefit costs (credits) (In millions) $ 3 $ 5 $ $ $ 193 373 (540) 7 14 656 703 $ $ 224 372 (574) 7 31 227 287 $ $ 208 390 (448) 7 — 108 265 22 (29) (36) — 20 25 (31) (81) 8 (82) 5 27 (30) (81) — 13 $ (20) $ (156) $ (66) (1) Subject to a cap, FirstEnergy has agreed to fund a pension enhancement through its pension plan, for voluntary enhanced retirement packages offered to certain FES employees, as well as offer certain other employee benefits (approximately $14 million recognized for the year ended December 31, 2019). Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31,* Weighted-average discount rate Expected long-term return on plan assets Rate of compensation increase Pension 2019 2018 2017 2019 4.44% 7.50% 4.10% 3.75% 7.50% 4.20% 4.25% 7.50% 4.20% 4.30% 7.50% N/A OPEB 2018 3.50% 7.50% N/A 2017 4.00% 7.50% N/A *Excludes impact of pension and OPEB mark-to-market adjustment. Amounts in the tables above include FES Debtors' share of the net periodic pension and OPEB costs (credits) of $242 million and $(19) million, respectively, for the year ended December 31, 2019. The FES Debtors' share of the net periodic pension and OPEB costs (credits) were $64 million and $(25) million, respectively, for the year ended December 31, 2018, and $60 million and $(17) million, respectively, for the year ended December 31, 2017. The 2019 special termination costs associated with FES' voluntary enhanced retirement package are a component of Discontinued operations in FirstEnergy's Consolidated Statements of Income (Loss). Following the FES Debtors’ voluntary bankruptcy filing, FE has billed the FES Debtors approximately $37 million and $42 million for their share of pension and OPEB service costs for the years ended December 31, 2019 and 2018, respectively. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed rates of return on plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy. Change in benefit obligation: Benefit obligation as of January 1 Service cost Interest cost Plan participants’ contributions Plan amendments Special termination benefits Medicare retiree drug subsidy Annuity purchase Actuarial (gain) loss Benefits paid Benefit obligation as of December 31 Change in fair value of plan assets: Fair value of plan assets as of January 1 Actual return on plan assets Annuity purchase Company contributions Plan participants’ contributions Benefits paid Fair value of plan assets as of December 31 Funded Status: Qualified plan Non-qualified plans Funded Status (Net liability as of December 31) Accumulated benefit obligation Amounts Recognized in AOCI: Prior service cost (credit) (In millions) $ 9,462 $ 10,167 $ 608 $ 193 373 — 2 14 — — 1,535 (529) 11,050 6,984 1,419 — 521 — (529) 8,395 (2,203) (452) (2,655) 10,439 24 $ $ $ $ $ $ $ $ $ $ $ $ $ $ 224 372 — 5 31 — (129) (710) (498) 9,462 6,704 (363) (129) 1,270 — (498) 6,984 (2,093) (385) (2,478) 8,951 30 $ $ $ $ $ $ $ 3 22 4 — — 1 — 64 (48) 654 408 73 — 21 4 (48) 458 $ $ $ — $ — (196) $ 731 5 25 3 5 8 1 — (121) (49) 608 439 (8) — 22 3 (48) 408 — — (200) — $ — (85) $ (121) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate Rate of compensation increase Cash balance weighted average interest crediting rate Assumed Health Care Cost Trend Rates (as of December 31) Health care cost trend rate assumed (pre/post-Medicare) Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) Year that the rate reaches the ultimate trend rate Allocation of Plan Assets (as of December 31) Equity securities Fixed Income Hedge funds Insurance-linked securities Real estate funds Derivatives Private equity funds Cash and short-term securities Total 3.34% 4.10% 2.57% 4.44% 4.10% 3.34% 3.18% N/A N/A 4.30% N/A N/A N/A N/A N/A 29% 36% 9% 2% 7% —% 4% 13% 100% N/A N/A N/A 34% 34% 11% 2% 10% 2% 2% 5% 100% 6.0-5.5% 6.0-5.5% 4.5% 2028 54% 30% —% —% —% —% —% 16% 100% 4.5% 2028 48% 35% —% —% —% —% —% 17% 100% 71 72 Components of Net Periodic Benefit Costs for the Years Ended December 31, Service cost Interest cost Expected return on plan assets Amortization of prior service costs (credits) Special termination costs (1) Pension & OPEB mark-to-market adjustment Net periodic benefit costs (credits) Pension 2019 2018 2017 2019 (In millions) OPEB 2018 2017 $ $ 193 373 (540) 7 14 656 703 $ $ 224 372 (574) 7 31 227 287 $ $ 208 390 (448) 7 — 108 265 $ 3 $ 5 $ 22 (29) (36) — 20 25 (31) (81) 8 (82) 5 27 (30) (81) — 13 $ (20) $ (156) $ (66) (1) Subject to a cap, FirstEnergy has agreed to fund a pension enhancement through its pension plan, for voluntary enhanced retirement packages offered to certain FES employees, as well as offer certain other employee benefits (approximately $14 million recognized for the year ended December 31, 2019). Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31,* Weighted-average discount rate Expected long-term return on plan assets Rate of compensation increase Pension 2019 2018 2017 2019 4.44% 7.50% 4.10% 3.75% 7.50% 4.20% 4.25% 7.50% 4.20% 4.30% 7.50% N/A OPEB 2018 3.50% 7.50% N/A 2017 4.00% 7.50% N/A *Excludes impact of pension and OPEB mark-to-market adjustment. Amounts in the tables above include FES Debtors' share of the net periodic pension and OPEB costs (credits) of $242 million and $(19) million, respectively, for the year ended December 31, 2019. The FES Debtors' share of the net periodic pension and OPEB costs (credits) were $64 million and $(25) million, respectively, for the year ended December 31, 2018, and $60 million and $(17) million, respectively, for the year ended December 31, 2017. The 2019 special termination costs associated with FES' voluntary enhanced retirement package are a component of Discontinued operations in FirstEnergy's Consolidated Statements of Income (Loss). Following the FES Debtors’ voluntary bankruptcy filing, FE has billed the FES Debtors approximately $37 million and $42 million for their share of pension and OPEB service costs for the years ended December 31, 2019 and 2018, respectively. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed rates of return on plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy. Obligations and Funded Status - Qualified and Non-Qualified Plans 2019 2018 2019 2018 Pension OPEB (In millions) $ 9,462 $ 10,167 $ 608 $ Change in benefit obligation: Benefit obligation as of January 1 Service cost Interest cost Plan participants’ contributions Plan amendments Special termination benefits Medicare retiree drug subsidy Annuity purchase Actuarial (gain) loss Benefits paid Benefit obligation as of December 31 Change in fair value of plan assets: Fair value of plan assets as of January 1 Actual return on plan assets Annuity purchase Company contributions Plan participants’ contributions Benefits paid Fair value of plan assets as of December 31 Funded Status: Qualified plan Non-qualified plans Funded Status (Net liability as of December 31) Amounts Recognized in AOCI: Prior service cost (credit) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate Rate of compensation increase Cash balance weighted average interest crediting rate Assumed Health Care Cost Trend Rates (as of December 31) Health care cost trend rate assumed (pre/post-Medicare) Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) Year that the rate reaches the ultimate trend rate Allocation of Plan Assets (as of December 31) Equity securities Fixed Income Hedge funds Insurance-linked securities Real estate funds Derivatives Private equity funds Cash and short-term securities Total 193 373 — 2 14 — — 1,535 (529) 11,050 6,984 1,419 — 521 — (529) 8,395 (2,203) (452) (2,655) $ $ $ $ $ $ $ $ $ $ $ $ $ $ 224 372 — 5 31 — (129) (710) (498) 9,462 6,704 (363) (129) 1,270 — (498) 6,984 (2,093) (385) (2,478) $ $ $ $ $ $ $ 3 22 4 — — 1 — 64 (48) 654 408 73 — 21 4 (48) 458 $ $ $ 731 5 25 3 5 8 1 — (121) (49) 608 439 (8) — 22 3 (48) 408 — — — — $ — (196) $ (200) 24 30 (85) $ (121) 3.34% 4.10% 2.57% 4.44% 4.10% 3.34% 3.18% N/A N/A 4.30% N/A N/A N/A N/A N/A 29% 36% 9% 2% 7% —% 4% 13% N/A N/A N/A 34% 34% 11% 2% 10% 2% 2% 5% 6.0-5.5% 6.0-5.5% 4.5% 2028 4.5% 2028 54% 30% —% —% —% —% —% 16% 48% 35% —% —% —% —% —% 17% 100% 100% 100% 100% Accumulated benefit obligation 10,439 8,951 — $ 71 72 (1) Excludes $176 million as of December 31, 2019, of receivables, payables, taxes and accrued income associated with financial instruments Cash and short-term securities $ — $ 71 $ — $ 71 reflected within the fair value table. (2) Net Asset Value used as a practical expedient to approximate fair value. (3) Includes insurance annuities, bank loans and emerging markets debt. December 31, 2018 Level 1 Level 2 Level 3 Total Asset Allocation (In millions) Mortgage-backed securities (non-government) Cash and short-term securities $ — $ 342 $ — $ The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 10, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2019 and 2018. December 31, 2019 Level 1 Level 2 Level 3 Total Asset Allocation (In millions) Cash and short-term securities $ — $ 1,069 $ — $ 1,532 828 — — 2,064 880 (40) — — — — — $ 1,492 $ 4,841 $ — $ 6,333 342 186 774 584 $ 8,219 100% 1,115 1,256 — — — 59 1,674 667 108 — — — — — — $ 1,223 $ 3,998 $ — $ (1) Excludes $68 million as of December 31, 2018, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (2) Net asset value used as a practical expedient to approximate fair value. (3) The classification of Level 2 and 3 assets from the prior year, $779 million and $665 million, respectively, was adjusted in the current year presentation and included outside of the fair value hierarchy table as of December 31, 2018, as investments for which Net Asset Value is used as a practical expedient to approximate fair value in accordance with ASU 2015-07 "Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)". Includes insurance annuities, bank loans and emerging markets debt. (4) $ 6,916 100% Equities Fixed income: Corporate bonds Other(3) Alternatives: Derivatives Total (1) Private equity funds (2) Insurance-linked securities (2) Hedge funds (2) Real estate funds (2) Total Investments Equities Fixed income: Government bonds Corporate bonds Other(4) Alternatives: Derivatives Total (1) Private equity funds (2) Insurance-linked securities (2) Hedge funds (3) Real estate funds (3) Total Investments 1,069 2,360 2,064 880 (40) 13% 29% 25% 11% —% 78% 4% 2% 9% 7% As of December 31, 2019 and 2018, the OPEB trust investments measured at fair value were as follows: Cash and short-term securities $ — $ 72 $ — $ 72 Mortgage-backed securities (non-government) (1) Excludes $1 million as of December 31, 2019, of receivables, payables, taxes and accrued income associated with financial instruments reflected $ 246 $ 211 $ — $ 457 December 31, 2019 Level 1 Level 2 Level 3 Total Asset Allocation (In millions) 246 — — 196 — — — 100 34 5 — 107 32 4 — — — — — — — — 246 100 34 5 196 107 32 4 December 31, 2018 Level 1 Level 2 Level 3 Total Asset Allocation (In millions) 16% 54% 22% 7% 1% 100% 17% 48% 26% 8% 1% 100% Equity investment: Domestic Fixed income: Government bonds Corporate bonds Total (1) within the fair value table. Equity investment: Domestic Fixed income: Government bonds Corporate bonds Total (1) within the fair value table. Target Asset Allocations 2019 2018 Equities Fixed income Hedge funds Real estate Alternative investments Cash 38% 30% 8% 10% 8% 6% 38% 30% 8% 10% 8% 6% 100% 100% 342 2,371 59 1,674 667 108 5,221 143 108 779 665 5% 34% 1% 23% 10% 2% 75% 2% 2% 11% 10% (1) Excludes $(2) million as of December 31, 2018, of receivables, payables, taxes and accrued income associated with financial instruments reflected $ 196 $ 214 $ — $ 410 FirstEnergy follows a total return investment approach using a mix of equities, fixed income and other available investments while taking into account the pension plan liabilities to optimize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate and private equity are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements and periodic asset/liability studies. FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2019 and 2018 are shown in the following table: 73 74 As of December 31, 2019 and 2018, the OPEB trust investments measured at fair value were as follows: December 31, 2019 Level 1 Level 2 Level 3 Total Asset Allocation (In millions) Cash and short-term securities $ — $ 72 $ — $ 72 Equity investment: Domestic Fixed income: Government bonds Corporate bonds Mortgage-backed securities (non-government) 246 — — — 100 34 5 — — — — 246 100 34 5 16% 54% 22% 7% 1% Total (1) 100% (1) Excludes $1 million as of December 31, 2019, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. — $ 457 246 211 $ $ $ $ 8,219 100% December 31, 2018 Level 1 Level 2 Level 3 Total Asset Allocation (In millions) (1) Excludes $176 million as of December 31, 2019, of receivables, payables, taxes and accrued income associated with financial instruments Cash and short-term securities $ — $ 71 $ — $ 71 Equity investment: Domestic Fixed income: Government bonds Corporate bonds Mortgage-backed securities (non-government) 196 — — — 107 32 4 — — — — 196 107 32 4 17% 48% 26% 8% 1% The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 10, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2019 and 2018. Cash and short-term securities $ — $ 1,069 $ — $ Level 1 Level 2 Level 3 Total Asset Allocation December 31, 2019 (In millions) 1,532 828 — — 2,064 880 (40) — $ 1,492 $ 4,841 $ — $ 6,333 reflected within the fair value table. (2) Net Asset Value used as a practical expedient to approximate fair value. (3) Includes insurance annuities, bank loans and emerging markets debt. Cash and short-term securities $ — $ 342 $ — $ Level 1 Level 2 Level 3 Total Asset Allocation December 31, 2018 (In millions) 1,115 1,256 — — — 59 1,674 667 108 — $ 1,223 $ 3,998 $ — $ — — — — — — — — — 1,069 2,360 2,064 880 (40) 342 186 774 584 342 2,371 59 1,674 667 108 5,221 143 108 779 665 13% 29% 25% 11% —% 78% 4% 2% 9% 7% 5% 34% 1% 23% 10% 2% 75% 2% 2% 11% 10% Equities Fixed income: Corporate bonds Other(3) Alternatives: Derivatives Total (1) Private equity funds (2) Insurance-linked securities (2) Hedge funds (2) Real estate funds (2) Total Investments Equities Fixed income: Government bonds Corporate bonds Other(4) Alternatives: Derivatives Total (1) Private equity funds (2) Insurance-linked securities (2) Hedge funds (3) Real estate funds (3) Total Investments FirstEnergy follows a total return investment approach using a mix of equities, fixed income and other available investments while taking into account the pension plan liabilities to optimize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate and private equity are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements and periodic asset/liability studies. FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2019 and 2018 are shown in the following table: (1) Excludes $68 million as of December 31, 2018, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (2) Net asset value used as a practical expedient to approximate fair value. The classification of Level 2 and 3 assets from the prior year, $779 million and $665 million, respectively, was adjusted in the current year presentation and included outside of the fair value hierarchy table as of December 31, 2018, as investments for which Net Asset Value is used as a practical expedient to approximate fair value in accordance with ASU 2015-07 "Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)". Includes insurance annuities, bank loans and emerging markets debt. (3) (4) Equities Fixed income Hedge funds Real estate Alternative investments Cash 38% 30% 8% 10% 8% 6% 38% 30% 8% 10% 8% 6% 100% 100% $ 6,916 100% Target Asset Allocations 2019 2018 73 74 Total (1) 100% (1) Excludes $(2) million as of December 31, 2018, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. — $ 410 196 214 $ $ $ Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contributions: performance metric consisting of a relative total shareholder return modifier utilizing the S&P 500 Utility Index as a comparator group. The estimated grant date fair value for these awards is calculated using the Monte Carlo simulation method. Pension OPEB Subsidy Receipts Benefit Payments (In millions) $ 2020 2021 2022 2023 2024 Years 2025-2029 $ 547 564 573 586 593 3,099 $ 52 49 48 47 46 208 (1) (1) (1) (1) (1) (3) 6. STOCK-BASED COMPENSATION PLANS FirstEnergy grants stock-based awards through the ICP 2015, primarily in the form of restricted stock and performance-based restricted stock units. Under FirstEnergy's previous incentive compensation plan, the ICP 2007, FirstEnergy also granted stock options and performance shares. The ICP 2007 and ICP 2015 include shareholder authorization to issue 29 million shares and 10 million shares, respectively, of common stock or their equivalent. As of December 31, 2019, approximately 3.9 million shares were available for future grants under the ICP 2015 assuming maximum performance metrics are achieved for the outstanding cycles of restricted stock units. No shares are available for future grants under the ICP 2007. Shares not issued due to forfeitures or cancellations may be added back to the ICP 2015. Shares granted under the ICP 2007 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods for stock-based awards range from one to ten years, with the majority of awards having a vesting period of three years. FirstEnergy also issues stock through its 401(k) Savings Plan, EDCP, and DCPD. Currently, FirstEnergy records the compensation costs for stock-based compensation awards that will be paid in stock over the vesting period based on the fair value on the grant date. FirstEnergy accounts for forfeitures as they occur. FirstEnergy adjusts the compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or settled. Actual income tax benefits realized during the years ended December 31, 2019, 2018 and 2017, were $24 million, $15 million and $15 million, respectively. The income tax effects of awards are recognized in the income statement when the awards vest, are settled or are forfeited. Stock-based compensation costs and the amount of stock-based compensation costs capitalized related to FirstEnergy plans for the years ended December 31, 2019, 2018 and 2017 are included in the following tables: For the Years Ended December 31, Restricted stock units payable in cash provide the participant the right to receive cash based on the number of stock units set forth in the agreement and value of the equivalent number of shares of FE common stock as of the vesting date. The cash portion of the restricted stock unit award is considered a liability award, which is remeasured each period based on FE's stock price and projected performance adjustments. The liability recorded for the portion of performance-based restricted stock units payable in cash in the future as of December 31, 2019, was $46 million. During 2019, approximately $44 million was paid in relation to the cash portion of restricted stock unit obligations that vested in 2019. The vesting period for the performance-based restricted stock unit awards granted in 2017, 2018 and 2019, were each three years. Dividend equivalents are received on the restricted stock units and are reinvested in additional restricted stock units and subject to the same performance conditions as the underlying award. Restricted stock unit activity for the year ended December 31, 2019, was as follows: Restricted Stock Unit Activity Nonvested as of January 1, 2019 Granted in 2019 Forfeited in 2019 Vested in 2019(1) Nonvested as of December 31, 2019 Shares (in millions) Weighted- Average Grant Date Fair Value (per share) $ 3.3 1.9 (0.4) (2.2) 2.6 $ 33.78 41.23 37.23 40.73 36.20 (1) Excludes dividend equivalents of approximately 636 thousand shares earned during vesting period. The weighted-average fair value of awards granted in 2019, 2018 and 2017 was $41.23, $36.78 and $31.71 per share, respectively. For the years ended December 31, 2019, 2018, and 2017, the fair value of restricted stock units vested was $91 million, $62 million, and $42 million, respectively. As of December 31, 2019, there was approximately $31 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted for restricted stock units, which is expected to be recognized over a period of approximately three years. Certain employees receive awards of FE restricted stock (as opposed to "units" with the right to receive shares at the end of the restriction period) subject to restrictions that lapse over a defined period of time or upon achieving performance results. The fair value of restricted stock is measured based on the average of the high and low prices of FE common stock on the date of grant. Dividends are received on the restricted stock and are reinvested in additional shares of restricted stock, subject to the vesting conditions of the underlying award. Restricted stock activity for the year ended December 31, 2019, was not material. Restricted Stock Stock Options Stock options have been granted to certain employees allowing them to purchase a specified number of common shares at a fixed exercise price over a defined period of time. Stock options generally expire ten years from the date of grant. There were no stock options granted in 2019. Stock option activity for the year ended December 31, 2019 was as follows: Stock Option Activity Balance, January 1, 2019 (all options exercisable) Options exercised Options forfeited Balance, December 31, 2019 (all options exercisable) Number of Shares (in millions) Weighted Average Exercise Price (per share) 0.8 $ (0.6) (0.1) 0.1 $ 37.37 37.26 37.72 37.75 Approximately $23 million and $12 million of cash was received from the exercise of stock options in 2019 and 2018, respectively. There was no cash received from the exercise of stock options in 2017. The weighted-average remaining contractual term of options outstanding as of December 31, 2019, was 2.16 years. There was no stock option expense for the years ended December 31, 2019, 2018 and 2017. Income tax benefits associated with stock-based compensation plan expense were $10 million, $18 million and $10 million for the years ended December 31, 2019, 2018 and 2017, respectively. Restricted Stock Units Beginning with the performance-based restricted stock units granted in 2015, two-thirds of each award will be paid in stock and one-third will be paid in cash. Restricted stock units payable in stock provide the participant the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of stock units set forth in the agreement, subject to adjustment based on FirstEnergy's performance relative to financial and operational performance targets applicable to each award. The grant date fair value of the stock portion of the restricted stock unit award is measured based on the average of the high and low prices of FE common stock on the date of grant. Beginning with awards granted in 2018, restricted stock units include a 75 76 Restricted Stock Units Restricted Stock 401(k) Savings Plan EDCP & DCPD Total Stock-based compensation costs capitalized $ $ $ 2017 2018 (In millions) 102 $ $ 1 33 7 73 1 33 9 Stock-based Compensation Plan 2019 116 54 $ $ 143 60 $ $ 49 1 42 6 98 37 Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contributions: performance metric consisting of a relative total shareholder return modifier utilizing the S&P 500 Utility Index as a comparator group. The estimated grant date fair value for these awards is calculated using the Monte Carlo simulation method. Pension OPEB Subsidy Receipts Benefit Payments (In millions) $ $ $ 547 564 573 586 593 3,099 52 49 48 47 46 208 (1) (1) (1) (1) (1) (3) 2020 2021 2022 2023 2024 Years 2025-2029 Restricted stock units payable in cash provide the participant the right to receive cash based on the number of stock units set forth in the agreement and value of the equivalent number of shares of FE common stock as of the vesting date. The cash portion of the restricted stock unit award is considered a liability award, which is remeasured each period based on FE's stock price and projected performance adjustments. The liability recorded for the portion of performance-based restricted stock units payable in cash in the future as of December 31, 2019, was $46 million. During 2019, approximately $44 million was paid in relation to the cash portion of restricted stock unit obligations that vested in 2019. The vesting period for the performance-based restricted stock unit awards granted in 2017, 2018 and 2019, were each three years. Dividend equivalents are received on the restricted stock units and are reinvested in additional restricted stock units and subject to the same performance conditions as the underlying award. Restricted stock unit activity for the year ended December 31, 2019, was as follows: Shares (in millions) Weighted- Average Grant Date Fair Value (per share) 33.78 41.23 37.23 40.73 36.20 $ 3.3 1.9 (0.4) (2.2) $ (1) Excludes dividend equivalents of approximately 636 thousand shares earned during vesting period. 2.6 Restricted Stock Unit Activity Nonvested as of January 1, 2019 Granted in 2019 Forfeited in 2019 Vested in 2019(1) Nonvested as of December 31, 2019 6. STOCK-BASED COMPENSATION PLANS FirstEnergy grants stock-based awards through the ICP 2015, primarily in the form of restricted stock and performance-based restricted stock units. Under FirstEnergy's previous incentive compensation plan, the ICP 2007, FirstEnergy also granted stock options and performance shares. The ICP 2007 and ICP 2015 include shareholder authorization to issue 29 million shares and 10 million shares, respectively, of common stock or their equivalent. As of December 31, 2019, approximately 3.9 million shares were available for future grants under the ICP 2015 assuming maximum performance metrics are achieved for the outstanding cycles of restricted stock units. No shares are available for future grants under the ICP 2007. Shares not issued due to forfeitures or cancellations may be added back to the ICP 2015. Shares granted under the ICP 2007 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods for stock-based awards range from one to ten years, with the majority of awards having a vesting period of three years. FirstEnergy also issues stock through its 401(k) Savings Plan, EDCP, and DCPD. Currently, FirstEnergy records the compensation costs for stock-based compensation awards that will be paid in stock over the vesting period based on the fair value on the grant date. FirstEnergy accounts for forfeitures as they occur. FirstEnergy adjusts the compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or settled. Actual income tax benefits realized during the years ended December 31, 2019, 2018 and 2017, were $24 million, $15 million and $15 million, respectively. The income tax effects of awards are recognized in the income statement when the awards vest, are settled or are forfeited. Stock-based compensation costs and the amount of stock-based compensation costs capitalized related to FirstEnergy plans for the years ended December 31, 2019, 2018 and 2017 are included in the following tables: Stock-based Compensation Plan Restricted Stock Units Restricted Stock 401(k) Savings Plan EDCP & DCPD Total Stock-based compensation costs capitalized For the Years Ended December 31, 2019 2018 2017 (In millions) $ 73 $ 102 $ 1 33 9 1 33 7 $ $ 116 54 $ $ 143 60 $ $ 49 1 42 6 98 37 There was no stock option expense for the years ended December 31, 2019, 2018 and 2017. Income tax benefits associated with stock-based compensation plan expense were $10 million, $18 million and $10 million for the years ended December 31, 2019, 2018 and 2017, respectively. Restricted Stock Units Beginning with the performance-based restricted stock units granted in 2015, two-thirds of each award will be paid in stock and one-third will be paid in cash. Restricted stock units payable in stock provide the participant the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of stock units set forth in the agreement, subject to adjustment based on FirstEnergy's performance relative to financial and operational performance targets applicable to each award. The grant date fair value of the stock portion of the restricted stock unit award is measured based on the average of the high and low prices of FE common stock on the date of grant. Beginning with awards granted in 2018, restricted stock units include a The weighted-average fair value of awards granted in 2019, 2018 and 2017 was $41.23, $36.78 and $31.71 per share, respectively. For the years ended December 31, 2019, 2018, and 2017, the fair value of restricted stock units vested was $91 million, $62 million, and $42 million, respectively. As of December 31, 2019, there was approximately $31 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted for restricted stock units, which is expected to be recognized over a period of approximately three years. Restricted Stock Certain employees receive awards of FE restricted stock (as opposed to "units" with the right to receive shares at the end of the restriction period) subject to restrictions that lapse over a defined period of time or upon achieving performance results. The fair value of restricted stock is measured based on the average of the high and low prices of FE common stock on the date of grant. Dividends are received on the restricted stock and are reinvested in additional shares of restricted stock, subject to the vesting conditions of the underlying award. Restricted stock activity for the year ended December 31, 2019, was not material. Stock Options Stock options have been granted to certain employees allowing them to purchase a specified number of common shares at a fixed exercise price over a defined period of time. Stock options generally expire ten years from the date of grant. There were no stock options granted in 2019. Stock option activity for the year ended December 31, 2019 was as follows: Stock Option Activity Balance, January 1, 2019 (all options exercisable) Options exercised Options forfeited Balance, December 31, 2019 (all options exercisable) Number of Shares (in millions) 0.8 Weighted Average Exercise Price (per share) $ (0.6) (0.1) 0.1 $ 37.37 37.26 37.72 37.75 Approximately $23 million and $12 million of cash was received from the exercise of stock options in 2019 and 2018, respectively. There was no cash received from the exercise of stock options in 2017. The weighted-average remaining contractual term of options outstanding as of December 31, 2019, was 2.16 years. 75 76 401(k) Savings Plan In 2019 and 2018, approximately 1 million and 1.3 million shares of FE common stock, respectively, were issued and contributed to participants' accounts. EDCP Under the EDCP, certain employees can defer a portion of their compensation, including base salary, annual incentive awards and/ or long-term incentive awards, into unfunded accounts. Annual incentive and long-term incentive awards may be deferred in FE stock accounts. Base salary and annual incentive awards may be deferred into a retirement cash account which earns interest. Dividends are calculated quarterly on stock units outstanding and are credited in the form of additional stock units. The form of payout as stock or cash vary depending upon the form of the award, the duration of the deferral and other factors. Certain types of deferrals such as dividend equivalent units, Annual incentive awards, and performance share awards are required to be paid in cash. Until 2015, payouts of the stock accounts typically occurred three years from the date of deferral, although participants could have elected to defer their shares into a retirement stock account that would pay out in cash upon retirement. In 2015, FirstEnergy amended the EDCP to eliminate the right to receive deferred shares after three years, effective for deferrals made on or after November 1, 2015. Awards deferred into a retirement stock account will pay out in cash upon separation from service, death or disability. Interest accrues on the cash allocated to the retirement cash account and the balance will pay out in cash over a time period as elected by the participant. DCPD Under the DCPD, members of FE's Board of Directors can elect to defer all or a portion of their equity retainers to a deferred stock account and their cash retainers to deferred stock or deferred cash accounts. The net liability recognized for DCPD of approximately $9 million as of December 31, 2019 and December 31, 2018, is included in the caption “Retirement benefits,” on the Consolidated Balance Sheets. 7. TAXES FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. FE and its subsidiaries, as well as FES and FENOC, are party to an intercompany income tax allocation agreement that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FE, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, are reallocated to the subsidiaries of FE that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit. FES and FENOC are expected to remain parties to the intercompany tax allocation agreement until their emergence from bankruptcy, which is when they will no longer be part of FirstEnergy's consolidated tax group. On December 22, 2017, the President signed into law the Tax Act, which included significant changes to the Internal Revenue Code of 1986 (as amended, the Code). The more significant changes that impacted FirstEnergy were as follows: • Reduction of the corporate federal income tax rate from 35% to 21%, effective in 2018; • Full expensing of qualified property, excluding rate regulated utilities, through 2022 with a phase down beginning in 2023; Limitations on interest deductions with an exception for rate regulated utilities, effective in 2018; Limitation of the utilization of federal NOLs arising after December 31, 2017 to 80% of taxable income with an indefinite carryforward; • • • Repeal of the corporate AMT and allowing taxpayers to claim a refund on any AMT credit carryovers. 77 78 INCOME TAXES(1) Currently payable (receivable)- Federal State(2) Deferred, net- Federal(3) State(4) For the Years Ended December 31, 2019 2018 2017 (In millions) $ (16) $ (16) $ 24 8 150 60 210 (5) 17 1 252 243 495 (6) 14 20 34 1,647 40 1,687 (6) 1,715 Investment tax credit amortization Total income taxes $ 213 $ 490 $ (1) (2) (3) (4) Income Taxes on Income from Continuing Operations. 31, 2018 and 2017, respectively. Excludes $1 million and $22 million of state tax expense associated with discontinued operations for the years ended December Excludes $(9) million, $(1.3) billion and $(771) million of federal tax benefit associated with discontinued operations for the years ended December 31, 2019, 2018 and 2017, respectively. Excludes $4 million, $12 million and $(69) million of state tax expense (benefit) associated with discontinued operations for the years ended December 31, 2019, 2018 and 2017, respectively. FirstEnergy tax rates are affected by permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period, but are not consistent from period to period. The following tables provide a reconciliation of federal income tax expense (benefit) at the federal statutory rate to the total income taxes (benefits) for the years ended December 31, 2019, 2018 and 2017: Income from Continuing Operations, before income taxes Federal income tax expense at statutory rate (21%, 21%, and 35% for 2019, 2018, and 2017, respectively) $ $ 1,117 235 $ $ $ $ 1,426 499 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit AFUDC equity and other flow-through Amortization of investment tax credits ESOP dividend Remeasurement of deferred taxes WV unitary group remeasurement Excess deferred tax amortization due to the Tax Act Uncertain tax positions Valuation allowances Other, net Total income taxes Effective income tax rate For the Years Ended December 31, 2019 2018 2017 (In millions) 1,512 318 90 (31) (5) (3) 24 126 (60) 2 21 8 1,193 40 (15) (6) (5) — — (3) 11 1 96 (36) (5) (3) — — (74) (11) 5 6 $ 213 $ 490 $ 1,715 19.1% 32.4% 120.3% FirstEnergy's effective tax rate on continuing operations for 2019 and 2018 was 19.1% and 32.4%, respectively. The decrease in the effective tax rate resulted primarily from the absence of charges that occurred in 2018, including approximately $24 million related to the remeasurement of deferred income taxes resulting from the Tax Act and approximately $126 million associated with the remeasurement of West Virginia state deferred income taxes, resulting from the legal and financial separation of FES and FENOC from FirstEnergy, which occurred in the first quarter of 2018 (see Note 3, "Discontinued Operations" for other tax matters relating to the FES Bankruptcy that were recognized in discontinued operations). In addition, in 2019, FirstEnergy's regulated distribution and transmission subsidiaries recognized an increase in the tax benefit associated with the amortization of net excess deferred income taxes as compared to 2018 (see Note 14, "Regulatory Matters," for additional detail). In 2019 and 2018, approximately 1 million and 1.3 million shares of FE common stock, respectively, were issued and contributed 401(k) Savings Plan to participants' accounts. EDCP period as elected by the participant. DCPD Balance Sheets. 7. TAXES Under the EDCP, certain employees can defer a portion of their compensation, including base salary, annual incentive awards and/ or long-term incentive awards, into unfunded accounts. Annual incentive and long-term incentive awards may be deferred in FE stock accounts. Base salary and annual incentive awards may be deferred into a retirement cash account which earns interest. Dividends are calculated quarterly on stock units outstanding and are credited in the form of additional stock units. The form of payout as stock or cash vary depending upon the form of the award, the duration of the deferral and other factors. Certain types of deferrals such as dividend equivalent units, Annual incentive awards, and performance share awards are required to be paid in cash. Until 2015, payouts of the stock accounts typically occurred three years from the date of deferral, although participants could have elected to defer their shares into a retirement stock account that would pay out in cash upon retirement. In 2015, FirstEnergy amended the EDCP to eliminate the right to receive deferred shares after three years, effective for deferrals made on or after November 1, 2015. Awards deferred into a retirement stock account will pay out in cash upon separation from service, death or disability. Interest accrues on the cash allocated to the retirement cash account and the balance will pay out in cash over a time Under the DCPD, members of FE's Board of Directors can elect to defer all or a portion of their equity retainers to a deferred stock account and their cash retainers to deferred stock or deferred cash accounts. The net liability recognized for DCPD of approximately $9 million as of December 31, 2019 and December 31, 2018, is included in the caption “Retirement benefits,” on the Consolidated FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. FE and its subsidiaries, as well as FES and FENOC, are party to an intercompany income tax allocation agreement that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FE, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, are reallocated to the subsidiaries of FE that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit. FES and FENOC are expected to remain parties to the intercompany tax allocation agreement until their emergence from bankruptcy, which is when they will no longer be part of FirstEnergy's consolidated tax group. On December 22, 2017, the President signed into law the Tax Act, which included significant changes to the Internal Revenue Code of 1986 (as amended, the Code). The more significant changes that impacted FirstEnergy were as follows: • Reduction of the corporate federal income tax rate from 35% to 21%, effective in 2018; Full expensing of qualified property, excluding rate regulated utilities, through 2022 with a phase down beginning in Limitations on interest deductions with an exception for rate regulated utilities, effective in 2018; Limitation of the utilization of federal NOLs arising after December 31, 2017 to 80% of taxable income with an indefinite 2023; • • • carryforward; • Repeal of the corporate AMT and allowing taxpayers to claim a refund on any AMT credit carryovers. INCOME TAXES(1) Currently payable (receivable)- Federal State(2) Deferred, net- Federal(3) State(4) Investment tax credit amortization Total income taxes For the Years Ended December 31, 2019 2018 2017 (In millions) $ (16) $ (16) $ 24 8 150 60 210 (5) 17 1 252 243 495 (6) $ 213 $ 490 $ 14 20 34 1,647 40 1,687 (6) 1,715 (1) (2) (3) (4) Income Taxes on Income from Continuing Operations. Excludes $1 million and $22 million of state tax expense associated with discontinued operations for the years ended December 31, 2018 and 2017, respectively. Excludes $(9) million, $(1.3) billion and $(771) million of federal tax benefit associated with discontinued operations for the years ended December 31, 2019, 2018 and 2017, respectively. Excludes $4 million, $12 million and $(69) million of state tax expense (benefit) associated with discontinued operations for the years ended December 31, 2019, 2018 and 2017, respectively. FirstEnergy tax rates are affected by permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period, but are not consistent from period to period. The following tables provide a reconciliation of federal income tax expense (benefit) at the federal statutory rate to the total income taxes (benefits) for the years ended December 31, 2019, 2018 and 2017: For the Years Ended December 31, 2019 2018 2017 (In millions) Income from Continuing Operations, before income taxes Federal income tax expense at statutory rate (21%, 21%, and 35% for 2019, 2018, and 2017, respectively) $ $ 1,117 235 $ $ Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit AFUDC equity and other flow-through Amortization of investment tax credits ESOP dividend Remeasurement of deferred taxes WV unitary group remeasurement Excess deferred tax amortization due to the Tax Act Uncertain tax positions Valuation allowances Other, net Total income taxes Effective income tax rate $ $ 1,512 318 90 (31) (5) (3) 24 126 (60) 2 21 8 1,426 499 40 (15) (6) (5) 1,193 — — (3) 11 1 96 (36) (5) (3) — — (74) (11) 5 6 $ 213 $ 490 $ 1,715 19.1% 32.4% 120.3% FirstEnergy's effective tax rate on continuing operations for 2019 and 2018 was 19.1% and 32.4%, respectively. The decrease in the effective tax rate resulted primarily from the absence of charges that occurred in 2018, including approximately $24 million related to the remeasurement of deferred income taxes resulting from the Tax Act and approximately $126 million associated with the remeasurement of West Virginia state deferred income taxes, resulting from the legal and financial separation of FES and FENOC from FirstEnergy, which occurred in the first quarter of 2018 (see Note 3, "Discontinued Operations" for other tax matters relating to the FES Bankruptcy that were recognized in discontinued operations). In addition, in 2019, FirstEnergy's regulated distribution and transmission subsidiaries recognized an increase in the tax benefit associated with the amortization of net excess deferred income taxes as compared to 2018 (see Note 14, "Regulatory Matters," for additional detail). 77 78 Accumulated deferred income taxes as of December 31, 2019 and 2018, are as follows: The following table summarizes the changes in unrecognized tax positions for the years ended December 31, 2019, 2018 and 2017: Property basis differences Pension and OPEB TMI-2 nuclear decommissioning AROs Regulatory asset/liability Deferred compensation Estimated worthless stock deduction Loss carryforwards and AMT credits Valuation reserve All other Net deferred income tax liability As of December 31, 2018 2019 $ (In millions) 5,037 (698) 89 (226) 445 (154) (1,007) (836) 441 (242) 2,849 $ 4,737 (629) 82 (215) 414 (170) (1,004) (899) 394 (208) 2,502 $ $ FirstEnergy has recorded as deferred income tax assets the effect of Federal NOLs and tax credits that will more likely than not be realized through future operations and through the reversal of existing temporary differences. As of December 31, 2019, FirstEnergy's loss carryforwards and AMT credits consisted of $2.1 billion ($441 million, net of tax) of Federal NOL carryforwards that will begin to expire in 2031 and Federal AMT credits of $9 million that have an indefinite carryforward period. The table below summarizes pre-tax NOL carryforwards for state and local income tax purposes of approximately $6.8 billion ($361 million, net of tax) for FirstEnergy, of which approximately $1.5 billion ($103 million, net of tax) is expected to be utilized based on current estimates and assumptions. The ultimate utilization of these NOLs may be impacted by statutory limitations on the use of NOLs imposed by state and local tax jurisdictions, changes in statutory tax rates, and changes in business which, among other things, impact both future profitability and the manner in which future taxable income is apportioned to various state and local tax jurisdictions. In addition to the valuation allowances on state and local NOLs, FirstEnergy has recorded a reserve against certain state and local property related DTAs (approximately $62 million, net of tax) and a reserve against the estimated nondeductible portion of interest expense, discussed above. Expiration Period 2020-2024 2025-2029 2030-2034 2035-2039 Indefinite State Local (In millions) $ 1,844 $ 1,081 1,652 1,265 886 67 — — — — $ 5,714 $ 1,081 FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. A recognition threshold and measurement attribute are utilized for financial statement recognition and measurement of tax positions taken or expected to be taken on the tax return. As of December 31, 2019 and 2018, FirstEnergy's total unrecognized income tax benefits were approximately $164 million and $158 million, respectively. The change in unrecognized income tax benefits from the prior year is primarily attributable to increases of approximately $14 million for the reserve for estimated nondeductible interest under Section 163(j) and $6 million for reserves on the estimated worthless stock deduction (see Note 3, Discontinued Operations, for further discussion). These increases were partially offset by a remeasurement of the 2018 reserve related to the estimated nondeductible interest under Section 163(j) of approximately $11 million, as well as a $3 million decrease due to the lapse in statute in certain state taxing jurisdictions. If ultimately recognized in future years, approximately $151 million of unrecognized income tax benefits would impact the effective tax rate. As of December 31, 2019, it is reasonably possible that approximately $59 million of unrecognized tax benefits may be resolved during 2020 as a result of settlements with taxing authorities or the statute of limitations expiring, of which $57 million would affect FirstEnergy's effective tax rate. Balance, January 1, 2017 Current year increases Decrease for lapse in statute Balance, December 31, 2017 Current year increases Prior year decreases Decrease for lapse in statute Balance, December 31, 2018 Current year increases Prior years decreases Decrease for lapse in statute Balance, December 31, 2019 (In millions) $ $ $ $ 84 2 (6) 80 125 (45) (2) 158 22 (12) (4) 164 FirstEnergy recognizes interest expense or income and penalties related to uncertain tax positions in income taxes by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken, or expected to be taken, on the tax return. FirstEnergy's recognition of net interest associated with unrecognized tax benefits in 2019, 2018 and 2017, was not material. For the years ended December 31, 2019 and 2018, the cumulative net interest payable recorded by FirstEnergy was not material. FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state taxing authorities. In June 2019, the IRS completed its examination of FirstEnergy's 2017 federal income tax return and issued a Full Acceptance Letter with no changes or adjustments to FirstEnergy's taxable income. Tax year 2018 is currently under review by the IRS. FirstEnergy's tax returns for some state jurisdictions are open from 2009-2018. General Taxes summarized as follows: General tax expense for the years ended December 31, 2019, 2018 and 2017, recognized in continuing operations is KWH excise State gross receipts Real and personal property Social security and unemployment Other Total general taxes 8. LEASES For the Years Ended December 31, 2019 2018 2017 $ (In millions) $ $ 191 185 504 100 28 198 192 478 103 22 $ 1,008 $ 993 $ 188 184 452 96 20 940 FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancelable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor. FirstEnergy adopted ASU 2016-02, “Leases (Topic 842)” on January 1, 2019, and elected a number of transitional practical expedients provided within the standard. These included a “package of three” expedients that must be taken together and allowed entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. In addition, FirstEnergy elected the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Adoption of the standard on January 1, 2019, did not result in a material cumulative effect adjustment upon adoption. FirstEnergy did not evaluate land easements under the new guidance as they were not previously accounted for as leases. FirstEnergy also elected not to separate lease components from non-lease components as non-lease components were not material. Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease 79 80 Property basis differences Pension and OPEB TMI-2 nuclear decommissioning AROs Regulatory asset/liability Deferred compensation Estimated worthless stock deduction Loss carryforwards and AMT credits Valuation reserve All other As of December 31, 2019 2018 (In millions) $ 5,037 $ (698) 89 (226) 445 (154) (836) 441 (242) 4,737 (629) 82 (215) 414 (170) (899) 394 (208) (1,007) (1,004) Net deferred income tax liability $ 2,849 $ 2,502 FirstEnergy has recorded as deferred income tax assets the effect of Federal NOLs and tax credits that will more likely than not be realized through future operations and through the reversal of existing temporary differences. As of December 31, 2019, FirstEnergy's loss carryforwards and AMT credits consisted of $2.1 billion ($441 million, net of tax) of Federal NOL carryforwards that will begin to expire in 2031 and Federal AMT credits of $9 million that have an indefinite carryforward period. The table below summarizes pre-tax NOL carryforwards for state and local income tax purposes of approximately $6.8 billion ($361 million, net of tax) for FirstEnergy, of which approximately $1.5 billion ($103 million, net of tax) is expected to be utilized based on current estimates and assumptions. The ultimate utilization of these NOLs may be impacted by statutory limitations on the use of NOLs imposed by state and local tax jurisdictions, changes in statutory tax rates, and changes in business which, among other things, impact both future profitability and the manner in which future taxable income is apportioned to various state and local tax jurisdictions. In addition to the valuation allowances on state and local NOLs, FirstEnergy has recorded a reserve against certain state and local property related DTAs (approximately $62 million, net of tax) and a reserve against the estimated nondeductible portion of interest expense, discussed above. Expiration Period 2020-2024 2025-2029 2030-2034 2035-2039 Indefinite State Local (In millions) $ 1,844 $ 1,081 1,652 1,265 886 67 — — — — $ 5,714 $ 1,081 FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. A recognition threshold and measurement attribute are utilized for financial statement recognition and measurement of tax positions taken or expected to be taken on the tax return. As of December 31, 2019 and 2018, FirstEnergy's total unrecognized income tax benefits were approximately $164 million and $158 million, respectively. The change in unrecognized income tax benefits from the prior year is primarily attributable to reserves on the estimated worthless stock deduction (see Note 3, Discontinued Operations, for further discussion). These increases were partially offset by a remeasurement of the 2018 reserve related to the estimated nondeductible interest under Section 163(j) of approximately $11 million, as well as a $3 million decrease due to the lapse in statute in certain state taxing jurisdictions. If ultimately recognized in future years, approximately $151 million of unrecognized income tax benefits would impact the effective tax rate. As of December 31, 2019, it is reasonably possible that approximately $59 million of unrecognized tax benefits may be resolved during 2020 as a result of settlements with taxing authorities or the statute of limitations expiring, of which $57 million would affect FirstEnergy's effective tax rate. Accumulated deferred income taxes as of December 31, 2019 and 2018, are as follows: The following table summarizes the changes in unrecognized tax positions for the years ended December 31, 2019, 2018 and 2017: Balance, January 1, 2017 Current year increases Decrease for lapse in statute Balance, December 31, 2017 Current year increases Prior year decreases Decrease for lapse in statute Balance, December 31, 2018 Current year increases Prior years decreases Decrease for lapse in statute Balance, December 31, 2019 (In millions) $ $ $ $ 84 2 (6) 80 125 (45) (2) 158 22 (12) (4) 164 FirstEnergy recognizes interest expense or income and penalties related to uncertain tax positions in income taxes by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken, or expected to be taken, on the tax return. FirstEnergy's recognition of net interest associated with unrecognized tax benefits in 2019, 2018 and 2017, was not material. For the years ended December 31, 2019 and 2018, the cumulative net interest payable recorded by FirstEnergy was not material. FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state taxing authorities. In June 2019, the IRS completed its examination of FirstEnergy's 2017 federal income tax return and issued a Full Acceptance Letter with no changes or adjustments to FirstEnergy's taxable income. Tax year 2018 is currently under review by the IRS. FirstEnergy's tax returns for some state jurisdictions are open from 2009-2018. General Taxes General tax expense for the years ended December 31, 2019, 2018 and 2017, recognized in continuing operations is summarized as follows: KWH excise State gross receipts Real and personal property Social security and unemployment Other Total general taxes For the Years Ended December 31, 2019 2018 2017 (In millions) $ $ 191 185 504 100 28 $ 198 192 478 103 22 $ 1,008 $ 993 $ 188 184 452 96 20 940 increases of approximately $14 million for the reserve for estimated nondeductible interest under Section 163(j) and $6 million for 8. LEASES FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancelable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor. FirstEnergy adopted ASU 2016-02, “Leases (Topic 842)” on January 1, 2019, and elected a number of transitional practical expedients provided within the standard. These included a “package of three” expedients that must be taken together and allowed entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. In addition, FirstEnergy elected the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Adoption of the standard on January 1, 2019, did not result in a material cumulative effect adjustment upon adoption. FirstEnergy did not evaluate land easements under the new guidance as they were not previously accounted for as leases. FirstEnergy also elected not to separate lease components from non-lease components as non-lease components were not material. Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease 79 80 term from 1 to 40 years, and certain leases include options to terminate. The exercise of lease renewal options is at FirstEnergy’s sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants. For vehicles leased under master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. As of December 31, 2019, the maximum potential loss for these lease agreements at the end of the lease term is approximately $15 million. Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income (Loss) such that amortization of the right-of-use asset and interest on lease liabilities equals the expense allowed for ratemaking purposes. Finance leases for regulated and non-regulated operations are accounted for as if the assets were owned and financed, with associated expense recognized in Interest expense and Provision for depreciation on FirstEnergy’s Consolidated Statements of Income (Loss), while all operating lease expenses are recognized in Other operating expense. The components of lease expense were as follows: (In millions) Operating lease costs (1) Finance lease costs: Amortization of right-of-use assets Interest on lease liabilities Total finance lease cost Total lease cost $ $ For the Year Ended December 31, 2019 Vehicles Buildings Other Total 28 $ 9 $ 12 $ 15 3 18 46 1 3 4 $ 13 $ 1 — 1 13 $ 49 17 6 23 72 (1) Includes $13 million of short-term lease costs. Supplemental cash flow information related to leases was as follows: (In millions) Cash paid for amounts included in the measurement of lease liabilities: For the Year Ended December 31, 2019 Operating cash flows from operating leases Operating cash flows from finance leases Finance cash flows from finance leases Right-of-use assets obtained in exchange for lease obligations: Operating leases Finance leases $ $ 29 5 25 83 3 Lease terms and discount rates were as follows: Weighted-average remaining lease terms (years) As of December 31, 2019 Operating leases Finance leases Weighted-average discount rate (1) Operating leases Finance leases 9.42 4.62 4.51% 10.45% (1) When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date. (In millions) Assets Liabilities Current: Operating Finance Noncurrent: Operating Finance Supplemental balance sheet information related to leases was as follows: Financial Statement Line Item As of December 31, 2019 Operating lease assets, net of accumulated amortization of $23 million Finance lease assets, net of accumulated amortization of $90 million Total leased assets Deferred charges and other assets $ Property, plant and equipment 231 73 304 32 15 241 45 333 60 57 55 44 33 170 419 (86) 333 $ $ $ 20 17 15 8 4 16 80 (20) 60 $ Other current liabilities $ Currently payable long-term debt Other noncurrent liabilities Long-term debt and other long-term obligations Total leased liabilities Maturities of lease liabilities as of December 31, 2019, were as follows: (In millions) Operating Leases Finance Leases Total $ $ 2020 2021 2022 2023 2024 Thereafter Total lease payments (1) Less imputed interest 40 40 40 36 29 154 339 (66) Total net present value $ 273 $ (1) Operating lease payments for certain leases are offset by sublease receipts of $13 million over 13 years. As of December 31, 2019, additional operating leases agreements, primarily for vehicles, that have not yet commenced are $13 million. These leases are expected to commence within the next 18 months with lease terms of 3 to 10 years. 81 82 term from 1 to 40 years, and certain leases include options to terminate. The exercise of lease renewal options is at FirstEnergy’s Supplemental balance sheet information related to leases was as follows: sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants. (In millions) Assets Financial Statement Line Item As of December 31, 2019 For vehicles leased under master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. As of December 31, 2019, the maximum potential loss for these lease agreements at the end of the lease term is approximately $15 million. Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income (Loss) such that amortization of the right-of-use asset and interest on lease liabilities equals the expense allowed for ratemaking purposes. Finance leases for regulated and non-regulated operations are accounted for as if the assets were owned and financed, with associated expense recognized in Interest expense and Provision for depreciation on FirstEnergy’s Consolidated Statements of Income (Loss), while all operating lease expenses are recognized in Other operating expense. The components of lease expense were as follows: (In millions) Operating lease costs (1) Finance lease costs: Amortization of right-of-use assets Interest on lease liabilities Total finance lease cost Total lease cost $ $ (1) Includes $13 million of short-term lease costs. For the Year Ended December 31, 2019 Vehicles Buildings Other Total 28 $ 9 $ 12 $ 15 3 18 46 1 3 4 1 — 1 13 $ 13 $ $ 49 17 6 23 72 Supplemental cash flow information related to leases was as follows: (In millions) Cash paid for amounts included in the measurement of lease liabilities: For the Year Ended December 31, 2019 Operating cash flows from operating leases Operating cash flows from finance leases Finance cash flows from finance leases Right-of-use assets obtained in exchange for lease obligations: Operating leases Finance leases $ $ 29 5 25 83 3 Lease terms and discount rates were as follows: Weighted-average remaining lease terms (years) As of December 31, 2019 Weighted-average discount rate (1) Operating leases Finance leases Operating leases Finance leases 9.42 4.62 4.51% 10.45% (1) When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date. 231 73 304 32 15 241 45 333 Operating lease assets, net of accumulated amortization of $23 million Finance lease assets, net of accumulated amortization of $90 million Total leased assets Deferred charges and other assets $ Property, plant and equipment $ Liabilities Current: Operating Finance Noncurrent: Operating Finance Other current liabilities $ Currently payable long-term debt Other noncurrent liabilities Long-term debt and other long-term obligations Total leased liabilities $ Maturities of lease liabilities as of December 31, 2019, were as follows: (In millions) Operating Leases Finance Leases Total $ 2020 2021 2022 2023 2024 Thereafter Total lease payments (1) Less imputed interest $ 40 40 40 36 29 154 339 (66) Total net present value $ 273 $ $ 20 17 15 8 4 16 80 (20) 60 $ 60 57 55 44 33 170 419 (86) 333 (1) Operating lease payments for certain leases are offset by sublease receipts of $13 million over 13 years. As of December 31, 2019, additional operating leases agreements, primarily for vehicles, that have not yet commenced are $13 million. These leases are expected to commence within the next 18 months with lease terms of 3 to 10 years. 81 82 ASC 840, "Leases" Disclosures The future minimum capital lease payments as of December 31, 2018, as reported in the 2018 Annual Report on Form 10-K for the year ended December 31, 2018 under ASC 840 ”Leases” are as follows: 10. FAIR VALUE MEASUREMENTS RECURRING FAIR VALUE MEASUREMENTS Capital Leases 2019 2020 2021 2022 2023 Years thereafter Total minimum lease payments Interest portion Present value of net minimum lease payments Less current portion Noncurrent portion (In millions) $ $ 24 19 16 13 8 16 96 (23) 73 18 55 The future minimum operating lease payments as of December 31, 2018, as reported in the 2018 Annual Report on Form 10-K for the year ended December 31, 2018 under ASC 840 ”Leases” are as follows: to measure fair value. Operating Leases (In millions) 2019 2020 2021 2022 2023 Years thereafter Total minimum lease payments $ $ 34 36 34 30 28 127 289 Operating lease expense under ASC 840 ”Leases" for the years ended December 31, 2018 and 2017 were $48 million and $53 million, respectively. 9. INTANGIBLE ASSETS As of December 31, 2019, intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheets include the following: Intangible Assets Amortization Expense Actual Estimated (In millions) NUG contracts(1) Coal contracts(2) Gross Accumulated Amortization Net 2019 2020 2021 2022 2023 2024 Thereafter $ $ 124 102 226 $ $ 46 $ 100 146 $ 78 2 80 $ $ 5 3 8 $ $ 5 2 7 $ $ 5 — 5 $ $ 5 — 5 $ $ 5 — 5 $ $ 5 — 5 $ $ 53 — 53 (1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings. (2) The coal contracts were recorded with a regulatory offset and their amortization does not impact earnings. Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows: Level 1 - Quoted prices for identical instruments in active market Level 2 - Quoted prices for similar instruments in active market - Quoted prices for identical or similar instruments in markets that are not active - Model-derived valuations for which all significant inputs are observable market data Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 - Valuation inputs are unobservable and significant to the fair value measurement FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast are used FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day- ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement. NUG contracts represent PPAs with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to- model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for the current year and next two years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on Intercontinental Exchange, Inc. quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement. For investments reported at NAV where there is no readily determinable fair value, a practical expedient is available that allows the NAV to approximate fair value. Investments that use NAV as a practical expedient are excluded from the requirement to be categorized within the fair value hierarchy tables. Instead, these investments are reported outside of the fair value hierarchy tables to assist in the reconciliation of investment balances reported in the tables to the balance sheet. FirstEnergy has elected the NAV practical expedient for investments in private equity funds, insurance-linked securities, hedge funds (absolute return) and real estate funds held within the pension plan. See Note 5, "Pension And Other Postemployment Benefits" for the pension financial assets accounted for at fair value by level within the fair value hierarchy. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of December 31, 2019, from those used as of December 31, 2018. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements. 83 84 ASC 840, "Leases" Disclosures 10. FAIR VALUE MEASUREMENTS The future minimum capital lease payments as of December 31, 2018, as reported in the 2018 Annual Report on Form 10-K for RECURRING FAIR VALUE MEASUREMENTS the year ended December 31, 2018 under ASC 840 ”Leases” are as follows: Capital Leases 2019 2020 2021 2022 2023 Years thereafter Interest portion Total minimum lease payments Present value of net minimum lease payments Less current portion Noncurrent portion (In millions) $ $ 24 19 16 13 8 16 96 73 18 55 (23) Operating Leases (In millions) 2019 2020 2021 2022 2023 Years thereafter Total minimum lease payments $ $ 34 36 34 30 28 127 289 The future minimum operating lease payments as of December 31, 2018, as reported in the 2018 Annual Report on Form 10-K for the year ended December 31, 2018 under ASC 840 ”Leases” are as follows: Operating lease expense under ASC 840 ”Leases" for the years ended December 31, 2018 and 2017 were $48 million and $53 million, respectively. 9. INTANGIBLE ASSETS include the following: As of December 31, 2019, intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheets Intangible Assets Amortization Expense Actual Estimated (In millions) NUG contracts(1) Coal contracts(2) Gross Accumulated Amortization Net 2019 2020 2021 2022 2023 2024 Thereafter $ $ 124 102 226 $ $ 46 $ 100 146 $ 78 2 80 $ $ 5 3 8 $ $ 5 2 7 $ $ 5 — 5 $ $ 5 — 5 $ $ 5 — 5 $ $ 5 — 5 $ $ 53 — 53 (1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings. (2) The coal contracts were recorded with a regulatory offset and their amortization does not impact earnings. Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows: Level 1 - Quoted prices for identical instruments in active market Level 2 - Quoted prices for similar instruments in active market - Quoted prices for identical or similar instruments in markets that are not active - Model-derived valuations for which all significant inputs are observable market data Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 - Valuation inputs are unobservable and significant to the fair value measurement FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast are used to measure fair value. FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day- ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement. NUG contracts represent PPAs with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to- model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for the current year and next two years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on Intercontinental Exchange, Inc. quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement. For investments reported at NAV where there is no readily determinable fair value, a practical expedient is available that allows the NAV to approximate fair value. Investments that use NAV as a practical expedient are excluded from the requirement to be categorized within the fair value hierarchy tables. Instead, these investments are reported outside of the fair value hierarchy tables to assist in the reconciliation of investment balances reported in the tables to the balance sheet. FirstEnergy has elected the NAV practical expedient for investments in private equity funds, insurance-linked securities, hedge funds (absolute return) and real estate funds held within the pension plan. See Note 5, "Pension And Other Postemployment Benefits" for the pension financial assets accounted for at fair value by level within the fair value hierarchy. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of December 31, 2019, from those used as of December 31, 2018. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements. 83 84 The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: Level 3 Quantitative Information December 31, 2019 December 31, 2018 hierarchy for the year ended December 31, 2019: Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value $ $ $ $ $ 722 $ 10 $ 1,438 405 10 339 13 20 250 401 — — 13 20 250 34 10 — — — — — $ — $ 135 $ — $ 135 $ — $ 405 $ — $ (In millions) — 2 — — — 627 629 — — — — 271 789 $ 1,195 $ 4 — — — — — 4 4 2 — — 271 1,416 $ 1,828 $ — 339 — — — 367 706 — $ — $ (1) $ (1) $ — $ — $ (1) $ — — (16) (16) — — (44) — $ — $ (17) $ (17) $ — $ — $ (45) $ (1) (44) (45) 629 $ 1,195 $ (13) $ 1,811 $ 706 $ 722 $ (35) $ 1,393 Assets Corporate debt securities Derivative assets FTRs(1) Equity securities(2) Foreign government debt securities U.S. government debt securities U.S. state debt securities Other(3) Total assets Liabilities Derivative liabilities FTRs(1) Derivative liabilities NUG contracts(1) Total liabilities Net assets (liabilities)(4) Fair Value, Net (In millions) Valuation Technique Significant Input Range Weighted Average Units FTRs NUG Contracts $ $ 3 (16) Model Model RTO auction clearing prices $0.70 to $3.40 $1.30 Dollars/MWH Generation Regional electricity prices 400 to 330,000 $25.30 to $35.20 115,000 $26.30 MWH Dollars/MWH INVESTMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include equity securities, AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes. Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the NDTs of JCP&L, ME and PN are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets. The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries. Nuclear Decommissioning and Nuclear Fuel Disposal Trusts JCP&L, ME and PN hold debt and equity securities within their respective NDT and nuclear fuel disposal trusts. The debt securities are classified as AFS securities, recognized at fair market value. As further discussed in Note 15, "Commitments, Guarantees and Contingencies", assets and liabilities held for sale on the FirstEnergy Consolidated Balance Sheets associated with the TMI-2 transaction consist of an ARO of $691 million , NDTs of $882 million, as well as property, plant and equipment with a net book value of zero, which are included in the regulated distribution segment. December 31, 2019(1) December 31, 2018(2) Cost Basis Unrealized Unrealized Gains Losses Fair Value(3) Cost Basis Unrealized Unrealized Gains Losses Fair Value (In millions) Debt securities Equity securities $ $ 403 $ — $ 9 $ — $ (11) $ — $ 401 $ — $ 714 339 $ $ 2 15 $ $ (28) $ (16) $ 688 338 (1) Excludes short-term cash investments of $751 million, of which $747 million is classified as held for sale. (2) Excludes short-term cash investments of $20 million. (3) Includes $135 million classified as held for sale. Proceeds from the sale of investments in equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the years ended December 31, 2019, 2018 and 2017, were as follows: Sale Proceeds Realized Gains Realized Losses Interest and Dividend Income For the Years Ended December 31, 2019 2018(1) 2017(1) (In millions) $ 1,637 $ 800 $ 1,230 98 (31) 38 41 (48) 41 74 (58) 39 (1) Excludes amounts classified as discontinued operations. (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Low Volatility High Dividend Index, S&P 500 Index, MSCI World Index and MSCI AC World IMI Index. (3) Primarily consists of short-term cash investments. (4) Excludes $(16) million and $4 million as of December 31, 2019, and December 31, 2018, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. Rollforward of Level 3 Measurements The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the years ended December 31, 2019 and December 31, 2018: The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in NDT and nuclear fuel disposal trusts as of December 31, 2019 and December 31, 2018: NUG Contracts(1) FTRs(1) Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net January 1, 2018 Balance Unrealized gain (loss) Purchases Settlements December 31, 2018 Balance Unrealized gain (loss) Purchases Settlements December 31, 2019 Balance $ $ $ — $ (79) $ (79) $ (In millions) — — — 2 — 33 2 — 33 — $ (44) $ (44) $ — — — (11) — 39 (11) — 39 3 8 5 (6) 10 $ (1) 6 (11) $ — $ 1 (5) 3 (1) $ — (4) 4 3 9 — (3) 9 (1) 2 (7) 3 — $ (16) $ (16) $ 4 $ (1) $ (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. 85 86 The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value Level 3 Quantitative Information hierarchy: Assets Corporate debt securities Derivative assets FTRs(1) Equity securities(2) Foreign government debt securities U.S. government debt securities U.S. state debt securities Other(3) Total assets Liabilities December 31, 2019 December 31, 2018 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total $ — $ 135 $ — $ 135 $ — $ 405 $ — $ — 2 — — — 627 629 — — — — 271 789 (In millions) 4 2 — — 271 1,416 4 — — — — — 4 — 339 — — — 367 706 — — 13 20 250 34 10 — — — — — $ 1,195 $ $ 1,828 $ $ 722 $ 10 $ 1,438 Derivative liabilities FTRs(1) Derivative liabilities NUG contracts(1) Total liabilities — $ — $ (1) $ (1) $ — $ — $ (1) $ — — (16) (16) — — (44) — $ — $ (17) $ (17) $ — $ — $ (45) $ Net assets (liabilities)(4) 629 $ 1,195 $ (13) $ 1,811 $ 706 $ 722 $ (35) $ 1,393 405 10 339 13 20 250 401 (1) (44) (45) The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the year ended December 31, 2019: Fair Value, Net (In millions) Valuation Technique Significant Input Range Weighted Average Units FTRs NUG Contracts $ $ 3 (16) Model Model RTO auction clearing prices $0.70 to $3.40 $1.30 Dollars/MWH Generation Regional electricity prices 400 to 330,000 $25.30 to $35.20 115,000 $26.30 MWH Dollars/MWH INVESTMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include equity securities, AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes. Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the NDTs of JCP&L, ME and PN are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets. The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries. (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Low Volatility High Dividend Index, S&P 500 Index, Nuclear Decommissioning and Nuclear Fuel Disposal Trusts MSCI World Index and MSCI AC World IMI Index. (3) Primarily consists of short-term cash investments. (4) Excludes $(16) million and $4 million as of December 31, 2019, and December 31, 2018, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. Rollforward of Level 3 Measurements JCP&L, ME and PN hold debt and equity securities within their respective NDT and nuclear fuel disposal trusts. The debt securities are classified as AFS securities, recognized at fair market value. As further discussed in Note 15, "Commitments, Guarantees and Contingencies", assets and liabilities held for sale on the FirstEnergy Consolidated Balance Sheets associated with the TMI-2 transaction consist of an ARO of $691 million , NDTs of $882 million, as well as property, plant and equipment with a net book value of zero, which are included in the regulated distribution segment. The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the years ended December 31, 2019 and December 31, 2018: The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in NDT and nuclear fuel disposal trusts as of December 31, 2019 and December 31, 2018: December 31, 2019(1) December 31, 2018(2) Cost Basis Unrealized Gains Unrealized Losses Fair Value(3) Cost Basis Unrealized Gains Unrealized Losses Fair Value (In millions) Debt securities Equity securities $ $ 403 $ — $ 9 $ — $ (11) $ — $ 401 $ — $ 714 339 $ $ 2 15 $ $ (28) $ (16) $ 688 338 (1) Excludes short-term cash investments of $751 million, of which $747 million is classified as held for sale. (2) Excludes short-term cash investments of $20 million. (3) Includes $135 million classified as held for sale. Proceeds from the sale of investments in equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the years ended December 31, 2019, 2018 and 2017, were as follows: $ $ $ $ $ $ $ January 1, 2018 Balance Unrealized gain (loss) Purchases Settlements Unrealized gain (loss) Purchases Settlements NUG Contracts(1) FTRs(1) Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net — $ (79) $ (79) $ $ — $ (In millions) — — — — — — 2 — 33 (11) — 39 2 — 33 (11) — 39 3 8 5 (6) 10 $ (1) 6 (11) (5) 1 3 — (4) 4 3 9 9 2 3 — (3) (1) (7) December 31, 2018 Balance — $ (44) $ (44) $ (1) $ December 31, 2019 Balance — $ (16) $ (16) $ 4 $ (1) $ (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. For the Years Ended December 31, 2018(1) (In millions) 2017(1) 2019 Sale Proceeds Realized Gains Realized Losses Interest and Dividend Income $ 1,637 $ 800 $ 1,230 98 (31) 38 41 (48) 41 74 (58) 39 (1) Excludes amounts classified as discontinued operations. 85 86 Other Investments PREFERRED AND PREFERENCE STOCK Other investments include employee benefit trusts, which are primarily invested in corporate-owned life insurance policies, and equity method investments. Other investments were $299 million and $253 million as of December 31, 2019 and December 31, 2018, respectively, and are excluded from the amounts reported above. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes finance lease obligations and net unamortized debt issuance costs, premiums and discounts as of December 31, 2019 and 2018: As of December 31, 2019 2018 (In millions) Carrying Value (1) Fair Value $ 20,074 $ 22,928 18,315 19,266 (1) The carrying value as of December 31, 2019, includes $2.3 billion of debt issuances and $789 million of redemptions that occurred during 2019. The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of December 31, 2019 and December 31, 2018. 11. CAPITALIZATION COMMON STOCK Retained Earnings and Dividends As of December 31, 2019, FirstEnergy had an accumulated deficit of $4.0 billion. Dividends declared in 2019 and 2018 were $1.53 and $1.82 per share, respectively. Dividends of $0.38 per share and $0.36 per share were paid in the first, second, third and fourth quarters in 2019 and 2018, respectively. On November 8, 2019, the Board of Directors declared a quarterly dividend of $0.39 per share to be paid from OPIC in the first quarter of 2020. The amount and timing of all dividend declarations are subject to the discretion of the Board of Directors and its consideration of business conditions, results of operations, financial condition and other factors. were paid. In addition to paying dividends from retained earnings, OE, CEI, TE, Penn, JCP&L, ME and PN have authorization from FERC to pay cash dividends to FirstEnergy from paid-in capital accounts, as long as their FERC-defined equity-to-total-capitalization ratio remains above 35%. In addition, AGC has authorization from FERC to pay cash dividends to its parent from paid-in capital accounts, as long as its FERC-defined equity-to-total-capitalization ratio remains above 45%. The articles of incorporation, indentures, regulatory limitations and various other agreements relating to the long-term debt of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock. None of these provisions materially restricted FirstEnergy’s subsidiaries’ abilities to pay cash dividends to FE as of December 31, 2019. Common Stock Issuance Additionally, FE issued approximately 3 million shares of common stock in 2019, 3.2 million shares of common stock in 2018 and 3.0 million shares of common stock in 2017 to registered shareholders and its directors and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans. On January 22, 2018, FE entered into a Common Stock Purchase Agreement for the private placement of 30,120,482 shares of FE’s common stock, par value $0.10 per share, representing an investment of $850 million ($3 million of common shares and $847 million of OPIC). Please see below for information on preferred stock converted into shares of common stock during 2018 and 2019. FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2019, as follows: Preferred Stock Preference Stock Shares Authorized Par Value Shares Authorized Par Value 8,000,000 no par no par 3,000,000 5,000,000 $ no par 25 5,000,000 6,000,000 8,000,000 1,200,000 4,000,000 3,000,000 12,000,000 15,600,000 10,000,000 11,435,000 940,000 10,000,000 32,000,000 $ $ $ $ $ $ $ $ 100 100 25 100 100 25 no par no par no par 100 0.01 no par Penn FE OE OE CEI TE TE ME PN MP PE WP JCP&L As of December 31, 2019, there were no preferred stock outstanding. As of December 31, 2019 and 2018, there were no preference stock outstanding. Preferred Stock Issuance FE entered into a Preferred Stock Purchase Agreement for the private placement of 1,616,000 shares of mandatorily convertible preferred stock, designated as the Series A Convertible Preferred Stock, par value $100 per share, representing an investment of nearly $1.62 billion ($162 million of mandatorily convertible preferred stock and $1.46 billion of OPIC). The preferred stock participated in dividends on the common stock on an as-converted basis based on the number of shares of common stock a holder of preferred stock would have received if its shares of preferred stock were converted on the dividend record date at the conversion price in effect at that time. Such dividends were paid at the same time that the dividends on common stock During 2018, 911,411 shares of preferred stock were converted into 33,238,910 shares of common stock at the option of the preferred stockholders. Also, at the option of the preferred stockholders, 494,767 shares of preferred stock were converted into 18,044,018 shares of common stock in January 2019. On July 22, 2019, 28,302 shares of preferred stock automatically converted into 1,032,165 shares of common stock, and 181,520 shares of preferred stock remained unconverted as the holder reached the 4.9% cap as outlined in the terms of the preferred stock. The remaining 181,520 preferred stock shares were converted on August 1, 2019, into 6,619,985 shares of common stock. As of December 31, 2019, 1,616,000 shares of preferred stock were converted into 58,935,078 shares of common stock and as a result, there are no preferred shares outstanding. The preferred stock included an embedded conversion option at a price that was below the fair value of the common stock on the commitment date. This beneficial conversion feature, which was approximately $296 million, represents the difference between the fair value per share of the common stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature was amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature was reflected in net income attributable to common stockholders as a deemed dividend. The beneficial conversion feature ($296 million) was fully amortized during the third quarter of 2018. Each share of preferred stock was convertible at the holder’s option into a number of shares of common stock equal to the $1,000 liquidation preference, divided by the conversion price then in effect ($27.42 per share). The conversion price was subject to anti- dilution adjustments and adjustments for subdivisions and combinations of the common stock, as well as dividends on the common stock paid in common stock and for certain equity issuances below the conversion price then in effect. 87 88 Other Investments PREFERRED AND PREFERENCE STOCK Other investments include employee benefit trusts, which are primarily invested in corporate-owned life insurance policies, and FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2019, as follows: equity method investments. Other investments were $299 million and $253 million as of December 31, 2019 and December 31, 2018, respectively, and are excluded from the amounts reported above. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes finance lease obligations and net unamortized debt issuance costs, premiums and discounts as of December 31, 2019 and 2018: As of December 31, 2019 2018 (In millions) Carrying Value (1) Fair Value $ 20,074 $ 22,928 18,315 19,266 (1) The carrying value as of December 31, 2019, includes $2.3 billion of debt issuances and $789 million of redemptions that occurred during 2019. The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of December 31, 2019 and December 31, 2018. 11. CAPITALIZATION COMMON STOCK Retained Earnings and Dividends As of December 31, 2019, FirstEnergy had an accumulated deficit of $4.0 billion. Dividends declared in 2019 and 2018 were $1.53 and $1.82 per share, respectively. Dividends of $0.38 per share and $0.36 per share were paid in the first, second, third and fourth quarters in 2019 and 2018, respectively. On November 8, 2019, the Board of Directors declared a quarterly dividend of $0.39 per share to be paid from OPIC in the first quarter of 2020. The amount and timing of all dividend declarations are subject to the discretion of the Board of Directors and its consideration of business conditions, results of operations, financial condition and other factors. In addition to paying dividends from retained earnings, OE, CEI, TE, Penn, JCP&L, ME and PN have authorization from FERC to pay cash dividends to FirstEnergy from paid-in capital accounts, as long as their FERC-defined equity-to-total-capitalization ratio remains above 35%. In addition, AGC has authorization from FERC to pay cash dividends to its parent from paid-in capital accounts, as long as its FERC-defined equity-to-total-capitalization ratio remains above 45%. The articles of incorporation, indentures, regulatory limitations and various other agreements relating to the long-term debt of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock. None of these provisions materially restricted FirstEnergy’s subsidiaries’ abilities to pay cash dividends to FE as of December 31, 2019. Common Stock Issuance Additionally, FE issued approximately 3 million shares of common stock in 2019, 3.2 million shares of common stock in 2018 and 3.0 million shares of common stock in 2017 to registered shareholders and its directors and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans. On January 22, 2018, FE entered into a Common Stock Purchase Agreement for the private placement of 30,120,482 shares of FE’s common stock, par value $0.10 per share, representing an investment of $850 million ($3 million of common shares and $847 million of OPIC). Please see below for information on preferred stock converted into shares of common stock during 2018 and 2019. Preferred Stock Preference Stock Shares Authorized Par Value Shares Authorized Par Value 5,000,000 6,000,000 8,000,000 1,200,000 4,000,000 3,000,000 12,000,000 15,600,000 10,000,000 11,435,000 940,000 10,000,000 32,000,000 $ $ $ $ $ $ $ $ 100 100 25 100 8,000,000 no par no par 25 no par 3,000,000 5,000,000 $ 100 25 no par no par no par 100 0.01 no par FE OE OE Penn CEI TE TE JCP&L ME PN MP PE WP As of December 31, 2019, there were no preferred stock outstanding. As of December 31, 2019 and 2018, there were no preference stock outstanding. Preferred Stock Issuance FE entered into a Preferred Stock Purchase Agreement for the private placement of 1,616,000 shares of mandatorily convertible preferred stock, designated as the Series A Convertible Preferred Stock, par value $100 per share, representing an investment of nearly $1.62 billion ($162 million of mandatorily convertible preferred stock and $1.46 billion of OPIC). The preferred stock participated in dividends on the common stock on an as-converted basis based on the number of shares of common stock a holder of preferred stock would have received if its shares of preferred stock were converted on the dividend record date at the conversion price in effect at that time. Such dividends were paid at the same time that the dividends on common stock were paid. During 2018, 911,411 shares of preferred stock were converted into 33,238,910 shares of common stock at the option of the preferred stockholders. Also, at the option of the preferred stockholders, 494,767 shares of preferred stock were converted into 18,044,018 shares of common stock in January 2019. On July 22, 2019, 28,302 shares of preferred stock automatically converted into 1,032,165 shares of common stock, and 181,520 shares of preferred stock remained unconverted as the holder reached the 4.9% cap as outlined in the terms of the preferred stock. The remaining 181,520 preferred stock shares were converted on August 1, 2019, into 6,619,985 shares of common stock. As of December 31, 2019, 1,616,000 shares of preferred stock were converted into 58,935,078 shares of common stock and as a result, there are no preferred shares outstanding. The preferred stock included an embedded conversion option at a price that was below the fair value of the common stock on the commitment date. This beneficial conversion feature, which was approximately $296 million, represents the difference between the fair value per share of the common stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature was amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature was reflected in net income attributable to common stockholders as a deemed dividend. The beneficial conversion feature ($296 million) was fully amortized during the third quarter of 2018. Each share of preferred stock was convertible at the holder’s option into a number of shares of common stock equal to the $1,000 liquidation preference, divided by the conversion price then in effect ($27.42 per share). The conversion price was subject to anti- dilution adjustments and adjustments for subdivisions and combinations of the common stock, as well as dividends on the common stock paid in common stock and for certain equity issuances below the conversion price then in effect. 87 88 Securitized Bonds Environmental Control Bonds The consolidated financial statements of FirstEnergy include environmental control bonds issued by two bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE. Proceeds from the bonds were used to construct environmental control facilities. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of December 31, 2019 and 2018, $333 million and $358 million of environmental control bonds were outstanding, respectively. Transition Bonds In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding II and are collateralized by its equity and assets, which consist primarily of bondable transition property. As of December 31, 2019 and 2018, $25 million and $41 million of the transition bonds were outstanding, respectively. In June 2013, the SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of December 31, 2019 and 2018, $268 million and $292 million of the phase-in recovery bonds were outstanding, respectively. Other Long-term Debt The Ohio Companies and Penn each have a first mortgage indenture under which they can issue FMBs secured by a direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property. Based on the amount of FMBs authenticated by the respective mortgage bond trustees as of December 31, 2019, the sinking fund requirement for all FMBs issued under the various mortgage indentures was zero. The following table presents scheduled debt repayments for outstanding long-term debt, excluding finance leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2019. PCRBs that are scheduled to be tendered for mandatory purchase prior to maturity are reflected in the applicable year in which such PCRBs LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS The following tables present outstanding long-term debt and finance lease obligations for FirstEnergy as of December 31, 2019 and 2018: (Dollar amounts in millions) Maturity Date Interest Rate 2019 2018 As of December 31, 2019 As of December 31, FMBs and secured notes - fixed rate 2020-2059 1.726% - 8.250% $ 4,741 $ 4,355 Unsecured notes - fixed rate Unsecured notes - variable rate Finance lease obligations Unamortized debt discounts Unamortized debt issuance costs Unamortized fair value adjustments Currently payable long-term debt 2020-2049 2.850% - 7.375% 14,575 13,450 2021 2.480% 750 60 (33) (103) 8 (380) 500 73 (39) (95) 10 (503) Total long-term debt and other long-term obligations $ 19,618 $ 17,751 Phase-In Recovery Bonds On January 10, 2019, ME issued $500 million of 4.30% senior notes due 2029. Proceeds from the issuance of senior notes were primarily used to refinance existing indebtedness, including ME’s $300 million of 7.70% senior notes due 2019, and borrowings outstanding under the FE regulated utility money pool and the FE Facility, to fund capital expenditures, and for other general corporate purposes. On February 8, 2019, JCP&L issued $400 million of 4.30% senior notes due 2026. Proceeds from the issuance of the senior notes were primarily used to refinance existing indebtedness, including amounts outstanding under the FE regulated utility money pool incurred in connection with the repayment at maturity of JCP&L’s $300 million of 7.35% senior notes due 2019 and the funding of storm recovery and restoration costs and expenses, to fund capital expenditures and working capital requirements and for other general corporate purposes. On March 28, 2019, FET issued $500 million of 4.55% senior notes due 2049. Proceeds from the issuance of the senior notes were used primarily to support FET’s capital structure, to repay short-term borrowings outstanding under the FE unregulated money pool, to finance capital improvements, and for other general corporate purposes, including funding working capital needs and day-to- day operations. On April 15, 2019, ATSI issued $100 million of 4.38% senior notes due 2031. Proceeds from the issuance of the senior notes were used primarily to repay short-term borrowings, to fund capital expenditures and working capital needs, and for other general corporate purposes. On May 21, 2019, WP issued $100 million of 4.22% FMBs due 2059. Proceeds from the issuance of the FMBs were or are, as the case may be, used to refinance existing indebtedness, to fund capital expenditures, and for other general corporate purposes. are scheduled to be tendered. On June 3, 2019, PN issued $300 million of 3.60% senior notes due 2029. Proceeds from the issuance of the senior notes were used to refinance existing indebtedness, including amounts outstanding under the FE regulated companies’ money pool incurred in connection with the repayment at maturity of PN’s $125 million of 6.63% senior notes due 2019, to fund capital expenditures, and for other general corporate purposes. On June 5, 2019, AGC issued $50 million of 4.47% senior unsecured notes due 2029. Proceeds from the issuance of the senior notes were used to improve liquidity, re-establish the debt component within its capital structure following the recent redemption of all of its existing long-term debt, and satisfy working capital requirements and other general corporate purposes. On August 15, 2019, WP issued $150 million of 4.22% FMBs due 2059. Proceeds were used to refinance existing indebtedness, fund capital expenditures and for other general corporate purposes. On November 14, 2019, MP issued $155 million of 3.23% FMBs due 2029 and $45 million of 3.93% FMBs due 2049. Proceeds were used to refinance existing debt, to fund capital expenditures, and for other general corporate purposes. Debt Covenant Default Provisions See Note 8, "Leases," for additional information related to finance leases. Year 2020 2021 2022 2023 2024 (In millions) $ $ $ $ $ 364 882 1,142 1,194 1,246 Certain PCRBs allow bondholders to tender their PCRBs for mandatory purchase prior to maturity. As of December 31, 2019, MP has a $73.5 million PCRB classified as long-term debt, which the debt holders may exercise their right to tender in 2021. FirstEnergy has various debt covenants under certain financing arrangements, including its revolving credit facilities and term loans. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on such debt and the maintenance of certain financial ratios. The failure by FirstEnergy to comply with the covenants contained in its financing arrangements could result in an event of default, which may have an adverse effect on its financial condition. As of December 31, 2019, FirstEnergy remains in compliance with all debt covenant provisions. 89 90 LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS Securitized Bonds The following tables present outstanding long-term debt and finance lease obligations for FirstEnergy as of December 31, 2019 Environmental Control Bonds and 2018: (Dollar amounts in millions) Maturity Date Interest Rate 2019 2018 As of December 31, 2019 As of December 31, FMBs and secured notes - fixed rate 2020-2059 1.726% - 8.250% $ 4,741 $ 4,355 2020-2049 2.850% - 7.375% 14,575 13,450 2021 2.480% Unsecured notes - fixed rate Unsecured notes - variable rate Finance lease obligations Unamortized debt discounts Unamortized debt issuance costs Unamortized fair value adjustments Currently payable long-term debt The consolidated financial statements of FirstEnergy include environmental control bonds issued by two bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE. Proceeds from the bonds were used to construct environmental control facilities. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of December 31, 2019 and 2018, $333 million and $358 million of environmental control bonds were outstanding, respectively. Transition Bonds In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding II and are collateralized by its equity and assets, which consist primarily of bondable transition property. As of December 31, 2019 and 2018, $25 million and $41 million of the transition bonds were outstanding, respectively. 750 60 (33) (103) 8 (380) 500 73 (39) (95) 10 (503) Total long-term debt and other long-term obligations $ 19,618 $ 17,751 Phase-In Recovery Bonds In June 2013, the SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of December 31, 2019 and 2018, $268 million and $292 million of the phase-in recovery bonds were outstanding, respectively. Other Long-term Debt The Ohio Companies and Penn each have a first mortgage indenture under which they can issue FMBs secured by a direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property. Based on the amount of FMBs authenticated by the respective mortgage bond trustees as of December 31, 2019, the sinking fund requirement for all FMBs issued under the various mortgage indentures was zero. The following table presents scheduled debt repayments for outstanding long-term debt, excluding finance leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2019. PCRBs that are scheduled to be tendered for mandatory purchase prior to maturity are reflected in the applicable year in which such PCRBs are scheduled to be tendered. Year 2020 2021 2022 2023 2024 (In millions) $ $ $ $ $ 364 882 1,142 1,194 1,246 On November 14, 2019, MP issued $155 million of 3.23% FMBs due 2029 and $45 million of 3.93% FMBs due 2049. Proceeds were used to refinance existing debt, to fund capital expenditures, and for other general corporate purposes. Debt Covenant Default Provisions Certain PCRBs allow bondholders to tender their PCRBs for mandatory purchase prior to maturity. As of December 31, 2019, MP has a $73.5 million PCRB classified as long-term debt, which the debt holders may exercise their right to tender in 2021. FirstEnergy has various debt covenants under certain financing arrangements, including its revolving credit facilities and term loans. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on such debt and the maintenance of certain financial ratios. The failure by FirstEnergy to comply with the covenants contained in its financing arrangements could result in an event of default, which may have an adverse effect on its financial condition. As of December 31, 2019, FirstEnergy remains in compliance with all debt covenant provisions. 89 90 On January 10, 2019, ME issued $500 million of 4.30% senior notes due 2029. Proceeds from the issuance of senior notes were primarily used to refinance existing indebtedness, including ME’s $300 million of 7.70% senior notes due 2019, and borrowings outstanding under the FE regulated utility money pool and the FE Facility, to fund capital expenditures, and for other general corporate purposes. On February 8, 2019, JCP&L issued $400 million of 4.30% senior notes due 2026. Proceeds from the issuance of the senior notes were primarily used to refinance existing indebtedness, including amounts outstanding under the FE regulated utility money pool incurred in connection with the repayment at maturity of JCP&L’s $300 million of 7.35% senior notes due 2019 and the funding of storm recovery and restoration costs and expenses, to fund capital expenditures and working capital requirements and for other general corporate purposes. On March 28, 2019, FET issued $500 million of 4.55% senior notes due 2049. Proceeds from the issuance of the senior notes were used primarily to support FET’s capital structure, to repay short-term borrowings outstanding under the FE unregulated money pool, to finance capital improvements, and for other general corporate purposes, including funding working capital needs and day-to- On April 15, 2019, ATSI issued $100 million of 4.38% senior notes due 2031. Proceeds from the issuance of the senior notes were used primarily to repay short-term borrowings, to fund capital expenditures and working capital needs, and for other general corporate day operations. purposes. On May 21, 2019, WP issued $100 million of 4.22% FMBs due 2059. Proceeds from the issuance of the FMBs were or are, as the case may be, used to refinance existing indebtedness, to fund capital expenditures, and for other general corporate purposes. On June 3, 2019, PN issued $300 million of 3.60% senior notes due 2029. Proceeds from the issuance of the senior notes were used to refinance existing indebtedness, including amounts outstanding under the FE regulated companies’ money pool incurred in connection with the repayment at maturity of PN’s $125 million of 6.63% senior notes due 2019, to fund capital expenditures, and for other general corporate purposes. On June 5, 2019, AGC issued $50 million of 4.47% senior unsecured notes due 2029. Proceeds from the issuance of the senior notes were used to improve liquidity, re-establish the debt component within its capital structure following the recent redemption of all of its existing long-term debt, and satisfy working capital requirements and other general corporate purposes. On August 15, 2019, WP issued $150 million of 4.22% FMBs due 2059. Proceeds were used to refinance existing indebtedness, fund capital expenditures and for other general corporate purposes. See Note 8, "Leases," for additional information related to finance leases. Additionally, there are cross-default provisions in a number of the financing arrangements. These provisions generally trigger a default in the applicable financing arrangement of an entity if it or any of its significant subsidiaries, excluding AE Supply, default under another financing arrangement in excess of a certain principal amount, typically $100 million. Although such defaults by any of the Utilities, ATSI, TrAIL or MAIT would generally cross-default FE financing arrangements containing these provisions, defaults by AE Supply would generally not cross-default to applicable financing arrangements of FE. Also, defaults by FE would generally not cross-default applicable financing arrangements of any of FE’s subsidiaries. Cross-default provisions are not typically found in any of the senior notes or FMBs of FE or the Utilities. 12. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT FirstEnergy had $1,000 million and $1,250 million of short-term borrowings as of December 31, 2019 and 2018, respectively. pool. FE and the Utilities and FET and certain of its subsidiaries participate in two separate five-year syndicated revolving credit facilities providing for aggregate commitments of $3.5 billion, which are available until December 6, 2022. Under the FE credit facility, an aggregate amount of $2.5 billion is available to be borrowed, repaid and reborrowed, subject to separate borrowing sub-limits for each borrower including FE and its regulated distribution subsidiaries. Under the FET credit facility, an aggregate amount of $1.0 billion is available to be borrowed, repaid and reborrowed under a syndicated credit facility, subject to separate borrowing sub-limits for each borrower including FE's transmission subsidiaries. As of December 31, 2019, available liquidity under the FE and FET revolving credit facilities was $2,496 million (reflecting $4 million of LOCs issued under various terms) and $1,000 million respectively. $250 million of the FE Facility and $100 million of the FET Facility, subject to each borrower's sub-limit, is available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the Facilities and against the applicable borrower’s borrowing sub-limit. Borrowings under the credit facilities may be used for working capital and other general corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries. Generally, borrowings under each of the credit facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the credit facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the credit facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. The Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the Facilities is related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross- default for other indebtedness in excess of $100 million. As of December 31, 2019, the borrowers were in compliance with the applicable debt-to-total-capitalization ratio covenants in each case as defined under the respective Facilities. The minimum interest charge coverage ratio no longer applies following FE's upgrade to an investment grade credit rating. Term Loans On October 19, 2018, FE entered into two separate syndicated term loan credit agreements, the first being a $1.25 billion 364-day facility with The Bank of Nova Scotia, as administrative agent, and the lenders identified therein, and the second being a $500 million two-year facility with JPMorgan Chase Bank, N.A., as administrative agent, and the lenders identified therein, respectively, the proceeds of each were used to reduce short-term debt. The term loans contain covenants and other terms and conditions substantially similar to those of the FE revolving credit facility described above, including a consolidated debt-to-total-capitalization ratio. Effective September 11, 2019, the two credit agreements noted above were amended to change the amounts available under the existing facilities from $1.25 billion and $500 million to $1 billion and $750 million, respectively, and extend the maturity dates until September 9, 2020, and September 11, 2021, respectively. The borrowing of $1.75 billion under the term loans, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. Outstanding alternate base rate advances will bear interest at a fluctuating interest rate per annum equal to the sum of an applicable margin for alternate base rate advances determined by reference to FE’s reference ratings plus the highest of (i) the administrative agent’s publicly-announced “prime rate,” (ii) the sum of 1/2 of 1% per annum plus the Federal Funds Rate in effect from time to time and (iii) the rate of interest per annum appearing on a nationally-recognized service such as the Dow Jones Market Service (Telerate) equal to one-month LIBOR on each day plus 1%. Outstanding Eurodollar rate advances will bear interest at LIBOR for interest periods of one week or one, two, three or six months plus an applicable margin determined by reference to FE’s reference ratings. Changes in FE’s reference ratings would lower or raise its applicable margin depending on whether ratings improved or were lowered, respectively. FirstEnergy Money Pools FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2019 was 2.27% per annum for the regulated companies’ money pool and 2.74% per annum for the unregulated companies’ money Weighted Average Interest Rates 13. ASSET RETIREMENT OBLIGATIONS The weighted average interest rates on short-term borrowings outstanding, including borrowings under the FirstEnergy Money Pools, as of December 31, 2019 and 2018, were 2.88% and 3.07%, respectively. FirstEnergy has recognized applicable legal obligations for AROs and their associated cost, primarily for the decommissioning of the TMI-2 nuclear generating facility and environmental remediation, including reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks and wastewater treatment lagoons. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation. The following table summarizes the changes to the ARO balances during 2019 and 2018: ARO Reconciliation (In millions) Balance, January 1, 2018 Changes in timing and amount of estimated cash flows Liabilities settled Accretion Liabilities settled Accretion Balance, December 31, 2018 Balance, December 31, 2019 (1) $ $ $ 570 203 (1) 40 812 (2) 46 856 (1) Includes $691 million related to TMI-2 classified as held for sale. See Note 15, "Commitments, Guarantees and Contingencies," for further information. In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 17, 2018, the EPA Administrator signed a final rule extending the deadline for certain CCR facilities to cease disposal and commence closure activities, as well as, establishing less stringent groundwater monitoring and protection requirements. On August 21, 2018, the D.C. Circuit remanded sections of the CCR Rule to the EPA to provide additional safeguards for unlined CCR impoundments that are more protective of human health and the environment. On November 4, 2019, the EPA issued a proposed rule accelerating the date that certain CCR impoundments must cease accepting waste and initiate closure to August 31, 2020. The proposed rule, which includes a 60-day comment period, provides exceptions, which could allow extensions to closure dates. During the fourth quarter of 2018, based on studies completed by a third-party to reassess the estimated costs and timing to decommission TMI-2, JCP&L, ME and PN increased their ARO by a total of approximately $172 million, with a regulatory offset. The increase in the ARO resulted primarily from accelerated timing of the estimated cash flows associated with decommissioning. 14. 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 91 92 Additionally, there are cross-default provisions in a number of the financing arrangements. These provisions generally trigger a default in the applicable financing arrangement of an entity if it or any of its significant subsidiaries, excluding AE Supply, default under another financing arrangement in excess of a certain principal amount, typically $100 million. Although such defaults by any of the Utilities, ATSI, TrAIL or MAIT would generally cross-default FE financing arrangements containing these provisions, defaults by AE Supply would generally not cross-default to applicable financing arrangements of FE. Also, defaults by FE would generally not cross-default applicable financing arrangements of any of FE’s subsidiaries. Cross-default provisions are not typically found in any of the senior notes or FMBs of FE or the Utilities. 12. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT FirstEnergy had $1,000 million and $1,250 million of short-term borrowings as of December 31, 2019 and 2018, respectively. FE and the Utilities and FET and certain of its subsidiaries participate in two separate five-year syndicated revolving credit facilities providing for aggregate commitments of $3.5 billion, which are available until December 6, 2022. Under the FE credit facility, an aggregate amount of $2.5 billion is available to be borrowed, repaid and reborrowed, subject to separate borrowing sub-limits for each borrower including FE and its regulated distribution subsidiaries. Under the FET credit facility, an aggregate amount of $1.0 billion is available to be borrowed, repaid and reborrowed under a syndicated credit facility, subject to separate borrowing sub-limits for each borrower including FE's transmission subsidiaries. As of December 31, 2019, available liquidity under the FE and FET revolving credit facilities was $2,496 million (reflecting $4 million of LOCs issued under various terms) and $1,000 million respectively. $250 million of the FE Facility and $100 million of the FET Facility, subject to each borrower's sub-limit, is available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the Facilities and against the applicable borrower’s borrowing sub-limit. Borrowings under the credit facilities may be used for working capital and other general corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries. Generally, borrowings under each of the credit facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the credit facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the credit facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. The Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the Facilities is related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross- default for other indebtedness in excess of $100 million. As of December 31, 2019, the borrowers were in compliance with the applicable debt-to-total-capitalization ratio covenants in each case as defined under the respective Facilities. The minimum interest charge coverage ratio no longer applies following FE's upgrade to an investment grade credit rating. Term Loans On October 19, 2018, FE entered into two separate syndicated term loan credit agreements, the first being a $1.25 billion 364-day facility with The Bank of Nova Scotia, as administrative agent, and the lenders identified therein, and the second being a $500 million two-year facility with JPMorgan Chase Bank, N.A., as administrative agent, and the lenders identified therein, respectively, the proceeds of each were used to reduce short-term debt. The term loans contain covenants and other terms and conditions substantially similar to those of the FE revolving credit facility described above, including a consolidated debt-to-total-capitalization ratio. Effective September 11, 2019, the two credit agreements noted above were amended to change the amounts available under the existing facilities from $1.25 billion and $500 million to $1 billion and $750 million, respectively, and extend the maturity dates until September 9, 2020, and September 11, 2021, respectively. The borrowing of $1.75 billion under the term loans, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. Outstanding alternate base rate advances will bear interest at a fluctuating interest rate per annum equal to the sum of an applicable margin for alternate base rate advances determined by reference to FE’s reference ratings plus the highest of (i) the administrative agent’s publicly-announced “prime rate,” (ii) the sum of 1/2 of 1% per annum plus the Federal Funds Rate in effect from time to time and (iii) the rate of interest per annum appearing on a nationally-recognized service such as the Dow Jones Market Service (Telerate) equal to one-month LIBOR on each day plus 1%. Outstanding Eurodollar rate advances will bear interest at LIBOR for interest periods of one week or one, two, three or six months plus an applicable margin determined by reference to FE’s reference ratings. Changes in FE’s reference ratings would lower or raise its applicable margin depending on whether ratings improved or were lowered, respectively. FirstEnergy Money Pools FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2019 was 2.27% per annum for the regulated companies’ money pool and 2.74% per annum for the unregulated companies’ money pool. Weighted Average Interest Rates The weighted average interest rates on short-term borrowings outstanding, including borrowings under the FirstEnergy Money Pools, as of December 31, 2019 and 2018, were 2.88% and 3.07%, respectively. 13. ASSET RETIREMENT OBLIGATIONS FirstEnergy has recognized applicable legal obligations for AROs and their associated cost, primarily for the decommissioning of the TMI-2 nuclear generating facility and environmental remediation, including reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks and wastewater treatment lagoons. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation. The following table summarizes the changes to the ARO balances during 2019 and 2018: ARO Reconciliation (In millions) Balance, January 1, 2018 Changes in timing and amount of estimated cash flows Liabilities settled Accretion Balance, December 31, 2018 Liabilities settled $ $ 570 203 (1) 40 812 (2) 46 Accretion Balance, December 31, 2019 (1) 856 (1) Includes $691 million related to TMI-2 classified as held for sale. See Note 15, "Commitments, Guarantees and Contingencies," for further information. $ In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 17, 2018, the EPA Administrator signed a final rule extending the deadline for certain CCR facilities to cease disposal and commence closure activities, as well as, establishing less stringent groundwater monitoring and protection requirements. On August 21, 2018, the D.C. Circuit remanded sections of the CCR Rule to the EPA to provide additional safeguards for unlined CCR impoundments that are more protective of human health and the environment. On November 4, 2019, the EPA issued a proposed rule accelerating the date that certain CCR impoundments must cease accepting waste and initiate closure to August 31, 2020. The proposed rule, which includes a 60-day comment period, provides exceptions, which could allow extensions to closure dates. During the fourth quarter of 2018, based on studies completed by a third-party to reassess the estimated costs and timing to decommission TMI-2, JCP&L, ME and PN increased their ARO by a total of approximately $172 million, with a regulatory offset. The increase in the ARO resulted primarily from accelerated timing of the estimated cash flows associated with decommissioning. 14. 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 91 92 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. 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, The following table summarizes the key terms of base distribution rate orders in effect for the Utilities as of December 31, 2019: these funds will be remitted to eligible nuclear energy generators. Company CEI ME(1) MP JCP&L OE PE (West Virginia) PE (Maryland) PN(1) Penn(1) TE WP(1) (1) Reflects filed debt/equity as final settlement/orders do not specifically include capital structure. (2) Commission-approved settlement agreements did not disclose ROE rates. Rates Effective May 2009 January 2017 February 2015 January 2017 January 2009 February 2015 March 2019 January 2017 January 2017 January 2009 January 2017 Allowed Debt/ Equity 51% / 49% 48.8% / 51.2% 54% / 46% 55% / 45% 51% / 49% 54% / 46% 47% / 53% 47.4% / 52.6% 49.9% / 50.1% 51% / 49% 49.7% / 50.3% Allowed ROE 10.5% Settled(2) Settled(2) 9.6% 10.5% Settled(2) 9.65% Settled(2) Settled(2) 10.5% Settled(2) 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. Ohio. 93 94 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 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 was refunded to customers in 2019. 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 JCP&L expects to file a distribution base rate case in New Jersey in February 2020, which will seek to recover certain costs associated with providing safe and reliable electric service to JCP&L customers, along with recovery of previously incurred storm modification. costs. OHIO The Ohio Companies operate under base distribution rates approved by the PUCO effective in 2009. The Ohio Companies’ residential and commercial base distribution revenues are decoupled, through a mechanism that took effect on February 1, 2020, to the base distribution revenue and lost distribution revenue associated with energy efficiency and peak demand reduction programs recovered as of the twelve-month period ending on December 31, 2018. The Ohio Companies currently operate under ESP IV effective June 1, 2016, and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (3) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low- income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in ESP IV further 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 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. The following table summarizes the key terms of base distribution rate orders in effect for the Utilities as of December 31, 2019: Company CEI ME(1) MP JCP&L OE PN(1) Penn(1) TE WP(1) PE (West Virginia) PE (Maryland) MARYLAND Rates Effective Allowed Debt/ Equity Allowed ROE May 2009 51% / 49% January 2017 48.8% / 51.2% February 2015 January 2017 January 2009 February 2015 March 2019 54% / 46% 55% / 45% 51% / 49% 54% / 46% 47% / 53% January 2017 47.4% / 52.6% January 2017 49.9% / 50.1% January 2009 51% / 49% January 2017 49.7% / 50.3% 10.5% Settled(2) Settled(2) 9.6% 10.5% Settled(2) 9.65% Settled(2) Settled(2) 10.5% Settled(2) (1) Reflects filed debt/equity as final settlement/orders do not specifically include capital structure. (2) Commission-approved settlement agreements did not disclose ROE rates. 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 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 was refunded to customers in 2019. 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. JCP&L expects to file a distribution base rate case in New Jersey in February 2020, which will seek to recover certain costs associated with providing safe and reliable electric service to JCP&L customers, along with recovery of previously incurred storm costs. OHIO The Ohio Companies operate under base distribution rates approved by the PUCO effective in 2009. The Ohio Companies’ residential and commercial base distribution revenues are decoupled, through a mechanism that took effect on February 1, 2020, to the base distribution revenue and lost distribution revenue associated with energy efficiency and peak demand reduction programs recovered as of the twelve-month period ending on December 31, 2018. The Ohio Companies currently operate under ESP IV effective June 1, 2016, and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (3) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low- income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio. ESP IV further provided for the Ohio Companies to collect through 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 93 94 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. 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 are contesting 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. Opponents to the legislation sought to submit it to a statewide referendum, and stay its effect unless and until approved by a majority of Ohio voters. Petitioners filed a lawsuit in the U.S. District Court for the Southern District of Ohio seeking additional time to gather signatures in support of a referendum. Petitioners failed to file the necessary number of petition signatures, and the legislation took effect on October 22, 2019. On October 23, 2019, the U.S. District Court denied petitioners’ request for more time, and certified questions of state law to the SCOH to answer. Petitioners appealed the U.S. District Court’s decision to the U.S. Court of Appeals for the Sixth Circuit. The Petitioners ended their challenge to the legislation voluntarily at the end of January 2020 causing the dismissal of the appeal, the lawsuit before the U.S District Court, and the proceedings before the SCOH. On November 21, 2019, the Ohio Companies applied to the PUCO for approval of a decoupling mechanism, which would set residential and commercial base distribution related revenues at the levels collected in 2018. As such, those base distribution revenues would no longer be based on electric consumption, which allows continued support of energy efficiency initiatives while also providing revenue certainty to the Ohio Companies. On January 15, 2020, the PUCO approved the Ohio Companies’ decoupling application, and the decoupling mechanism took effect on February 1, 2020. 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 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 had broad support, including PUCO Staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties. On July 17, 2019, the PUCO approved the settlement agreement with no material modifications. On September 11, 2019, the PUCO denied the application for rehearing of environmental advocates who were not parties to the settlement. 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. 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. 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. Following a periodic review of the LTIIPs in 2018 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 May 23, 2019, the PPUC approved the Pennsylvania Companies’ Modified LTIIPs that revised LTIIP spending in 2019 of approximately $45 million by ME, $25 million by PN, $26 million by Penn and $51 million by WP, and terminating at the end of 2019. On August 30, 2019, the Pennsylvania Companies filed 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 January 16, 2020, the PPUC approved the LTIIPs without modification, as well as directed the Pennsylvania Companies to submit corrective action plans by March 16, 2020, which outline how they will reduce their pole replacement backlogs over a five-year period to a rolling two-year backlog. 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. The parties to the DSIC proceeding submitted a Joint Settlement that resolved the issues that were pending from the order issued on June 9, 2016, and 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. The Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the PPUC’s decision, and the Pennsylvania Companies contested the appeal. The Commonwealth Court reversed the PPUC’s decision of April 19, 2018 and remanded the matter to the PPUC to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. The Commonwealth Court denied Applications for Reargument in the Court’s July 11, 2019 Opinion and Order filed by the PPUC and the Pennsylvania Companies. 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, the PPUC’s Bureau of Investigation, and the Pennsylvania OCA opposed Penn’s Petition. On January 17, 2020, the parties filed a petition seeking approval of settlement that provides for a temporary increase in the recoverability cap from 5% to 7.5%, which will expire on the earlier of the effective date of new base rates following Penn’s next base rate case or the expiration of its LTIIP II program. The settlement is subject to PPUC approval. WEST VIRGINIA annually. 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 95 96 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. 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 are contesting 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. Opponents to the legislation sought to submit it to a statewide referendum, and stay its effect unless and until approved by a majority of Ohio voters. Petitioners filed a lawsuit in the U.S. District Court for the Southern District of Ohio seeking additional time to gather signatures in support of a referendum. Petitioners failed to file the necessary number of petition signatures, and the legislation took effect on October 22, 2019. On October 23, 2019, the U.S. District Court denied petitioners’ request for more time, and certified questions of state law to the SCOH to answer. Petitioners appealed the U.S. District Court’s decision to the U.S. Court of Appeals for the Sixth Circuit. The Petitioners ended their challenge to the legislation voluntarily at the end of January 2020 causing the dismissal of the appeal, the lawsuit before the U.S District Court, and the proceedings before the SCOH. On November 21, 2019, the Ohio Companies applied to the PUCO for approval of a decoupling mechanism, which would set residential and commercial base distribution related revenues at the levels collected in 2018. As such, those base distribution revenues would no longer be based on electric consumption, which allows continued support of energy efficiency initiatives while also providing revenue certainty to the Ohio Companies. On January 15, 2020, the PUCO approved the Ohio Companies’ decoupling application, and the decoupling mechanism took effect on February 1, 2020. 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 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 had broad support, including PUCO Staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties. On July 17, 2019, the PUCO approved the settlement agreement with no material modifications. On September 11, 2019, the PUCO denied the application for rehearing of environmental advocates who were not parties to the settlement. 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. 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. 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. Following a periodic review of the LTIIPs in 2018 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 May 23, 2019, the PPUC approved the Pennsylvania Companies’ Modified LTIIPs that revised LTIIP spending in 2019 of approximately $45 million by ME, $25 million by PN, $26 million by Penn and $51 million by WP, and terminating at the end of 2019. On August 30, 2019, the Pennsylvania Companies filed 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 January 16, 2020, the PPUC approved the LTIIPs without modification, as well as directed the Pennsylvania Companies to submit corrective action plans by March 16, 2020, which outline how they will reduce their pole replacement backlogs over a five-year period to a rolling two-year backlog. 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. The parties to the DSIC proceeding submitted a Joint Settlement that resolved the issues that were pending from the order issued on June 9, 2016, and 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. The Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the PPUC’s decision, and the Pennsylvania Companies contested the appeal. The Commonwealth Court reversed the PPUC’s decision of April 19, 2018 and remanded the matter to the PPUC to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. The Commonwealth Court denied Applications for Reargument in the Court’s July 11, 2019 Opinion and Order filed by the PPUC and the Pennsylvania Companies. 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, the PPUC’s Bureau of Investigation, and the Pennsylvania OCA opposed Penn’s Petition. On January 17, 2020, the parties filed a petition seeking approval of settlement that provides for a temporary increase in the recoverability cap from 5% to 7.5%, which will expire on the earlier of the effective date of new base rates following Penn’s next base rate case or the expiration of its LTIIP II program. The settlement is subject to PPUC approval. 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. 95 96 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. An order was issued on December 20, 2019, approving the ENEC settlement and termination of the PPA with Morgantown Energy Associates. 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. All the parties reached a settlement in the case, and the WVPSC issued its order approving the settlement without change on December 20, 2019. 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 REGULATORY MATTERS FERC Actions on Tax Act 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. The following table summarizes the key terms of rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities as of December 31, 2019: Company ATSI JCP&L MP PE WP MAIT TrAIL Rates Effective Capital Structure Allowed ROE January 1, 2015 June 1, 2017(1) March 21, 2018(2) March 21, 2018(2) March 21, 2018(2) July 1, 2017 Actual (13 month average) Settled(1)(3) Settled(3) Settled(3) Settled(3) Lower of Actual (13 month average) or 60% 10.38% Settled(1)(3) Settled(3) Settled(3) Settled(3) 10.3% July 1, 2008 Actual (year-end) 12.7% (TrAIL the Line & Black Oak SVC) 11.7% (All other projects) (1) Effective on January 1, 2020, JCP&L has implemented a forward-looking formula rate, which has been accepted by FERC, subject to refund, pending further hearing and settlement proceedings. (2) See FERC Actions on Tax Act below. (3) FERC-approved settlement agreements did not specify. 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 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 864). Order 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. Alternatively, formula rate utilities can demonstrate to FERC that their formula rate template already achieves these outcomes. Utilities with transmission stated rates are required to address these new requirements as part of their next transmission rate case. 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. FirstEnergy’s formula rate transmission utilities will make the required filings on or before the deadlines established in FERC’s order. FirstEnergy’s stated rate transmission utilities will address the requirements as part of their next transmission rate case. JCP&L is addressing the requirements in the course of its pending transmission rate case. Transmission ROE Methodology FERC’s methodology for calculating electric transmission utility ROE has been in transition as a result of an April 14, 2017 ruling by the D.C. Circuit that vacated FERC’s then-effective methodology. On October 16, 2018, FERC issued an order in which it proposed a revised ROE methodology. FERC proposed that, for complaint proceedings alleging that an existing ROE is not just and reasonable, FERC will 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. On November 21, 2019, FERC announced in a complaint proceeding involving MISO utilities that FERC would rely on the discounted cash flow and capital-asset pricing models as the basis for establishing ROE. It is not clear at this time whether FERC’s November ruling will be applied more broadly. 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 FERC dockets where the ROE methodology is being reviewed, and on December 23, 2019, JCP&L filed a request for rehearing of FERC’s November decision in the MISO utilities docket. JCP&L Transmission Formula Rate On October 30, 2019, JCP&L filed tariff amendments with FERC to convert JCP&L’s existing stated transmission rate to a forward- looking formula transmission rate. JCP&L requested that the tariff amendments become effective January 1, 2020. On December 19, 2019, FERC issued its initial order in the case, allowing JCP&L to transition to a forward-looking formula rate as of January 1, 2020 as requested, subject to refund, pending further hearing and settlement proceedings. JCP&L is engaged in settlement negotiations. 97 98 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 ENEC rates into 2020, and supports the termination of the Morgantown Energy Associates PPA, was filed with the WVPSC on October 18, 2019. An order was issued on December 20, 2019, approving the ENEC settlement and termination of the PPA with Morgantown Energy Associates. 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. All the parties reached a settlement in the case, and the WVPSC issued its order approving the settlement without change on December 20, 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 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. The following table summarizes the key terms of rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities as of December 31, 2019: Company ATSI JCP&L MP PE WP MAIT TrAIL Rates Effective Capital Structure Allowed ROE January 1, 2015 Actual (13 month average) June 1, 2017(1) March 21, 2018(2) March 21, 2018(2) March 21, 2018(2) Settled(1)(3) Settled(3) Settled(3) Settled(3) July 1, 2017 Lower of Actual (13 month average) or 60% 10.38% Settled(1)(3) Settled(3) Settled(3) Settled(3) 10.3% (1) Effective on January 1, 2020, JCP&L has implemented a forward-looking formula rate, which has been accepted by FERC, subject to July 1, 2008 Actual (year-end) 12.7% (TrAIL the Line & Black Oak SVC) 11.7% (All other projects) refund, pending further hearing and settlement proceedings. (2) See FERC Actions on Tax Act below. (3) FERC-approved settlement agreements did not specify. 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 NUG entity. A settlement between MP, PE, and the majority of the intervenors fully resolving the ENEC case, which maintains 2019 RTO Realignment 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. FERC REGULATORY MATTERS FERC Actions on Tax Act On March 15, 2018, FERC initiated proceedings on the question of how to address possible changes to ADIT and bonus depreciation as a result of the Tax Act. Such possible changes could impact FERC-jurisdictional rates, including transmission rates. On November 21, 2019, FERC issued a final rule (Order 864). Order 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. Alternatively, formula rate utilities can demonstrate to FERC that their formula rate template already achieves these outcomes. Utilities with transmission stated rates are required to address these new requirements as part of their next transmission rate case. 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. FirstEnergy’s formula rate transmission utilities will make the required filings on or before the deadlines established in FERC’s order. FirstEnergy’s stated rate transmission utilities will address the requirements as part of their next transmission rate case. JCP&L is addressing the requirements in the course of its pending transmission rate case. Transmission ROE Methodology FERC’s methodology for calculating electric transmission utility ROE has been in transition as a result of an April 14, 2017 ruling by the D.C. Circuit that vacated FERC’s then-effective methodology. On October 16, 2018, FERC issued an order in which it proposed a revised ROE methodology. FERC proposed that, for complaint proceedings alleging that an existing ROE is not just and reasonable, FERC will 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. On November 21, 2019, FERC announced in a complaint proceeding involving MISO utilities that FERC would rely on the discounted cash flow and capital-asset pricing models as the basis for establishing ROE. It is not clear at this time whether FERC’s November ruling will be applied more broadly. 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 FERC dockets where the ROE methodology is being reviewed, and on December 23, 2019, JCP&L filed a request for rehearing of FERC’s November decision in the MISO utilities docket. JCP&L Transmission Formula Rate On October 30, 2019, JCP&L filed tariff amendments with FERC to convert JCP&L’s existing stated transmission rate to a forward- looking formula transmission rate. JCP&L requested that the tariff amendments become effective January 1, 2020. On December 19, 2019, FERC issued its initial order in the case, allowing JCP&L to transition to a forward-looking formula rate as of January 1, 2020 as requested, subject to refund, pending further hearing and settlement proceedings. JCP&L is engaged in settlement negotiations. 97 98 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES NUCLEAR INSURANCE JCP&L, ME and PN maintain property damage insurance provided by NEIL for their interest in the retired TMI- 2 nuclear facility, a permanently shut down and defueled facility. Under these arrangements, up to $150 million of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. JCP&L, ME and PN pay annual premiums and are subject to retrospective premium assessments of up to approximately $1.2 million during a policy year. JCP&L, ME and PN intend to maintain insurance against nuclear risks as long as it is available. To the extent that property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of JCP&L, ME or PN’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by JCP&L, ME or PN’s insurance policies, or to the extent such insurance becomes unavailable in the future, JCP&L, ME or PN would remain at risk for such costs. The Price-Anderson Act limits public liability relative to a single incident at a nuclear power plant. In connection with TMI-2, JCP&L, ME and PN carry the required ANI third party liability coverage and also have coverage under a Price Anderson indemnity agreement issued by the NRC. The total available coverage in the event of a nuclear incident is $560 million, which is also the limit of public liability for any nuclear incident involving TMI-2. GUARANTEES AND OTHER ASSURANCES FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. condition. Clean Air Act As of December 31, 2019, outstanding guarantees and other assurances aggregated approximately $1.6 billion, consisting of guarantees on behalf of the FES Debtors ($350 million), parental guarantees on behalf of its consolidated subsidiaries' guarantees ($1.0 billion), other guarantees ($114 million) and other assurances ($151 million). FirstEnergy has also committed to provide certain additional guarantees to the FES Debtors for retained environmental liabilities of AE Supply related to the Pleasants Power Station and McElroy's Run CCR disposal facility as part of the settlement agreement in connection with the FES Bankruptcy. COLLATERAL AND CONTINGENT-RELATED FEATURES In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on AE Supply's power portfolio exposure as of December 31, 2019, AE Supply has posted no collateral. The Utilities and Transmission Companies have posted no collateral. These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of December 31, 2019: Potential Collateral Obligations Contractual Obligations for Additional Collateral At Current Credit Rating Upon Further Downgrade Surety Bonds (Collateralized Amount)(1) Total Exposure from Contractual Obligations AE Supply Utilities and FET FE Total (In millions) 1 — — 1 $ $ — $ — $ 36 63 99 $ — 257 257 $ 1 36 320 357 $ $ 99 Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield's Ferry CCR disposal site, respectively. OTHER COMMITMENTS AND CONTINGENCIES FE is a guarantor under a $120 million syndicated senior secured term loan facility due November 12, 2024, under which Global Holding's outstanding principal balance is $114 million as of December 31, 2019. In addition to FE, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several guaranties of the obligations of Global Holding under the facility. In connection with the facility, 69.99% of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral. ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy's environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances. CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry's bid for a lengthy pause in the litigation and set a briefing schedule. On September 13, 2019, the D.C. Circuit remanded the CSAPR update rule to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may materially impact FirstEnergy's operations, cash flows and financial condition. In February 2019, the EPA announced its final decision to retain without changes the NAAQS for SO2, specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB. As of September 30, 2019, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA. In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility's NOx emissions significantly contribute to Delaware's inability to attain the ozone NAAQS. The petition sought a short-term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3 and Pleasants Units 1 and 2, significantly contribute to Maryland's inability to attain the ozone NAAQS. The petition sought NOx emission rate limits for the 36 EGUs by May 1, 2017. On September 14, 2018, the EPA denied both the States of Delaware and Maryland's petitions under CAA Section 126. In October 2018, Delaware and Maryland appealed the denials of their petitions to the D.C. Circuit. In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including Ohio, Pennsylvania and West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. On May 3, 2018, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to November 9, 2018. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss. 100 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES NUCLEAR INSURANCE JCP&L, ME and PN maintain property damage insurance provided by NEIL for their interest in the retired TMI- 2 nuclear facility, a permanently shut down and defueled facility. Under these arrangements, up to $150 million of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. JCP&L, ME and PN pay annual premiums and are subject to retrospective premium assessments of up to approximately $1.2 million during a policy year. JCP&L, ME and PN intend to maintain insurance against nuclear risks as long as it is available. To the extent that property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of JCP&L, ME or PN’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by JCP&L, ME or PN’s insurance policies, or to the extent such insurance becomes unavailable in the future, JCP&L, ME or PN would remain at risk for such costs. The Price-Anderson Act limits public liability relative to a single incident at a nuclear power plant. In connection with TMI-2, JCP&L, ME and PN carry the required ANI third party liability coverage and also have coverage under a Price Anderson indemnity agreement issued by the NRC. The total available coverage in the event of a nuclear incident is $560 million, which is also the limit of public liability for any nuclear incident involving TMI-2. GUARANTEES AND OTHER ASSURANCES FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. As of December 31, 2019, outstanding guarantees and other assurances aggregated approximately $1.6 billion, consisting of guarantees on behalf of the FES Debtors ($350 million), parental guarantees on behalf of its consolidated subsidiaries' guarantees ($1.0 billion), other guarantees ($114 million) and other assurances ($151 million). FirstEnergy has also committed to provide certain additional guarantees to the FES Debtors for retained environmental liabilities of AE Supply related to the Pleasants Power Station and McElroy's Run CCR disposal facility as part of the settlement agreement in connection with the FES Bankruptcy. COLLATERAL AND CONTINGENT-RELATED FEATURES In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on AE Supply's power portfolio exposure as of December 31, 2019, AE Supply has posted no collateral. The Utilities and Transmission Companies have posted no collateral. These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of December 31, 2019: Potential Collateral Obligations Contractual Obligations for Additional Collateral At Current Credit Rating Upon Further Downgrade Surety Bonds (Collateralized Amount)(1) Total Exposure from Contractual Obligations AE Supply Utilities and FET FE Total (In millions) 1 — — 1 $ $ — $ — $ 36 63 99 — 257 257 $ $ 1 36 320 357 $ $ 99 Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield's Ferry CCR disposal site, respectively. OTHER COMMITMENTS AND CONTINGENCIES FE is a guarantor under a $120 million syndicated senior secured term loan facility due November 12, 2024, under which Global Holding's outstanding principal balance is $114 million as of December 31, 2019. In addition to FE, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several guaranties of the obligations of Global Holding under the facility. In connection with the facility, 69.99% of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral. ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy's environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition. Clean Air Act FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances. CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry's bid for a lengthy pause in the litigation and set a briefing schedule. On September 13, 2019, the D.C. Circuit remanded the CSAPR update rule to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may materially impact FirstEnergy's operations, cash flows and financial condition. In February 2019, the EPA announced its final decision to retain without changes the NAAQS for SO2, specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB. As of September 30, 2019, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA. In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility's NOx emissions significantly contribute to Delaware's inability to attain the ozone NAAQS. The petition sought a short-term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3 and Pleasants Units 1 and 2, significantly contribute to Maryland's inability to attain the ozone NAAQS. The petition sought NOx emission rate limits for the 36 EGUs by May 1, 2017. On September 14, 2018, the EPA denied both the States of Delaware and Maryland's petitions under CAA Section 126. In October 2018, Delaware and Maryland appealed the denials of their petitions to the D.C. Circuit. In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including Ohio, Pennsylvania and West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. On May 3, 2018, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to November 9, 2018. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss. 100 Climate Change There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation. At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide GHG emissions by 26 to 28 percent below 2005 levels by 2025. In 2015, FirstEnergy set a goal of reducing company-wide CO2 emissions by at least 90 percent below 2005 levels by 2045. As of December 31, 2018, FirstEnergy has reduced its CO2 emissions by approximately 62 percent. In September 2016, the U.S. joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHG under the Clean Air Act,” concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. The EPA released its final CPP regulations in August 2015 to reduce CO2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. To replace the CPP, the EPA proposed the ACE rule on August 21, 2018, which would establish emission guidelines for states to develop plans to address GHG emissions from existing coal-fired power plants. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that establishes guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired power plants. Depending on the outcomes of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material. Clean Water Act Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material. On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations phase-in as permits are renewed on a five-year cycle from 2018 to 2023. On April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On November 4, 2019, the EPA issued a proposed rule revising the effluent limits for discharges from wet scrubber systems and extending the deadline for compliance to December 31, 2025. The EPA’s proposed rule retains the zero discharge standard and 2023 compliance date for ash transport water, but adds some allowances for discharge under certain circumstances. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's operations may result. On September 29, 2016, FirstEnergy received a request from the EPA for information pursuant to CWA Section 308(a) for information concerning boron exceedances of effluent limitations established in the NPDES Permit for the former Mitchell Power Station’s Mingo landfill, owned by WP. On November 1, 2016, WP provided an initial response that contained information related to a similar boron issue at the former Springdale Power Station’s landfill. The EPA requested additional information regarding the Springdale landfill and on November 15, 2016, WP provided a response and intends to fully comply with the Section 308(a) information request. On March 3, 2017, WP proposed to the PA DEP a re-route of its wastewater discharge to eliminate potential boron exceedances at the Springdale landfill. On January 29, 2018, WP submitted an NPDES permit renewal application to PA DEP proposing to re-route its wastewater discharge to eliminate potential boron exceedances at the Mingo landfill. On February 20, 2018, the DOJ issued a letter and tolling agreement on behalf of EPA alleging violations of the CWA at the Mingo landfill while seeking to enter settlement negotiations in lieu of filing a complaint. On November 4, 2019, the EPA proposed a penalty of nearly $1.3 million to settle alleged past boron exceedances at the Mingo and Springdale landfills. On December 17, 2019, WP responded to the EPA's settlement proposal but is unable to predict the outcome of this matter. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 17, 2018, the EPA Administrator signed a final rule extending the deadline for certain CCR facilities to cease disposal and commence closure activities, as well as, establishing less stringent groundwater monitoring and protection requirements. On August 21, 2018, the D.C. Circuit remanded sections of the CCR Rule to the EPA to provide additional safeguards for unlined CCR impoundments that are more protective of human health and the environment. On November 4, 2019, the EPA issued a proposed rule accelerating the date that certain CCR impoundments must cease accepting waste and initiate closure to August 31, 2020. The proposed rule, which includes a 60-day comment period, provides exceptions, which could allow extensions to closure dates. FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 2019, based on estimates of the total costs of cleanup, FirstEnergy's proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $109 million have been accrued through December 31, 2019. Included in the total are accrued liabilities of approximately $77 million for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time. OTHER LEGAL PROCEEDINGS Nuclear Plant Matters Under NRC regulations, JCP&L, ME and PN must ensure that adequate funds will be available to decommission their retired nuclear facility, TMI-2. As of December 31, 2019, JCP&L, ME and PN had in total approximately $882 million invested in external trusts to be used for the decommissioning and environmental remediation of their retired TMI-2 nuclear generating facility. The values of these NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, the obligation to JCP&L, ME and PN to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs. On October 15, 2019, JCP&L, ME, PN and GPUN executed an asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of EnergySolutions, LLC, concerning the transfer and dismantlement of TMI-2. This transfer of TMI-2 to TMI-2 Solutions, LLC will include the transfer of: (i) the ownership and operating NRC licenses for TMI-2; (ii) the external trusts for the decommissioning and environmental remediation of TMI-2; and (iii) related liabilities of approximately $900 million as of December 31, 2019. There can be no assurance that the transfer will receive the required regulatory approvals and, even if approved, whether the conditions to the closing of the transfer will be satisfied. On November 12, 2019, JCP&L filed a Petition with the NJBPU seeking approval of the transfer and sale of JCP&L’s entire 25% interest in TMI-2 to TMI-2 Solutions, LLC. Also on November 12, 2019, JCP&L, ME, PN, GPUN and TMI-2 Solutions, LLC filed an application with the NRC seeking approval to transfer the NRC license for TMI-2 to TMI-2 Solutions, LLC. Both proceedings are ongoing. Assets and liabilities held for sale on the FirstEnergy Consolidated Balance Sheet associated with the transaction consist of asset retirement obligations of $691 million, NDTs of $882 million as well as property, plant and equipment with a net book value of zero, which are included in the regulated distribution segment. FES Bankruptcy On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FGMUC, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. See Note 3, "Discontinued Operations," for additional information. 101 102 Climate Change There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation. At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide GHG emissions by 26 to 28 percent below 2005 levels by 2025. In 2015, FirstEnergy set a goal of reducing company-wide CO2 emissions by at least 90 percent below 2005 levels by 2045. As of December 31, 2018, FirstEnergy has reduced its CO2 emissions by approximately 62 percent. In September 2016, the U.S. joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHG under the Clean Air Act,” concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. The EPA released its final CPP regulations in August 2015 to reduce CO2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. To replace the CPP, the EPA proposed the ACE rule on August 21, 2018, which would establish emission guidelines for states to develop plans to address GHG emissions from existing coal-fired power plants. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that establishes guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired power plants. Depending on the outcomes of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material. Clean Water Act Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material. On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations phase-in as permits are renewed on a five-year cycle from 2018 to 2023. On April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On November 4, 2019, the EPA issued a proposed rule revising the effluent limits for discharges from wet scrubber systems and extending the deadline for compliance to December 31, 2025. The EPA’s proposed rule retains the zero discharge standard and 2023 compliance date for ash transport water, but adds some allowances for discharge under certain circumstances. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's operations may result. On September 29, 2016, FirstEnergy received a request from the EPA for information pursuant to CWA Section 308(a) for information concerning boron exceedances of effluent limitations established in the NPDES Permit for the former Mitchell Power Station’s Mingo landfill, owned by WP. On November 1, 2016, WP provided an initial response that contained information related to a similar boron issue at the former Springdale Power Station’s landfill. The EPA requested additional information regarding the Springdale landfill and on November 15, 2016, WP provided a response and intends to fully comply with the Section 308(a) information request. On March 3, 2017, WP proposed to the PA DEP a re-route of its wastewater discharge to eliminate potential boron exceedances at the Springdale landfill. On January 29, 2018, WP submitted an NPDES permit renewal application to PA DEP proposing to re-route its wastewater discharge to eliminate potential boron exceedances at the Mingo landfill. On February 20, 2018, the DOJ issued a letter and tolling agreement on behalf of EPA alleging violations of the CWA at the Mingo landfill while seeking to enter settlement negotiations in lieu of filing a complaint. On November 4, 2019, the EPA proposed a penalty of nearly $1.3 million to settle alleged past boron exceedances at the Mingo and Springdale landfills. On December 17, 2019, WP responded to the EPA's settlement proposal but is unable to predict the outcome of this matter. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 17, 2018, the EPA Administrator signed a final rule extending the deadline for certain CCR facilities to cease disposal and commence closure activities, as well as, establishing less stringent groundwater monitoring and protection requirements. On August 21, 2018, the D.C. Circuit remanded sections of the CCR Rule to the EPA to provide additional safeguards for unlined CCR impoundments that are more protective of human health and the environment. On November 4, 2019, the EPA issued a proposed rule accelerating the date that certain CCR impoundments must cease accepting waste and initiate closure to August 31, 2020. The proposed rule, which includes a 60-day comment period, provides exceptions, which could allow extensions to closure dates. FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 2019, based on estimates of the total costs of cleanup, FirstEnergy's proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $109 million have been accrued through December 31, 2019. Included in the total are accrued liabilities of approximately $77 million for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time. OTHER LEGAL PROCEEDINGS Nuclear Plant Matters Under NRC regulations, JCP&L, ME and PN must ensure that adequate funds will be available to decommission their retired nuclear facility, TMI-2. As of December 31, 2019, JCP&L, ME and PN had in total approximately $882 million invested in external trusts to be used for the decommissioning and environmental remediation of their retired TMI-2 nuclear generating facility. The values of these NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, the obligation to JCP&L, ME and PN to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs. On October 15, 2019, JCP&L, ME, PN and GPUN executed an asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of EnergySolutions, LLC, concerning the transfer and dismantlement of TMI-2. This transfer of TMI-2 to TMI-2 Solutions, LLC will include the transfer of: (i) the ownership and operating NRC licenses for TMI-2; (ii) the external trusts for the decommissioning and environmental remediation of TMI-2; and (iii) related liabilities of approximately $900 million as of December 31, 2019. There can be no assurance that the transfer will receive the required regulatory approvals and, even if approved, whether the conditions to the closing of the transfer will be satisfied. On November 12, 2019, JCP&L filed a Petition with the NJBPU seeking approval of the transfer and sale of JCP&L’s entire 25% interest in TMI-2 to TMI-2 Solutions, LLC. Also on November 12, 2019, JCP&L, ME, PN, GPUN and TMI-2 Solutions, LLC filed an application with the NRC seeking approval to transfer the NRC license for TMI-2 to TMI-2 Solutions, LLC. Both proceedings are ongoing. Assets and liabilities held for sale on the FirstEnergy Consolidated Balance Sheet associated with the transaction consist of asset retirement obligations of $691 million, NDTs of $882 million as well as property, plant and equipment with a net book value of zero, which are included in the regulated distribution segment. FES Bankruptcy On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FGMUC, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. See Note 3, "Discontinued Operations," for additional information. 101 102 Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 14, "Regulatory Matters." company debt. Financial information for each of FirstEnergy’s reportable segments is presented in the tables below: transactions and discontinued operations are shown separately in the following table of Segment Financial Information. As of December 31, 2019, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was included in continuing operations of Corporate/Other. As of December 31, 2019, Corporate/Other had approximately $7.1 billion of FE holding FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE's or its subsidiaries' financial condition, results of operations and cash flows. 16. TRANSACTIONS WITH AFFILIATED COMPANIES FE does not bill directly or allocate any of its costs to any subsidiary company. Costs are charged to FE's subsidiaries, as well as FES and FENOC, for services received from FESC. The majority of costs are directly billed or assigned at no more than cost. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC. The current allocation or assignment formulas used and their bases include multiple factor formulas: each company’s proportionate amount of FirstEnergy’s aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Intercompany transactions are generally settled under commercial terms within thirty days. The Utilities and Transmission Companies are parties to an intercompany income tax allocation agreement with FE and its other subsidiaries, including FES and FENOC, that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FE are generally reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit (see Note 7, "Taxes"). Additionally, the Utilities purchase power from FES to meet a portion of their POLR and default service requirements and provide power to certain facilities. See Note 3, "Discontinued Operations" for additional details. 17. SEGMENT INFORMATION Regulated Distribution and Regulated Transmission are FirstEnergy's reportable segments. On March 31, 2018, as discussed in Note 3, “Discontinued Operations,” FirstEnergy deconsolidated FES and FENOC and presented FES, FENOC, BSPC and a portion of AE Supply, representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, as discontinued operations in FirstEnergy’s consolidated financial statements resulting from actions taken as part of the strategic review to exit commodity-exposed generation. The financial information for all periods has been revised to present the discontinued operations within Reconciling Adjustments. The remaining business activities that previously comprised the CES reportable operating segment were not material and, as such, have been combined into Corporate/ Other for reporting purposes. The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment's results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs. Included within the segment are $882 million of assets classified as held for sale associated with the asset purchase and sale agreement with TMI-2 Solutions to transfer TMI-2 to TMI-2 Solutions, LLC. See Note 15, "Commitments, Guarantees and Contingencies" for additional information. The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are primarily derived from forward-looking formula rates at the Transmission Companies as well as stated transmission rates at JCP&L, MP, PE and WP. Effective January 1, 2020, JPC&L's transmission rates became forward-looking formula rates, subject to refund, pending further hearing and settlement proceedings. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities. Corporate/Other reflects corporate support not charged to FE's subsidiaries, interest expense on FE’s holding company debt and other businesses that do not constitute an operating segment. Reconciling adjustments for the elimination of inter-segment Segment Financial Information For the Years Ended December 31, 2019 External revenues Internal revenues Total revenues Provision for depreciation Amortization (deferral) of regulatory assets, net Miscellaneous income (expense), net Interest expense Income taxes (benefits) Income (loss) from continuing operations Property additions December 31, 2018 External revenues Internal revenues Total revenues Provision for depreciation Amortization (deferral) of regulatory assets, net Miscellaneous income (expense), net Interest expense Income taxes (benefits) Income (loss) from continuing operations Property additions December 31, 2017 External revenues Internal revenues Total revenues Provision for depreciation Amortization of regulatory assets, net Miscellaneous income (expense), net Interest expense Income taxes Property additions Income (loss) from continuing operations As of December 31, 2019 Total assets Total goodwill As of December 31, 2018 Total assets Total goodwill As of December 31, 2017 Total assets Total goodwill $ $ $ $ $ $ $ $ $ $ $ Regulated Distribution Regulated Transmission Corporate/ Other Reconciling Adjustments FirstEnergy Consolidated (In millions) $ 9,511 $ 1,510 $ $ — $ 11,035 1,473 $ 1,090 $ 102 $ — $ 9,900 $ 1,335 $ $ — $ 11,261 187 9,698 863 (89) 174 495 271 1,076 203 10,103 812 (163) 192 514 422 1,242 158 9,760 724 292 57 535 580 916 16 1,526 284 10 15 192 113 447 18 1,353 252 13 14 167 122 397 17 1,324 224 16 1 156 205 336 372 (171) (619) 468 (54) (617) 14 — 14 5 — 80 26 8 34 3 — 32 19 24 43 10 — 39 358 930 (1,541) (203) (203) 68 — (26) (26) — — (229) (229) 69 — (33) (33) — — 27 (199) (199) 69 — (44) (44) — — — 11,035 1,220 (79) 243 1,033 213 904 2,665 — 11,261 1,136 (150) 205 1,116 490 1,022 2,675 — 10,928 1,027 308 53 1,005 1,715 (289) 2,587 1,411 $ 1,104 $ 133 $ $ 9,602 $ 1,307 $ $ — $ 10,928 1,191 $ 1,030 $ 49 $ 317 $ 29,642 5,004 28,690 5,004 27,730 5,004 $ $ $ $ $ $ 11,611 614 10,404 614 9,525 614 $ $ $ $ $ $ 1,015 $ — $ 33 $ — $ 42,301 5,618 944 $ — $ 25 $ — $ 40,063 5,618 1,007 $ 3,995 $ — $ — $ 42,257 5,618 103 104 Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 14, "Regulatory Matters." FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE's or its subsidiaries' financial condition, results of operations and cash flows. 16. TRANSACTIONS WITH AFFILIATED COMPANIES FE does not bill directly or allocate any of its costs to any subsidiary company. Costs are charged to FE's subsidiaries, as well as FES and FENOC, for services received from FESC. The majority of costs are directly billed or assigned at no more than cost. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified The Utilities and Transmission Companies are parties to an intercompany income tax allocation agreement with FE and its other subsidiaries, including FES and FENOC, that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FE are generally reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit (see Note 7, "Taxes"). Additionally, the Utilities purchase power from FES to meet a portion of their POLR and default service requirements and provide power to certain facilities. See Note 3, "Discontinued Operations" for additional details. 17. SEGMENT INFORMATION Regulated Distribution and Regulated Transmission are FirstEnergy's reportable segments. On March 31, 2018, as discussed in Note 3, “Discontinued Operations,” FirstEnergy deconsolidated FES and FENOC and presented FES, FENOC, BSPC and a portion of AE Supply, representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, as discontinued operations in FirstEnergy’s consolidated financial statements resulting from actions taken as part of the strategic review to exit commodity-exposed generation. The financial information for all periods has been revised to present the discontinued operations within Reconciling Adjustments. The remaining business activities that previously comprised the CES reportable operating segment were not material and, as such, have been combined into Corporate/ Other for reporting purposes. The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment's results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs. Included within the segment are $882 million of assets classified as held for sale associated with the asset purchase and sale agreement with TMI-2 Solutions to transfer TMI-2 to TMI-2 Solutions, LLC. See Note 15, "Commitments, Guarantees and Contingencies" for additional information. The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are primarily derived from forward-looking formula rates at the Transmission Companies as well as stated transmission rates at JCP&L, MP, PE and WP. Effective January 1, 2020, JPC&L's transmission rates became forward-looking formula rates, subject to refund, pending further hearing and settlement proceedings. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities. Corporate/Other reflects corporate support not charged to FE's subsidiaries, interest expense on FE’s holding company debt and other businesses that do not constitute an operating segment. Reconciling adjustments for the elimination of inter-segment transactions and discontinued operations are shown separately in the following table of Segment Financial Information. As of December 31, 2019, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was included in continuing operations of Corporate/Other. As of December 31, 2019, Corporate/Other had approximately $7.1 billion of FE holding company debt. Financial information for each of FirstEnergy’s reportable segments is presented in the tables below: and are allocated using formulas developed by FESC. The current allocation or assignment formulas used and their bases include Miscellaneous income (expense), net multiple factor formulas: each company’s proportionate amount of FirstEnergy’s aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Intercompany transactions are generally settled under commercial terms within thirty days. Interest expense Income taxes (benefits) Income (loss) from continuing operations Segment Financial Information For the Years Ended December 31, 2019 External revenues Internal revenues Total revenues Provision for depreciation Amortization (deferral) of regulatory assets, net Regulated Distribution Regulated Transmission Corporate/ Other Reconciling Adjustments FirstEnergy Consolidated (In millions) $ 9,511 $ 1,510 $ $ — $ 187 9,698 863 (89) 174 495 271 1,076 16 1,526 284 10 15 192 113 447 1,473 $ 1,090 $ 9,900 $ 1,335 $ 203 10,103 812 (163) 192 514 422 1,242 18 1,353 252 13 14 167 122 397 1,411 $ 1,104 $ 9,602 $ 1,307 $ 17 1,324 224 16 1 156 205 336 158 9,760 724 292 57 535 580 916 1,191 29,642 5,004 28,690 5,004 27,730 5,004 $ $ $ $ $ $ $ 14 — 14 5 — 80 372 (171) (619) 102 26 8 34 3 — 32 468 (54) (617) 133 19 24 43 10 — 39 358 930 (1,541) $ $ $ $ (203) (203) 68 — (26) (26) — — — $ — $ (229) (229) 69 — (33) (33) — — 27 $ — $ (199) (199) 69 — (44) (44) — — 317 $ 11,035 — 11,035 1,220 (79) 243 1,033 213 904 2,665 11,261 — 11,261 1,136 (150) 205 1,116 490 1,022 2,675 10,928 — 10,928 1,027 308 53 1,005 1,715 (289) 2,587 1,030 $ 49 $ 11,611 614 10,404 614 9,525 614 $ $ $ $ $ $ 1,015 $ — $ 33 $ — $ 42,301 5,618 944 $ — $ 25 $ — $ 40,063 5,618 1,007 $ 3,995 $ — $ — $ 42,257 5,618 Property additions December 31, 2018 External revenues Internal revenues Total revenues Provision for depreciation Amortization (deferral) of regulatory assets, net Miscellaneous income (expense), net Interest expense Income taxes (benefits) Income (loss) from continuing operations Property additions December 31, 2017 External revenues Internal revenues Total revenues Provision for depreciation Amortization of regulatory assets, net Miscellaneous income (expense), net Interest expense Income taxes Income (loss) from continuing operations Property additions As of December 31, 2019 Total assets Total goodwill As of December 31, 2018 Total assets Total goodwill As of December 31, 2017 Total assets Total goodwill $ $ $ $ $ $ $ $ $ $ $ 103 104 18. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED) CONTROLS AND PROCEDURES The following summarizes certain consolidated operating results by quarter for 2019 and 2018. Evaluation of Disclosure Controls and Procedures FirstEnergy CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions, except per share amounts) 2019 2018 Revenues Other operating expense Provision for depreciation Operating Income Pension and OPEB mark-to-market adjustment Income before income taxes Income taxes Income from continuing operations Discontinued operations (1) (Note 3) Net Income (Loss) Income allocated to preferred stockholders (2) Net income (loss) attributable to common stockholders Earnings (loss) per share of common stock-(3) Basic - Continuing Operations Basic - Discontinued Operations (Note 3) Basic - Net Income (Loss) Attributable to Common Stockholders Diluted - Continuing Operations Diluted - Discontinued Operations (Note 3) Diluted - Net Income (Loss) Attributable to Common Stockholders Dec. 31 Sep. 30 Jun. 30 Mar. 31 Dec. 31 Sep. 30 Jun. 30 Mar. 31 $ 2,673 $ 2,963 $ 2,516 $ 2,883 $ 2,710 $ 3,064 $ 2,625 $ 2,862 of the period covered by this report. 809 310 615 (674) (249) (68) (181) 70 (111) — (111) (0.33) 0.13 (0.20) (0.33) 0.13 758 304 681 — 496 107 389 2 391 — 391 0.72 0.01 0.73 0.72 — 606 309 585 — 422 81 341 (29) 312 4 779 297 629 — 448 93 355 (35) 320 5 308 315 0.63 0.66 (0.05) (0.07) 0.58 0.63 0.59 0.66 (0.05) (0.07) 770 293 512 (144) 169 35 134 4 138 10 128 0.24 0.01 0.25 0.24 0.01 739 283 710 — 520 121 399 (857) (458) 54 684 283 700 — 409 101 308 (9) 299 165 940 277 580 — 414 233 181 1,188 1,369 156 (512) 134 1,213 0.68 0.30 (1.70) (0.02) (1.02) 0.68 0.28 0.30 (1.70) (0.02) 0.05 2.50 2.55 0.05 2.49 (0.20) 0.72 0.58 0.59 0.25 (1.02) 0.28 2.54 (1) Net of income taxes (2) The sum of quarterly income allocated to preferred stockholders may not equal annual income allocated to preferred stockholders as quarter- to-date and year-to-date amounts are calculated independently. (3) The sum of quarterly earnings per share information may not equal annual earnings per share due to the issuance of shares and conversion of preferred shares throughout the year. See the FirstEnergy Consolidated Statements of Stockholders' Equity and Note 6, "Stock-Based Compensation Plans," for additional information. The management of FirstEnergy, with the participation of the chief executive officer and chief financial officer, has reviewed and evaluated the effectiveness of their registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, Rules 13a-15(e) and 15d-15(e), as of the end of the period covered by this report. Based on that evaluation, the chief executive officer and chief financial officer have concluded that FirstEnergy’s disclosure controls and procedures were effective as of the end Management’s Report on Internal Control over Financial Reporting See Management’s Report on Internal Control over Financial Reporting under "Financial Statements and Supplementary Data". Management is required to assess the effectiveness of FirstEnergy's internal control over financial reporting. Based on that assessment, management concluded that FirstEnergy's internal control over financial reporting was effective as of December 31, 2019. Changes in Internal Control over Financial Reporting During the quarter ended December 31, 2019, there were no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, FirstEnergy's internal control over financial reporting. 105 106 18. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED) CONTROLS AND PROCEDURES The following summarizes certain consolidated operating results by quarter for 2019 and 2018. Evaluation of Disclosure Controls and Procedures The management of FirstEnergy, with the participation of the chief executive officer and chief financial officer, has reviewed and evaluated the effectiveness of their registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, Rules 13a-15(e) and 15d-15(e), as of the end of the period covered by this report. Based on that evaluation, the chief executive officer and chief financial officer have concluded that FirstEnergy’s disclosure controls and procedures were effective as of the end of the period covered by this report. Management’s Report on Internal Control over Financial Reporting See Management’s Report on Internal Control over Financial Reporting under "Financial Statements and Supplementary Data". Management is required to assess the effectiveness of FirstEnergy's internal control over financial reporting. Based on that assessment, management concluded that FirstEnergy's internal control over financial reporting was effective as of December 31, 2019. Changes in Internal Control over Financial Reporting During the quarter ended December 31, 2019, there were no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, FirstEnergy's internal control over financial reporting. FirstEnergy CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions, except per share amounts) 2019 2018 Revenues Other operating expense Provision for depreciation Operating Income Pension and OPEB mark-to-market adjustment Income before income taxes Income taxes Income from continuing operations Discontinued operations (1) (Note 3) Net Income (Loss) Income allocated to preferred stockholders (2) Net income (loss) attributable to common stockholders Earnings (loss) per share of common stock-(3) Basic - Continuing Operations Basic - Discontinued Operations (Note 3) Basic - Net Income (Loss) Attributable to Common Stockholders Diluted - Continuing Operations Diluted - Discontinued Operations (Note 3) Diluted - Net Income (Loss) Attributable to Common Stockholders (1) Net of income taxes Dec. 31 Sep. 30 Jun. 30 Mar. 31 Dec. 31 Sep. 30 Jun. 30 Mar. 31 $ 2,673 $ 2,963 $ 2,516 $ 2,883 $ 2,710 $ 3,064 $ 2,625 $ 2,862 809 310 615 (674) (249) (68) (181) (111) 70 — (111) (0.33) 0.13 (0.20) (0.33) 0.13 758 304 681 — 496 107 389 2 391 — 391 0.72 0.01 0.73 0.72 — 606 309 585 — 422 81 341 (29) 312 4 779 297 629 — 448 93 355 (35) 320 5 0.63 0.66 (0.05) (0.07) 0.58 0.63 0.59 0.66 (144) 770 293 512 169 35 134 4 138 10 128 0.24 0.01 0.25 0.24 0.01 739 283 710 — 520 121 399 (857) (458) 54 684 283 700 — 409 101 308 (9) 299 165 0.68 0.30 (1.70) (0.02) (1.02) 0.68 0.28 0.30 940 277 580 — 414 233 181 1,188 1,369 156 0.05 2.50 2.55 0.05 2.49 308 315 (512) 134 1,213 (0.05) (0.07) (1.70) (0.02) (0.20) 0.72 0.58 0.59 0.25 (1.02) 0.28 2.54 (2) The sum of quarterly income allocated to preferred stockholders may not equal annual income allocated to preferred stockholders as quarter- to-date and year-to-date amounts are calculated independently. (3) The sum of quarterly earnings per share information may not equal annual earnings per share due to the issuance of shares and conversion of preferred shares throughout the year. See the FirstEnergy Consolidated Statements of Stockholders' Equity and Note 6, "Stock-Based Compensation Plans," for additional information. 105 106 Information About Our Executive Officers (as of February 10, 2020) Name C. E. Jones C. L. Walker G. D. Benz J. J. Lisowski R. P. Reffner S. E. Strah Age 64 54 60 38 69 56 S. L. Belcher 51 Positions Held During Past Five Years Dates President and Chief Executive Officer (A) (B) Chief Executive Officer (G) President (C) Senior Vice President and Chief Human Resources Officer (B) Vice President, Human Resources (B) Executive Director, Talent Management (B) Executive Director, Human Resources (B) Senior Vice President, Strategy (B) Vice President, Supply Chain (B) Vice President, Controller and Chief Accounting Officer (A) (B) Vice President and Controller (C) (E) Controller and Treasurer (G) Controller and Treasurer (F) Assistant Controller (E) Assistant Controller (B) (C) (D) (G) Assistant Controller (A) (F) Senior Vice President and General Counsel (A) (B) (C) (E) Vice President and General Counsel (E) Vice President and General Counsel (B) (C) Vice President and General Counsel (D) Vice President and General Counsel (G) Vice President and General Counsel (F) Senior Vice President and Chief Financial Officer (A) (B) (C) (E) President (D) President (E) Senior Vice President & President, FirstEnergy Utilities (B) President (C) Vice President, Distribution Support (B) Senior Vice President and President, FirstEnergy Utilities (B) President (C) (E) President and Chief Nuclear Officer (G) President, FirstEnergy Nuclear Operating Company (B) Senior Vice President and Chief Operating Officer (G) 2015-present 2015-2017 *-2015 2019-present 2018-2019 2016-2018 *-2016 2015-present *-2015 2018-present 2018-present 2017-2018 2016-2018 2016-2017 *-2017 *-2016 2018-present 2016-2018 2015-2018 2015-2017 *-2017 *-2016 2018-present 2017-2018 2016-2018 2015-2018 2015-2018 *-2015 2018-present 2018-present 2015-2018 2015-2017 *-2015 * Indicates position held at least since January 1, 2015 (A) Denotes position held at FE (B) Denotes position held at FESC (C) Denotes position held at the Ohio Companies, the Pennsylvania Companies, MP, PE, FET, TrAIL and ATSI (D) Denotes position held at AGC (E) Denotes position held at MAIT (F) Denotes position held at FES and FG, which filed a voluntary petition under Chapter 11 of the United States Bankruptcy Code in March 2018 (G) Denotes position held at FENOC, which filed a voluntary petition under Chapter 11 of the United States Bankruptcy Code in March 2018 107 SHAREHOLDER SERVICES TRANS FER AG ENT AND REG ISTRAR American Stock Transfer & Trust Company, LLC (AST) is the company’s Transfer Agent and Registrar. Registered shareholders wanting to transfer stock, or who need assistance or information, can send their stock certificate(s) or write to FirstEnergy Corp., c/o American Stock Transfer & Trust Company, LLC, P.O. Box 2016, New York, NY 10272-2016. Shareholders also can call toll-free at 1-800-736-3402, between 8 a.m. and 8 p.m. Eastern time, Monday through Friday. For Internet access to general shareholder and account information, visit the AST website at https://us.astfinancial.com/InvestOnline/Invest/AllPlan. ST OCK INVESTMENT PLAN Registered shareholders and employees of the company can participate in the FirstEnergy Corp. Stock Investment Plan. To learn more about the company’s Stock Investment Plan, visit AST’s website at https://us.astfinancial.com/InvestOnline/Invest/AllPlan, or contact AST toll-free at 1-800-736-3402. DIREC T DIVIDEND DEPO SIT Registered shareholders can have their dividend payments automatically deposited to checking, savings or credit union accounts at any financial institution that accepts electronic direct deposits. Using this free service ensures that payments will be available to you on the payment date, eliminating the possibility of mail delay or lost checks. Contact AST toll-free at 1-800-736-3402 to receive a Direct Dividend Deposit Authorization Agreement. ST OCK LISTING A ND TRADIN G The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol FE. FORM 1 0-K ANNUAL REPORT The Annual Report on Form 10-K, as filed with the Securities and Exchange Commission, including the financial statements and financial statement schedules, will be sent to you without charge upon written request to Ebony Yeboah-Amankwah, Vice President, Deputy General Counsel, Corporate Secretary and Chief Ethics Officer, FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308-1890. You also can view the Form 10-K by visiting the company’s website at www.firstenergycorp.com/investor. 76 South Main Street, Akron, Ohio 44308-1890 

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