FirstEnergy
Annual Report 2017

Plain-text annual report

A N N UA L R E PO RT 20 17 FINANCIAL HIGHLIGHTS K E Y A C C O M P L I S H M E N T S • Generated $3.8 billion in cash from operations • Maintained dividend of $1.44 per share • Attained top-quartile safety performance in our industry • Invested $1 billion to modernize our transmission system as part of our Energizing the Future initiative • Achieved six consecutive quarters of growth in the industrial sector of our distribution business F I N A N C I A L S A T A G L A N C E (in millions, except per share amounts) TOTAL REVENUES NET INCOME (LOSS) BASIC AND DILUTED EARNINGS (LOSS) per common share DIVIDENDS PAID per common share 2017 $14,017 $(1,724) $(3.88) $1.44 2016 $14,562 $(6,177) $(14.49) $1.44 2015 $15,026 $578 $1.37 $1.44 N E T C A S H F R O M O P E R A T I N G A C T I V I T I E S (in millions) 2017 2016 2015 $3,808 $3,383 $3,460 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 R E G U L A T E D T R A N S M I S S I O N A N D D I S T R I B U T I O N R E V E N U E S (in millions) 2017 2016 2015 $11,059 $10,773 $10,628 0 2,000 4,000 6,000 8,000 10,000 12,000 T R A N S M I S S I O N A N D D I S T R I B U T I O N R E L I A B I L I T Y I N D E X * 2017 2016 2015 2.40 2.78 2.80 0 0.5 1 1.5 2 2.5 3 * FirstEnergy’s index comprises two indices that are commonly used in the electric utility industry: Transmission Outage Frequency (TOF) and System Average Interruption Duration Index (SAIDI). Our index measures frequency and duration of service interruptions: the better the performance, the higher the score. A MESSAGE TO OUR SHAREHOLDERS In 2017, we made considerable progress in our efforts to transform FirstEnergy into a high-performing regulated utility company, dedicated to achieving sustainable, customer-focused growth. We always strive for fair, appropriate and timely recovery of investments in our electric system while ensuring affordable rates for customers. Toward that end, successful rate proceedings at eight of our electric distribution utilities in Ohio, Pennsylvania and New Jersey resulted in additional annual revenue of nearly $600 million for our company beginning in 2017, which will fund a wide range of system enhancements. We continue to improve the operating earnings of our transmission business as we implement major upgrades designed to help customers benefit from a more reliable, resilient and secure grid. We’ve increased funding for our Energizing the Future transmission investment program, which is expanding grid modernization and reliability projects into the eastern part of our service area. In addition, we’re creating efficiencies and lowering costs throughout our business. For example, we far exceeded the initial savings estimates related to our Cash Flow Improvement Project, a comprehensive effort launched by our employees in 2015 to reduce expenses and enhance revenue. Through this initiative and other cost-saving measures, we achieved $820 million in sustainable savings over the past three years. These efforts, combined with the aggressive steps we’re taking to move away from a commodity- exposed generation business, helped set the stage for a major announcement in January of this year: a $2.5 billion equity investment in your company from several prominent investors, including affiliates of Elliott Management Corporation, Bluescape, GIC and Zimmer Partners, LP. This investment benefits our customers, shareholders and employees by strengthening our balance sheet, reducing FirstEnergy holding company debt by $1.45 billion. Combined with a previous contribution of $500 million, it also provided $1.25 billion in funding to our pension plan in 2018. In addition, the investment accelerates our growth and infrastructure improvement plans for our transmission and distribution businesses. We plan to invest more than $10 billion in these operations through 2021, which supports a projected annual growth rate of 6 to 8 percent* for our regulated business over the three-year period. *Excludes the Ohio Distribution Modernization Rider and is offset by the corporate segment. Charles E. Jones President and Chief Executive Officer 6M CUSTOMERS IN THE MIDWEST AND MID-ATLANTIC REGIONS 65K SQUARE MILES OF SERVICE TERRITORY 277K MILES OF DISTRIBUTION LINES 1 MOVING AWAY FROM COMMODITY-EXPOSED GENERATION the plant to our Mon Power utility. In addition, although the Public Service Commission of West Virginia approved the sale, its conditions would have exposed Mon Power to significant commodity risk. This decision is in no way a reflection of the hard work and dedication of the 190 employees at the plant who ensure that customers benefit from the reliable power it generates around the clock. We continue to believe that federal and state energy policies should properly compensate baseload coal and nuclear generating plants for the many key benefits they offer, including clean, reliable power, thousands of well-paying jobs and considerable support to local communities. The equity transaction supports our transition to a fully regulated company, dedicated to providing superior service to customers. As part of this effort, we’ve created a restructuring working group to serve in an advisory role, sharpening our focus on exiting the competitive generation business in a timely manner. The group includes Jim Pearson, executive vice president, Finance; Leila Vespoli, executive vice president of Corporate Strategy, Regulatory Affairs and chief legal officer; and Gary Benz, senior vice president of Strategy; as well as two outside members. FirstEnergy Solutions’ (FES) Board of Directors will continue to make decisions about our competitive subsidiary, including any that are related to filing for bankruptcy protection for FES. Among other transition-related initiatives, in 2017, we sold 859 megawatts (MW) of competitive natural gas generation assets located in Pennsylvania and Virginia for an all-cash price of $388 million. The sale involved four gas-fired power stations owned by FirstEnergy subsidiary Allegheny Energy Supply Company, LLC (AES), which also sold its 50 percent interest in the Buchanan Generating Facility in March of this year. The sale by Allegheny Generating Company of a portion of its interest in Bath County Pumped-Storage Hydro is expected to close in the first half of this year. In addition, AES has agreed to settlement terms of $93 million involving a coal supply dispute. In February 2018, AES notified PJM that it will deactivate or sell the coal-fired, 1,300 MW Pleasants Power Station in Willow Island, W.Va., by January 2019. Previously, the Federal Energy Regulatory Commission (FERC) rejected a proposal to transfer 2 (Left) We’re supporting the growing energy needs of NatureFresh™ Farms in Delta, Ohio, as the commercial indoor agriculture and greenhouse facility expands its operations in our Toledo Edison service area. UNLOCKING THE VALUE OF OUR REGULATED BUSINESS We’re making smart investments in our regulated operating companies and transmission affiliates that are positioning your company for future growth. These include investments in new technologies that help us provide more reliable, responsive service to customers. For example, through our multibillion-dollar Energizing the Future initiative, we continue to upgrade and modernize our transmission system. From 2014 through 2017, we invested $4.4 billion on grid improvement projects, and we plan to invest an additional $4.0 billion to $4.8 billion from 2018 through 2021. As part of this initiative, we plan to implement nearly 1,200 smart grid projects from 2017 through 2020 designed to make our system more robust, secure and resistant to extreme weather events, as well as technologies that minimize the threat of physical and cyberattacks. Projects completed last year include construction of a new 16-mile transmission line in Monmouth County, N.J., that will benefit 180,000 customers, and a rebuilt 7.5-mile transmission line in western Pennsylvania that incorporates smart grid technologies aimed at reducing the frequency and duration of power outages for customers in Butler and Mercer counties. To support eastward expansion of the program, our Penelec and Met-Ed utilities transferred their transmission assets to our Mid-Atlantic Interstate Transmission subsidiary, known as MAIT. FERC accepted new transmission rates for MAIT, subject to refund, as well as Jersey Central Power & Light, which will continue to manage transmission projects within its service area. With MAIT in place, we invested $243 million in 2017 on transmission projects that will primarily benefit customers in our Penelec and Met-Ed service areas, and we’re planning to spend approximately $400 million in 2018. Looking beyond our grid investment plans through 2021, we also have identified $20 billion in additional projects across our 24,500-mile transmission system that have the potential to further increase reliability, upgrade the condition of equipment, enhance system performance and improve operational flexibility. To help our employees meet the challenges of this complex transmission network, we announced plans to build the Center for Advanced Energy Technology adjacent to our West Akron Campus. The facility will provide engineers and relay technicians with a hands-on training environment that will simulate real-world conditions on the transmission system. It also will be used for evaluating and testing equipment to ensure it complies with the latest industry standards, including those related to cybersecurity. On the distribution side of our business, we’re moving toward a future in which our utilities will manage a more dynamic, intelligent and secure network that will change the way energy is delivered to our customers. Toward that end, we’re investing in a wide range of technologies while evaluating new opportunities to modernize our distribution system and meet the future energy needs of customers. 3 To date, we’ve installed nearly 1.5 million smart meters in Pennsylvania as part of our efforts to deploy these devices for nearly all of our 2 million customers in the state by mid-2019. Last year, we began billing customers based on data received through automated readings. Today, most customers with a smart meter can access detailed information that can help them better understand and manage their energy use. Moving forward, these devices may help us better detect power outages and restore power more quickly and efficiently. We’re also exploring opportunities that will result from the growing adoption of plug-in electric vehicles, distributed generation resources such as rooftop solar and battery storage, and home energy management systems that enable customers to more actively manage their energy use and costs. In addition, we’re participating in PowerForward, an ambitious grid modernization initiative launched in 2017 by the Public Utilities Commission of Ohio (PUCO). This effort brings together industry experts to explore how technological and regulatory innovations can benefit customers. Also in Ohio, we filed a $450 million grid modernization plan with the PUCO that will provide immediate reliability benefits while preparing our system for future smart grid enhancements that make the most sense for our customers. We see great potential in new distribution automation technology, enabled by high-speed communications, that can help ensure quicker service restoration. For example, we installed prototype equipment in a portion of our Maryland service area that helps prevent service interruptions by proactively evaluating grid conditions and quickly taking corrective actions, even before outages occur. We also continue to offer new value-added products and services that can help customers save energy while living smarter and healthier lifestyles. In 2017, we launched Smartmart™ by FirstEnergy, our new e-commerce website (www.smart-mart.com). This user-friendly online marketplace provides an expanded range of innovative tools, technologies and services designed to provide customers with greater comfort, convenience, security and productivity – from surge protection plans to energy- saving smart thermostats. Commercial and industrial customers can benefit from our Electric Advantage program, which enables them to enhance their productivity and competitiveness and meet sustainability goals using efficient electric products, such as electric forklifts and infrared heating systems for drying products and curing coatings. As we move forward with these and other initiatives, we remain optimistic about several positive trends in our distribution business, including better-than-expected residential sales and six consecutive quarters of load growth in the industrial sector. Growth in the latter segment is largely driven by the shale gas and steel industries. 4 (Above) Employees at our Harrison Power Station in Haywood, W.Va., reached a significant milestone in 2017 when they surpassed 1 million hours worked without a lost-time injury. SUSTAINING OUR COMMUNITIES We’re committed to protecting the environment and making our communities stronger. I’m proud of our employees’ ongoing efforts to improve our environmental performance – from remediation programs that support redevelopment at our former facilities, to responsible vegetation management and reforestation practices. Through our partnership with the Electric Power Research Institute, we’re helping fuel the next generation of electric vehicles while minimizing the cost and impact on the reliability of our nation’s electric system. We also participate in the CDP (formerly the Carbon Disclosure Project), which enables companies, cities, states and regions to measure and manage the environmental impact of their operations. Our own CDP scoring reflects continued improvement in our efforts to wisely use water resources and achieve our companywide goal of reducing carbon-dioxide emissions by at least 90 percent below 2005 levels by 2045. In addition, the resources of FirstEnergy and the FirstEnergy Foundation – combined with the energy and enthusiasm of our employees – benefit hundreds of organizations and thousands of people each year. In 2017, our foundation granted $6.1 million to support over 1,000 community-based organizations, and our employees lent their time and talents to assist hundreds of charitable groups. I’m also proud of the way our employees responded to the large-scale power outages caused by Hurricane Irma. More than 630 employees traveled to Florida in September to assist with the service restoration efforts. This crisis served as a stark reminder of the importance of a reliable and resilient electric system for customers and our nation’s economy. 5 3 PROMOTING A SAFE, DIVERSE AND HIGHLY SKILLED WORKFORCE We’re addressing a significant issue facing companies throughout the nation – the need to replace experienced employees who are reaching retirement age. With about 30 percent of our employees currently eligible to retire, we’re filling hundreds of positions companywide through promotions, internal job postings and recruitment of highly qualified people. We continue to train the next generation of line, substation and power plant workers for FirstEnergy’s utilities through our Power Systems Institute (PSI) and Power Plant Technology (PPT) workforce development programs, which combine classroom learning at colleges and universities across our service area with hands-on skills training at company facilities. We hired 273 graduates of the programs in 2017, bringing the total to more than 1,600 graduates who have joined our company through PSI and PPT. Our top priority is ensuring that all our working men and women arrive home safely at the end of every workday, and our OSHA-recordable injury rate of 0.82 places us in the top quartile for safety performance in our industry. However, two fatalities involving employees in 2017 remind us that we need to do more to bring our safety performance in line with our expectations. We have worked hard over the years to strengthen our safety culture and build personal accountability for safety at every level of our organization. I can assure you we remain committed to fully understanding the circumstances around these tragic events and will continue to work together to emerge as a stronger, safer organization. We also remain committed to sustaining a work environment that values diversity and inclusion. Our success in this vital area will help us achieve higher levels of performance, better serve our customers, and attract and recruit the best candidates who see value in our organization and want to be part of our team. For these and other reasons, we’re dedicated to building a workforce that more accurately reflects the demographics of the communities we serve. 6 For example, we have formed an Executive Diversity & Inclusion Council and implemented awareness programs to help ensure our managers and supervisors are making appropriate, unbiased decisions in their everyday work activities. In 2017, all employees were trained to better understand the strategic value and importance of an inclusive work environment. As part of our 2018 incentive compensation targets, we’ve introduced a Diversity & Inclusion goal that applies to every FirstEnergy leader – from the manager level to me. This goal will assess our progress toward increasing diversity in our professional hires and succession plans and demonstrating improvement in key areas identified in an employee survey. We will continue to dedicate ourselves to building a culture that values diversity by fostering teamwork, respect, candor, opportunity and inclusiveness. POSITIONED FOR FUTURE SUCCESS I want to thank employees for their efforts to build a better future for our customers and company, as well as our shareholders for their continued support of FirstEnergy. I also want to express my deep appreciation to George Smart for his leadership, expertise and counsel during a 14-year tenure as non-executive chairman of FirstEnergy’s Board of Directors. I look forward to working closely with George’s very capable and worthy successor, Don Misheff. I believe the positive steps outlined in this report have positioned FirstEnergy for stable, predictable growth in the years ahead as we bring greater value to our customers, shareholders and employees. Charles E. Jones President and Chief Executive Officer March 9, 2018 PA MD 9 NJ OH WV VA Generation Stations Coal Gas/Oil Hydro Nuclear Ohio Ohio Edison 1 B ay S hore Plant 2 Bruce Mans field Plant 3 F ort Martin P ower S tation 4 Harris on P ower S tation 5 P leas ants P ower S tation 6 W.H. S ammis Plant The Illuminating Company FIRSTENERGY CORPORATE PROFILE Toledo Edison 7 Buchanan Generating Facility 8 West Lorain Plant 9 Forked River Pennsylvania Met-Ed Penelec Penn Power Headquartered in Akron, Ohio, FirstEnergy is a forward-thinking electric utility powered by a diverse team of employees committed to making customers’ lives brighter, the environment better and communities stronger. Our subsidiaries are involved in the transmission, distribution West Virginia/Maryland and generation of electricity. West Penn Power Mon Power Potomac Edison New Jersey Jersey Central Power & Light Our workforce of more than 15,600 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 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. 12-19-2017 FirstEnergy subsidiaries own or control generating capacity from nuclear, coal, natural gas, hydro, wind and solar facilities. 10 B ath C ounty P umped-S torage Hydro 11 Y ards C reek Pumped-Storage Hydro OHIO 12 Beaver Valley Power Station noitatS rewoP raelcuN esseB-sivaD 31 tnalP rewoP raelcuN yrreP 41 GENERATING STATIONS Ohio Edison Win d1 A Blue Creek, OH B Pennsylvania The Illuminating Company - Meyersdale - Casselman - Allegheny Ridge I - Allegheny Ridge II - Highland C High Trail, I L 2 Toledo Edison PENNSYLVANIA Met-Ed Penelec Sola r1 Maryland Solar 1 Purchase Power Contracts 2 Not shown on map Penn Power West Penn Power WEST VIRGINIA/ MARYLAND Mon Power Potomac Edison NEW JERSEY Jersey Central Power & Light Coal Gas/Oil Hydro Nuclear Wind Solar 7 FIRSTENERGY BOARD OF DIRECTORS BACK ROW (LEFT TO RIGHT) Christopher D. Pappas President, Chief Executive Officer and Director of Trinseo S.A. (plastics, latex and rubber producer) Thomas N. Mitchell Retired, formerly President, Chief Executive Officer and Director of Ontario Power Generation Inc. Sandra Pianalto Retired, formerly President and Chief Executive Officer of the Federal Reserve Bank of Cleveland Steven J. Demetriou Chairman, Chief Executive Officer and Director of Jacobs Engineering Group, Inc. (provider of technical professional and construction services) Charles E. Jones President and Chief Executive Officer of FirstEnergy Corp. Donald T. Misheff Retired, formerly Managing Partner of the Northeast Ohio offices of Ernst & Young LLP Paul T. Addison Retired, formerly Managing Director in the Utilities Department of Salomon Smith Barney (Citigroup) James F. O’Neil III Partner, Western Commerce Group (advisory and investment firm) Julia L. Johnson President of NetCommunications, LLC (regulatory and public affairs firm) Michael J. Anderson Chairman of the Board of The Andersons, Inc. (diversified agribusiness) William T. Cottle Retired, formerly Chairman of the Board, President and Chief Executive Officer of STP Nuclear Operating Company FRONT ROW (LEFT TO RIGHT) Luis A. Reyes Retired, formerly Regional Administrator of the U.S. Nuclear Regulatory Commission George M. Smart Non-executive Chairman of the FirstEnergy Corp. Board of Directors. Retired, formerly President of Sonoco-Phoenix, Inc. Dr. Jerry Sue Thornton Chief Executive Officer of Dream Catcher Educational Consulting (higher education coaching and professional development). Retired President of Cuyahoga Community College DEAR SHAREHOLDERS: During the past year, FirstEnergy’s management has continued to implement a strategy to transition to a fully regulated utility. As part of this effort, the company made significant investments in its grid modernization program, strengthened its financial position, reduced expenses and divested some competitive generation units. Your Board maintained the annual dividend of $1.44 per share in 2017 and will continue to review the dividend on a quarterly basis as FirstEnergy captures opportunities for customer-centered growth in its regulated transmission and distribution businesses. On a personal note, I would like to thank William T. Cottle, who is retiring from the Board as of the 2018 Annual Meeting of Shareholders. The Board is truly grateful for the leadership and guidance Bill provided during his 15 years of distinguished service to FirstEnergy and its shareholders. I’d also like to welcome Sandra Pianalto, who was elected to the Board in February 2018. Ms. Pianalto served for more than a decade as president and chief executive officer of the Federal Reserve Bank of Cleveland. Before joining the Bank, Sandy was an economist at the Federal Reserve Board of Governors and served on the staff of the Budget Committee of the U.S. House of Representatives. Her strong leadership skills and unparalleled expertise in finance and economics are a great asset to your Board. I conclude my role as non-executive chairman of FirstEnergy’s Board of Directors at the Annual Meeting of Shareholders on May 15. It’s been a great privilege to serve on the Board of FirstEnergy and its predecessor, Ohio Edison, for 30 years. I’m proud of your Board’s many accomplishments during my 14-year tenure as chairman and its commitment to maintaining high standards for practices and policies that help ensure good corporate governance. As your company continues its transformation into a high-performance, fully regulated utility company, I’m confident it will succeed under the leadership of my successor, Donald T. Misheff. Don joined FirstEnergy’s Board in 2012 and brings more than 30 years of financial and corporate governance experience, business development expertise and a comprehensive knowledge of our industry to the Board. Your Board appreciates your ongoing trust and confidence as it works with your management team to capitalize on the outstanding opportunities that lie ahead. Sincerely, George M. Smart Chairman of the Board 8 FIRSTENERGY EXECUTIVE OFFICERS* Charles E. Jones President and Chief Executive Officer Leila L. Vespoli Executive Vice President, Corporate Strategy, Regulatory Affairs and Chief Legal Officer James F. Pearson Executive Vice President, Finance 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 Charles D. Lasky Senior Vice President, Human Resources and Chief Human Resource Officer Steven E. Strah Senior Vice President and Chief Financial Officer Jason J. Lisowski Vice President, Controller and Chief Accounting Officer Robert P. Reffner Vice President and General Counsel Ebony L. Yeboah-Amankwah Vice President, Corporate Secretary and Chief Ethics Officer * More detailed information on the principal occupation or employment of each of our executive officers, as of February 20, and the principal business of any organization by which FirstEnergy executive officers are employed may be found on page 156 of this report. A N N UA L R E PO RT 20 17 CONTENTS 1 ............. Glossary of Terms 6............. Selected Financial Data 8............. Management’s Discussion and Analysis 67........... Management Report 68 .......... Report of Independent Registered Public Accounting Firm 70........... Consolidated Statements of Income (Loss) 71 ........... Consolidated Statements of Comprehensive Income (Loss) 72........... Consolidated Balance Sheets 73........... Consolidated Statements of Common Stockholders’ Equity 74........... Consolidated Statements of Cash Flows 75........... Notes to the Consolidated Financial Statements 156 ......... Executive Officers as of February 20, 2018 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 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, a generation subsidiary of AE Supply and equity method investee of MP 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 BU Energy Buchanan Energy Company of Virginia, LLC, a subsidiary of AE Supply, and 50% owner in a joint venture that owns the Buchanan Generating Facility Buchanan Generation Buchanan Generation, LLC, a joint venture between AE Supply and CNX Gas Corporation CEI CES FE FENOC FES FESC FET FEV FG FirstEnergy Global Holding Global Rail GPU Green Valley JCP&L MAIT ME MP NG OE The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary Competitive Energy Services, a reportable operating segment of FirstEnergy FirstEnergy Corp., a public utility holding company FirstEnergy Nuclear Operating Company, a subsidiary of FE, which operates nuclear generating facilities FirstEnergy Solutions Corp., together with its consolidated subsidiaries, 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 facilities 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 Group, LLC, a subsidiary of Global Holding that owns coal transportation operations near Roundup, Montana GPU, Inc., former parent of JCP&L, ME and PN, that merged with FE on November 7, 2001 Green Valley Hydro, LLC, which owned hydroelectric generating stations 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 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 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 Utilities WP 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 OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP West Penn Power Company, a Pennsylvania electric utility operating subsidiary The following abbreviations and acronyms are used to identify frequently used terms in this report: AAA ADIT American Arbitration Association Accumulated Deferred Income Taxes 1 GLOSSARY OF TERMS, Continued AEP AFS AFUDC ALJ AMT AOCI ARO ASU American Electric Power Company, Inc. Available-for-sale Allowance for Funds Used During Construction Administrative Law Judge Alternative Minimum Tax Accumulated Other Comprehensive Income Asset Retirement Obligation Accounting Standards Update Bath County Bath County Pumped Storage Hydro-Power Station BGS bps BNSF BRA CAA CBA CCR Basic Generation Service Basis points BNSF Railway Company PJM RPM Base Residual Auction Clean Air Act Collective Bargaining Agreement Coal Combustion Residuals CERCLA Comprehensive Environmental Response, Compensation, and Liability Act of 1980 CFL CFR CFTC CO2 CPP CSAPR CSX CTA CWA Compact Fluorescent Light Code of Federal Regulations Commodity Futures Trading Commission Carbon Dioxide EPA's Clean Power Plan Cross-State Air Pollution Rule CSX Transportation, Inc. Consolidated Tax Adjustment Clean Water Act D.C. Circuit DCPD United States Court of Appeals for the District of Columbia Circuit Deferred Compensation Plan for Outside Directors DCR DMR DOE DPM DR DSIC DSP DTA EDC EDCP EE&C EGS EGU ELPC Delivery Capital Recovery Distribution Modernization Rider United States Department of Energy Distribution Platform Modernization Demand Response Distribution System Improvement Charge Default Service Plan Deferred Tax Asset Electric Distribution Company Executive Deferred Compensation Plan Energy Efficiency and Conservation Electric Generation Supplier Electric Generation Units Environmental Law & Policy Center EmPOWER Maryland EmPOWER Maryland Energy Efficiency Act ENEC EPA EPRI ERO ESOP ESP ESP IV ESP IV PPA Facebook® Expanded Net Energy Cost United States Environmental Protection Agency Electric Power Research Institute Electric Reliability Organization Employee Stock Ownership Plan Electric Security Plan Electric Security Plan IV Unit Power Agreement entered into on April 1, 2016, by and between the Ohio Companies and FES Facebook is a registered trademark of Facebook, Inc. 2 GLOSSARY OF TERMS, Continued FASB FERC Fitch FMB FPA FTR GAAP GHG HCl IBEW ICE ICP 2007 ICP 2015 IIP IRP IRS ISO kV kW KWH LBR LED LOC LSE Financial Accounting Standards Board Federal Energy Regulatory Commission Fitch Ratings First Mortgage Bond Federal Power Act Financial Transmission Right Accounting Principles Generally Accepted in the United States of America Greenhouse Gases Hydrochloric Acid International Brotherhood of Electrical Workers Intercontinental Exchange, Inc. FirstEnergy Corp. 2007 Incentive Plan FirstEnergy Corp. 2015 Incentive Compensation Plan Investment Infrastructure Program Integrated Resource Plan Internal Revenue Service Independent System Operator Kilovolt Kilowatt Kilowatt-hour Little Blue Run Light Emitting Diode Letter of Credit Load Serving Entity LS Power LS Power Equity Partners, LP LTIIPs MATS MDPSC MISO MLP mmBTU Moody’s MOPR MVP MW MWH NAAQS NDT NEIL NERC NJAPA NJBPU NOL NOPR NOV NOx NPDES NRC NS NSR NUG Long-Term Infrastructure Improvement Plans Mercury and Air Toxics Standards Maryland Public Service Commission Midcontinent Independent System Operator, Inc. Master Limited Partnership One Million British Thermal Units Moody’s Investors Service, Inc. Minimum Offer Price Rule Multi-Value Project Megawatt Megawatt-hour National Ambient Air Quality Standards Nuclear Decommissioning Trust Nuclear Electric Insurance Limited North American Electric Reliability Corporation New Jersey Administrative Procedure Act New Jersey Board of Public Utilities Net Operating Loss Notice of Proposed Rulemaking Notice of Violation Nitrogen Oxide National Pollutant Discharge Elimination System Nuclear Regulatory Commission Norfolk Southern Corporation New Source Review Non-Utility Generation NYPSC New York State Public Service Commission 3 GLOSSARY OF TERMS, Continued OCA OCC OPEB OPEIU ORC OTC OTTI OVEC PA DEP PCB PCRB PJM Office of Consumer Advocate Ohio Consumers' Counsel Other Post-Employment Benefits Office and Professional Employees International Union Ohio Revised Code Over The Counter Other-Than-Temporary Impairments Ohio Valley Electric Corporation Pennsylvania Department of Environmental Protection Polychlorinated Biphenyl Pollution Control Revenue Bond PJM Interconnection, L.L.C. PJM Region PJM Tariff The aggregate of the zones within PJM PJM Open Access Transmission Tariff PM POLR POR PPA PPB PPUC PSA PSD PUCO PURPA R&D RCRA REC Particulate Matter Provider of Last Resort Purchase of Receivables Purchase Power Agreement Parts per Billion Pennsylvania Public Utility Commission Power Supply Agreement Prevention of Significant Deterioration Public Utilities Commission of Ohio Public Utility Regulatory Policies Act of 1978 Research and Development Resource Conservation and Recovery Act Renewable Energy Credit Regulation FD Regulation Fair Disclosure promulgated by the SEC REIT RFC RFP RGGI ROE RPM RRS RSS RTEP RTO RWG S&P SB310 SBC SEC Real Estate Investment Trust ReliabilityFirst Corporation Request for Proposal Regional Greenhouse Gas Initiative Return on Equity Reliability Pricing Model Retail Rate Stability Rich Site Summary Regional Transmission Expansion Plan Regional Transmission Organization Restructuring Working Group Standard & Poor’s Ratings Service Substitute Senate Bill No. 310 Societal Benefits Charge United States Securities and Exchange Commission Seventh Circuit United States Court of Appeals for the Seventh Circuit SIP Sixth Circuit State Implementation Plan(s) Under the Clean Air Act United States Court of Appeals for the Sixth Circuit SO2 SOS SPE SRC SREC SSA Sulfur Dioxide Standard Offer Service Special Purpose Entity Storm Recovery Charge Solar Renewable Energy Credit Social Security Administration 4 GLOSSARY OF TERMS, Continued SSO Tax Act TDS TMI-2 TO Twitter® UWUA VEPCO VIE VMP VMS VSCC WVDEP WVPSC Standard Service Offer Tax Cuts and Jobs Act adopted December 22, 2017 Total Dissolved Solid Three Mile Island Unit 2 Transmission Owner Twitter is a registered trademark of Twitter, Inc. Utility Workers Union of America Virginia Electric and Power Company Variable Interest Entity Vegetation Management Plan Vegetation Management Surcharge Virginia State Corporation Commission West Virginia Department of Environmental Protection Public Service Commission of West Virginia 5 SELECTED FINANCIAL DATA FirstEnergy For the Years Ended December 31, 2017 2016 2015 2014 2013 Revenues Income (Loss) From Continuing Operations Earnings (Loss) Available to FirstEnergy Corp. Earnings (Loss) per Share of Common Stock: Basic - Continuing Operations Basic - Discontinued Operations Basic - Earnings (Loss) Available to FirstEnergy Corp. Diluted - Continuing Operations Diluted - Discontinued Operations Diluted - Earnings (Loss) Available to FirstEnergy Corp. Weighted Average Shares Outstanding: Basic Diluted Dividends Declared per Share of Common Stock Total Assets Capitalization as of December 31: Total Equity Long-Term Debt and Other Long-Term Obligations Total Capitalization PRICE RANGE OF COMMON STOCK (In millions, except per share amounts) 14,017 $ 14,562 $ 15,026 (1,724) $ (6,177) $ (1,724) $ (6,177) $ 578 578 $ $ $ (3.88) $ (14.49) $ 1.37 $ — — — (3.88) $ (14.49) $ 1.37 $ (3.88) $ (14.49) $ 1.37 $ — — — (3.88) $ (14.49) $ 1.37 $ 15,049 213 299 0.51 0.20 0.71 0.51 0.20 0.71 444 444 1.44 42,257 $ $ 426 426 1.44 43,148 $ $ 422 424 1.44 52,094 $ $ 420 421 1.44 51,552 $ $ $ $ $ $ $ $ $ 14,892 375 392 0.90 0.04 0.94 0.90 0.04 0.94 418 419 1.65 49,980 3,925 $ 6,241 $ 12,422 $ 12,422 $ 12,695 21,115 18,192 19,099 19,080 15,753 25,040 $ 24,433 $ 31,521 $ 31,502 $ 28,448 $ $ $ $ $ $ $ $ $ $ $ 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. 2017 2016 High Low High Low First Quarter Second Quarter Third Quarter Fourth Quarter Yearly $ $ $ $ $ 32.54 31.94 33.08 35.22 35.22 $ $ $ $ $ 29.51 27.93 28.93 30.18 27.93 $ $ $ $ $ 36.54 36.32 36.60 34.83 36.60 $ $ $ $ $ 30.62 31.37 32.12 29.33 29.33 Closing prices are from http://finance.yahoo.com. 6 SHAREHOLDER RETURN The following graph shows the total cumulative return from a $100 investment on December 31, 2012 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 79,916 and 79,454 holders of 445,334,111 and 475,589,829 shares of FE’s common stock as of December 31, 2017 and January 31, 2018, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 12, "Capitalization," of the Combined Notes to Consolidated Financial Statements. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 7 FIRSTENERGY CORP. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Forward-Looking Statements: This Annual Report includes forward-looking statements based on information currently available to management. 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. These statements 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: • • The ability to experience growth in the Regulated Distribution and Regulated Transmission segments and the effectiveness of our strategy to transition to a fully regulated business profile. The accomplishment of our regulatory and operational goals in connection with our transmission and distribution investment plans, including, but not limited to, our planned transition to forward-looking formula rates. • • • • • Changes in assumptions regarding economic conditions within our territories, assessment of the reliability of our transmission system, or the availability of capital or other resources supporting identified transmission investment opportunities. The ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, the ability to continue to reduce costs and to successfully execute our financial plans designed to improve our credit metrics and strengthen our balance sheet. Success of legislative and regulatory solutions for generation assets that recognize their environmental or energy security benefits. The risks and uncertainties associated with the lack of viable alternative strategies regarding the CES segment, thereby causing FES to restructure its substantial debt and other financial obligations with its creditors or seek protection under U.S. bankruptcy laws (which filing would include FENOC) and the losses, liabilities and claims arising from such bankruptcy proceeding, including any obligations at FirstEnergy. The risks and uncertainties at the CES segment, including FES, its subsidiaries, and FENOC, related to wholesale energy and capacity markets, and the viability and/or success of strategic business alternatives, such as pending and potential CES generating unit asset sales or the potential need to deactivate additional generating units, which could result in further substantial write-downs and impairments of assets. The substantial uncertainty as to FES’ ability to continue as a going concern and substantial risk that it may be necessary for FES and FENOC to seek protection under U.S. bankruptcy laws. The risks and uncertainties associated with litigation, arbitration, mediation and like proceedings, including, but not limited to, any such proceedings related to vendor commitments, such as long-term fuel and transportation agreements. The uncertainties associated with the deactivation of older regulated and competitive units, including the impact on vendor commitments, such as long-term fuel and transportation agreements, and as it relates to the reliability of the transmission grid, the timing thereof. The impact of other future changes to the operational status or availability of our generating units and any capacity performance charges associated with unit unavailability. • • • • • Changing energy, capacity and commodity market prices including, but not limited to, coal, natural gas and oil prices, and their availability and impact on margins. • Costs being higher than anticipated and the success of our policies to control costs and to mitigate low energy, capacity and market prices. • Replacement power costs being higher than anticipated or not fully hedged. • Our ability to improve electric commodity margins and the impact of, among other factors, the increased cost of fuel and • fuel transportation on such margins. The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with any litigation, including NSR litigation, or potential regulatory initiatives or rulemakings (including that such initiatives or rulemakings could result in our decision to deactivate or idle certain generating units). • Changes in customers' demand for power, including, but not limited to, changes resulting from the implementation of state and federal energy efficiency and peak demand reduction mandates. • Economic or weather conditions affecting future sales, margins and operations such as a polar vortex or other significant weather events, and all associated regulatory events or actions. • Changes in national and regional economic conditions affecting us, our subsidiaries and/or our major industrial and • • commercial customers, and other counterparties with which we do business, including fuel suppliers. The impact of labor disruptions by our unionized workforce. The risks associated with cyber-attacks and other disruptions to our information technology system that may compromise our generation, transmission and/or distribution services and data security breaches of sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers, suppliers, business partners and other individuals in our data centers and on our networks. 8 • • • • The impact of the regulatory process and resulting outcomes on the matters at the federal level and in the various states in which we do business including, but not limited to, matters related to rates. The impact of the federal regulatory process on FERC-regulated entities and transactions, in particular FERC regulation of wholesale energy and capacity markets, including PJM markets and FERC-jurisdictional wholesale transactions; FERC regulation of cost-of-service rates; and FERC’s compliance and enforcement activity, including compliance and enforcement activity related to NERC’s mandatory reliability standards. The uncertainties of various cost recovery and cost allocation issues resulting from ATSI's realignment into PJM. The ability to comply with applicable state and federal reliability standards and energy efficiency and peak demand reduction mandates. • Other legislative and regulatory changes, including the federal administration's required review and potential revision of environmental requirements, including, but not limited to, the effects of the EPA's CPP, CCR, CSAPR and MATS programs, including our estimated costs of compliance, CWA waste water effluent limitations for power plants, and CWA 316(b) water intake regulation. • Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to, • • • the revocation or non-renewal of necessary licenses, approvals or operating permits by the NRC). Issues arising from the indications of cracking in the shield building at Davis-Besse. • • Changing market conditions that could affect the measurement of certain liabilities and the value of assets held in our NDTs, pension trusts and other trust funds, and cause us and/or our subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated. The impact of changes to significant accounting policies. The impact of any changes in tax laws or regulations, including the Tax Act, 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 and our subsidiaries. Further actions that may be taken by credit rating agencies that could negatively affect us and/or our subsidiaries’ access to financing, increase the costs thereof, increase requirements to post additional collateral to support, or accelerate payments under outstanding commodity positions, LOCs and other financial guarantees, and the impact of these events on the financial condition and liquidity of FirstEnergy and/or its subsidiaries, specifically FES and its subsidiaries. Issues concerning the stability of domestic and foreign financial institutions and counterparties with which we do business. The risks and other factors discussed from time to time in our SEC filings, and other similar factors. • • • Dividends declared from time to time on FE's common stock and thereby on FE's preferred stock, during any period may in the aggregate vary from prior periods due to circumstances considered by FE's 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, 2017, filed with the SEC on February 20, 2018, (b) this Management's Discussion and Analysis of Financial Condition and Results of Operations, and (c) other factors discussed herein and in other filings with the SEC by the registrants. These risks, unless otherwise indicated, are presented on a consolidated basis for FirstEnergy; if and to the extent a deconsolidation occurs with respect to certain FirstEnergy companies, the risks described herein may materially change. 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 FirstEnergy's business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. Each of the registrants expressly disclaims any obligation to update or revise, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise. 9 FIRSTENERGY’S BUSINESS FirstEnergy and its subsidiaries are principally involved in the generation, transmission and distribution of electricity. Its reportable segments are as follows: Regulated Distribution, Regulated Transmission, and CES. 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 commodity costs of securing electric generation and the deferral and amortization of certain fuel costs. The service areas of, and customers served by, FirstEnergy's regulated distribution utilities are summarized below (in thousands): Company Area Served Customers Served (1) OE Penn CEI TE JCP&L ME PN WP MP PE 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) As of December 31, 2017 1,049 166 751 311 1,127 569 587 726 392 409 6,087 The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, MAIT (effective January 31, 2017) and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP). The segment's revenues are primarily derived from forward-looking rates at ATSI and TrAIL, as well as stated transmission rates at certain of FirstEnergy's utilities. As discussed in "Outlook - FERC Matters" below, MAIT and JCP&L submitted applications to FERC requesting authorization to implement forward-looking formula transmission rates. In March 2017, FERC approved JCP&L's and MAIT's forward-looking formula rates, subject to refund, with effective dates of June 1, 2017, and July 1, 2017, respectively. Additionally, MAIT and JCP&L filed settlement agreements with FERC on October 13, 2017 and December 21, 2017, respectively, both pending final orders by FERC. Both the forward-looking and stated rates recover costs and provide a return on transmission capital investment. Under forward-looking rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which are 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. The CES segment, through FES and AE Supply, primarily supplies electricity to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. As of January 31, 2018, this business segment controlled 12,303 MWs of electric generating capacity, including, as further discussed below, 756 MWs of generating capacity which remain subject to an asset purchase agreement with a subsidiary of LS Power that is expected to close in the first half of 2018. The CES segment’s operating results are primarily derived from electric generation sales less the related costs of electricity generation, including fuel, purchased power and net transmission (including congestion) and ancillary costs and capacity costs charged by PJM to deliver energy to the segment’s customers, as well as other operating and maintenance costs, including costs incurred by FENOC. Interest expense on stand-alone holding company debt, corporate income taxes and other businesses that do not constitute an operating segment are categorized as Corporate/Other for reportable business segment purposes. Additionally, reconciling adjustments for the elimination of inter-segment transactions are included in Corporate/Other. As of December 31, 2017, Corporate/ Other had $6.8 billion of stand-alone holding company long-term debt, of which $1.45 billion was subject to variable-interest rates, and $300 million was borrowed by FE under its revolving credit facility. On January 22, 2018, FE repaid its $1.45 billion of outstanding variable-interest rate debt using the proceeds from the $2.5 billion equity investment. 10 EXECUTIVE SUMMARY FirstEnergy’s strategy is to be a fully regulated utility company, focusing on stable and predictable earnings and cash flow from its regulated business units - Regulated Distribution and Regulated Transmission - which focus on delivering enhanced customer service and reliability. Together, the Regulated Distribution and Transmission businesses are expected to provide stable, predictable earnings and cash flows that support FE’s dividend. 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. Since 2015, Regulated Distribution has experienced significant growth through investments that have improved reliability and added operating flexibility to the distribution infrastructure and the implementation of new rates at eight of the ten Utilities in 2017, which provide benefits to the customers and communities those Utilities serve. Based on its current capital plan, which includes $5.7 to $6.7 billion in forecasted capital investments through 2021, Regulated Distribution’s rate base growth rate is expected to be approximately 5% through 2021. 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 in operations, the Regulated Transmission business is the centerpiece of FirstEnergy’s regulated investment strategy with approximately 80% of its capital investments recovered under forward-looking formula rates, including ATSI, TrAIL, and MAIT, which recently filed a proposed settlement with FERC regarding its formula rate, as well as the transmission system at JCP&L, which recently filed a proposed settlement with FERC to maintain a stated-rate through 2020. Both the MAIT and JCP&L settlement agreements are pending before FERC. Regulated Transmission has also experienced significant growth as part of its Energizing the Future transmission plan with $4.4 billion in capital investment from 2014 through 2017 and plans to invest $4.0 to $4.8 billion in capital from 2018 to 2021, which are expected to result in Regulated Transmission rate base growth of approximately 11% through 2021. FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of approximately $20 billion beyond those identified through 2021, 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. The Company continues to focus on its regulated growth strategy and in November 2016, FirstEnergy announced a strategic review to exit its commodity-exposed generation at CES, which is primarily comprised of the operations of FES and AE Supply. In connection with this strategic review, AE Supply and AGC entered into an asset purchase agreement with a subsidiary of LS Power, 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) for an all-cash purchase price of $825 million, subject to adjustments and through multiple, independent closings. On December 13, 2017, AE Supply completed the sale of the natural gas generating plants with net proceeds, subject to post-closing adjustments, of approximately $388 million. The sale of AE Supply’s interests in the Bath County hydroelectric power station and the Buchanan Generating facility is expected to generate net proceeds of $375 million and is anticipated to close in the first half of 2018, subject in each case to various customary and other closing conditions, including, without limitation, receipt of regulatory approvals. Additionally, on March 6, 2017, AE Supply and MP entered into an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station (1,300 MWs) for approximately $195 million, resulting from an RFP issued by MP to address its generation shortfall. On January 12, 2018, FERC issued an order denying authorization for the transaction, holding that MP and AE Supply did not demonstrate the sale was consistent with the public interest and the transaction did not fall within the safe harbors for meeting FERC’s affiliate cross-subsidization analysis. On January 26, 2018, the WVPSC approved the transfer of the Pleasants Power Station, subject to certain conditions as further described in "Outlook - West Virginia," below, which included MP assuming significant commodity risk. Based on the FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement and on February 16, 2018, AE Supply announced its intent to exit operations of the Pleasants Power Station by January 1, 2019, through either sale or deactivation, which resulted in a pre-tax impairment charge of $120 million. With the sale of the gas plants completed, upon the consummation of the sale of AGC's interest in the Bath County hydroelectric power station or the sale or deactivation of the Pleasants Power Station, AE Supply is obligated under the amended and restated purchase agreement and AE Supply’s applicable debt agreements, to satisfy and discharge approximately $305 million of currently outstanding senior notes as well as its $142 million of pollution control notes and AGC’s $100 million senior notes, which are expected to require the payment of “make-whole” premiums currently estimated to be approximately $95 million based on current interest rates. For additional information see "Outlook" below. The strategic options to exit the remaining portion of the CES portfolio, which is primarily at FES, are limited. The credit quality of FES, including its unsecured debt rating of Ca at Moody’s, C at S&P, and C at Fitch and the negative outlook from Moody’s and S&P, has challenged its ability to consummate asset sales. Furthermore, the inability to obtain legislative support under the Department of Energy’s recent NOPR, which was rejected by FERC, limits FES’ strategic options to plant deactivations, restructuring its debt and other financial obligations with its creditors, and/or to seek protection under U.S. bankruptcy laws. 11 As part of the strategic review, FES evaluated its options with respect to its nuclear power plants. Factors considered as part of this review included current and forecasted market conditions, such as wholesale power and capacity prices, legislative and regulatory solutions that recognize their environmental and energy security benefits, and many other factors, including the significant capital and operating costs associated with operating a safe and reliable nuclear fleet. Based on this analysis, given the weak power and capacity price environment and the lack of legislative and regulatory solutions achieved to date, FES concluded that it would be increasingly difficult to operate these facilities in this environment and absent significant change concluded that it was probable that the facilities would be either deactivated or sold before the end of their estimated useful lives. As a result, FES recorded a pre- tax charge of $2.0 billion in the fourth quarter of 2017 to fully impair the nuclear facilities, including the generating plants and nuclear fuel as well as to reserve against the value of materials and supplies inventory and to increase its asset retirement obligation. For additional information see Note 2, "Asset Sales and Impairments." Although FES has access to a $500 million secured line of credit with FE, all of which was available as of January 31, 2018, its current credit rating and the current forward wholesale pricing environment present significant challenges to FES. As previously disclosed, FES has $515 million of maturing debt in 2018 (excluding intra-company debt), beginning with a $100 million principal payment due April 2, 2018. Based on FES' current senior unsecured debt rating, capital structure and long-term cash flow projections, the debt maturities are unlikely to be refinanced. Although management continues to explore cost reductions and other options to improve cash flow, these obligations and their impact to liquidity raise substantial doubt about FES’ ability to meet its obligations as they come due over the next twelve months and, as such, its ability to continue as a going concern. 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 preferred shares will receive the same dividend paid on common stock on an as-converted basis and are non-voting except in certain limited circumstances. The new preferred shares contain an optional conversion for holders beginning in July 2018, and will mandatorily convert in 18-months from the issuance, subject to limited exceptions. Proceeds from the investment were used to reduce holding company debt by $1.45 billion, fund the company’s pension plan by $750 million, with the remainder used for general corporate purposes. Because of this investment, FirstEnergy does not currently anticipate the need to issue additional equity through at least 2021 outside of its regular stock investment and employee benefit plans. In connection with the equity investment, FirstEnergy formed a RWG composed of three employees of FirstEnergy and two outside members to advise FirstEnergy management regarding an FES restructuring in the event the FES Board decides to seek bankruptcy protection. On December 22, 2017, the President signed into law the Tax Act. Substantially all of the provisions of the Tax Act are effective for taxable years beginning after December 31, 2017. The Tax Act includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated public utilities including FirstEnergy’s regulated distribution and transmission subsidiaries. The more significant changes that impact FirstEnergy included in the Tax Act are the following: • 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; 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. As a result of the Tax Act, FirstEnergy recognized a non-cash charge to income tax expense of $1.2 billion ($1.1 billion at FES) and resulted in excess deferred taxes at Regulated Distribution and Regulated Transmission of $2.3 billion, of which the revenue impact was recorded to a regulatory liability. Although certain state utility commissions have initiated proceedings to understand the impact of the Tax Act, the full amount and timing of any refund of excess deferred taxes or the impact of the lower federal income tax rate on future customer utility rates cannot be determined at this time. For additional information see Note 6, "Taxes." 12 FINANCIAL OVERVIEW (In millions, except per share amounts) 2017 2016 2015 2017 vs 2016 2016 vs 2015 For the Years Ended December 31 Increase (Decrease) REVENUES: OPERATING EXPENSES: Fuel Purchased power Other operating expenses Pension and OPEB mark-to-market adjustment Provision for depreciation Amortization of regulatory assets, net General taxes Impairment of assets and related charges Total operating expenses OPERATING INCOME (LOSS) OTHER INCOME (EXPENSE): Investment income (loss) Impairment of equity method investment Interest expense Capitalized financing costs Total other expense INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) INCOME TAXES (BENEFITS) NET INCOME (LOSS) EARNINGS (LOSS) PER SHARE OF COMMON STOCK: Basic Diluted NM - Not Meaningful $ 14,017 $ 14,562 $ 15,026 $ (545) (4)% $ (464) (3)% 1,383 3,194 4,232 141 1,138 308 1,043 2,406 13,845 1,666 3,843 3,851 147 1,313 297 1,042 10,665 22,824 1,855 4,423 3,740 242 1,282 172 978 42 12,734 (283) (649) 381 (6) (175) 11 1 (8,259) (8,979) (17)% (17)% 10 % (4)% (13)% 4 % — % (77)% (39)% (189) (580) 111 (95) 31 125 64 10,623 10,090 172 (8,262) 2,292 8,434 NM (10,554) 98 — (1,178) 79 (1,001) 84 — (1,157) 103 (970) (22) (362) (1,132) 117 (1,399) 14 — (21) (24) (31) 17 % — % 2 % (23)% 3 % 106 362 (25) (14) 429 (829) (9,232) 895 (3,055) 893 315 8,403 3,950 91 % (10,125) NM (3,370) $ (1,724) $ (6,177) $ 578 $ 4,453 72 % $ (6,755) $ $ (3.88) $ (3.88) $ (14.49) $ (14.49) $ 1.37 1.37 $ $ 10.61 10.61 73 % $ 73 % $ (15.86) (15.86) (10)% (13)% 3 % (39)% 2 % 73 % 7 % NM 79 % NM NM (100)% 2 % (12)% (31)% NM NM NM NM NM FirstEnergy’s net loss in 2017 was $(1,724) million, or a basic and diluted loss of $(3.88) per share of common stock, compared with a net loss of $(6,177) million, or a basic and diluted loss of $(14.49) per share of common stock in 2016, and net income of $578 million, or basic and diluted earnings of $1.37 per share of common stock in 2015. Highlights of the key changes in year-over- year financial results are included below: 2017 compared with 2016 FirstEnergy's operating results in 2017 increased $4,453 million as compared to 2016, primarily reflecting lower pre-tax impairment charges of $8,259 million, as follows: Pre-tax impairment charges of $10,665 million recognized in 2016, include the following: • • • Impairment charges of $9,218 million resulting from management's plans to exit its commodity-exposed generation at CES and the anticipated cash flows over the shortened period. The impairment of $800 million of goodwill at CES, reflecting a weak outlook for energy and capacity markets. Impairment charges totaling $647 million resulting from management's decision to exit the Bay Shore Unit 1 generating station and Units 1-4 of the W.H. Sammis generating station. Pre-tax impairment charges of $2,406 million recognized in 2017, include the following: • Charges of $2,045 million associated with FES' nuclear generating assets, as discussed above in "Executive Summary." Impairment charges of $193 million as a result of the amended asset purchase agreement between AE Supply, AGC, BU • Energy and a subsidiary of LS Power. Impairment charge of $120 million resulting from AE Supply's announced intent to exit operations of the Pleasants Power Station, through either sale or deactivation by January 1, 2019. Impairment charges totaling $41 million associated with formula-rate settlement agreements filed with FERC by MAIT and JCP&L. • • Additionally, as a result of the remeasurement of accumulated deferred income taxes in conjunction with the Tax Act, FirstEnergy recognized a non-cash charge to income tax expense of $1,193 million, of which approximately $1,062 million was recognized at CES. 13 FirstEnergy’s 2017 revenues decreased $545 million as compared to the same period in 2016, resulting from a $1,020 million decrease at CES, partially offset by a $181 million increase at Regulated Transmission and a $105 million increase at Regulated Distribution. • The decrease in revenues at CES resulted from a 10 million MWH decline in contract sales at lower prices, as well as lower capacity auction prices and lower net gains on financially settled contracts, partially offset by an increase in short- term (net hourly position) transactions. The increase in revenues at Regulated Transmission resulted primarily from recovery of incremental operating expenses and a higher rate base at ATSI and TrAIL. The increase in revenues at Regulated Distribution resulted from the implementation of new rates in January 2017, partially offset by lower weather-related distribution deliveries and higher customer shopping. • • Operating expenses decreased $8,979 million in 2017 as compared to 2016, reflecting a decrease at CES of $8,931 million, primarily associated with the asset impairment charges discussed above, and a decrease at Regulated Distribution of $307 million, partially offset by an increase of $155 million at Regulated Transmission. • • Purchased power decreased $649 million mainly due to lower volumes at CES and Regulated Distribution as well as lower capacity expense at CES. Fuel expense decreased $283 million, mainly due to lower generation at CES associated with outages and lower economic dispatch of fossil units reflecting low wholesale spot market energy prices, as well as lower unit prices on fossil fuel contracts. • Depreciation expense decreased $175 million, mainly from a lower asset base at CES resulting from asset impairments recognized in 2016. • Other operating expenses increased $381 million, reflecting an increase of $251 million at CES, primarily associated with estimated losses on long-term coal and coal transportation contract disputes recognized in 2017 and higher non-cash mark-to-market losses on commodity contract positions. Operating expenses at Regulated Distribution increased $88 million, resulting primarily from higher operating and maintenance expenses, including increased expenses in Pennsylvania recovered through the new base distribution rates, effective January 27, 2017, and increased storm restoration costs. Other expense increased $31 million, primarily from higher interest expense and lower capitalized financing costs. Absent the impact from the Tax Act, discussed above, FirstEnergy’s effective tax rate on pre-tax losses for 2017 and 2016 was 35.9% and 33.1%, respectively. The change in the effective tax rate resulted primarily from the absence of 2016 charges, including $246 million of valuation allowances recorded against state and local deferred tax assets, that management believes, more likely than not, will not be realized, as well as the impairment of $800 million of goodwill, of which $433 million was non-deductible for tax purposes. 2016 compared with 2015 FirstEnergy's operating results in 2016 decreased $6,755 million as compared to 2015, primarily reflecting pre-tax impairment charges of $10,665 million recognized in 2016, as discussed above. FirstEnergy’s 2016 revenues decreased $464 million as compared to the same period in 2015, resulting from a $835 million decrease at CES, partially offset by increases of $47 million and $98 million at Regulated Distribution and Regulated Transmission, respectively. • The decrease in revenue at CES resulted from a 15 million MWH decline in contract sales, as the segment aligned sales to its generation, as well as lower capacity revenue associated with lower capacity auction prices. The decline in contract sales volume was partially offset by higher wholesale sales and higher net gains on financially settled contracts. The increase in revenue at Regulated Distribution primarily resulted from higher weather-related distribution deliveries and the full year impact of net rate increases implemented in 2015, partially offset by lower generation sales. Distribution deliveries increased 0.3%, or 0.4 million MWHs, reflecting higher weather-related sales. The increase in revenue at Regulated Transmission primarily resulted from the recovery of incremental operating expenses and a higher rate base at ATSI and TrAIL, partially offset by adjustments associated with ATSI and TrAIL's annual rate filing for costs previously recovered as well as a lower ROE in 2016 at ATSI under its FERC-approved comprehensive settlement related to the implementation of its forward-looking formula rate. • • Operating expenses increased $10,090 million in 2016 as compared to 2015, reflecting an increase at CES of $9,799 million, primarily associated with the asset impairment charges discussed above, and an increase at Regulated Transmission of $78 million, partially offset by a decrease of $50 million at Regulated Distribution. 14 Changes in certain operating expenses include the following: • • • Purchased power decreased $580 million mainly due to lower volumes at CES and Regulated Distribution and lower capacity expense at CES. Fuel expense decreased $189 million mainly resulting from lower generation at CES associated with outages and lower economic dispatch of fossil units reflecting low wholesale spot market energy prices, as well as lower unit prices on fossil fuel contracts. Pension and OPEB mark-to-market adjustments decreased $95 million to $147 million in 2016. The 2016 adjustment resulted from a 25 bps decrease in the discount rate used to measure benefit obligations partially offset by higher than expected asset returns and changes in certain actuarial assumptions. • Other operating expenses increased $111 million, primarily reflecting an increase at Regulated Distribution resulting from the recognition of economic development and energy efficiency obligations in accordance with the PUCO's order approving the Ohio Companies' ESP IV, higher network transmission expenses, higher retirement benefit costs and higher operating and maintenance expenses associated with storm restoration costs, partially offset by lower PJM transmission costs and lower nuclear planned outage costs at CES. Other expense decreased $429 million, primarily due to the absence of a $362 million pre-tax impairment charge associated with FEV's investment in Global Holding recognized in 2015 and lower OTTI on NDT investments. FirstEnergy’s 2016 effective tax rate was 33.1% on pre-tax losses as compared to 35.3% on pre-tax income in 2015. The change primarily relates to the $800 million impairment of goodwill, of which $433 million was non-deductible for tax purposes. Additionally, in 2016 $246 million of valuation allowances were recorded against deferred tax assets, that management believes, more likely than not, will not be realized. RESULTS OF OPERATIONS 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 19, "Segment Information," of the Combined 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: Net Income (Loss) By Business Segment: Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/Other Net Income (Loss) Basic Earnings (Loss) Per Share Diluted Earnings (Loss) Per Share $ $ $ $ 2017 2016 2015 2017 vs 2016 2016 vs 2015 (In millions, except per share amounts) Increase (Decrease) $ 916 336 $ 651 331 (2,641) (335) (6,919) (240) 588 328 89 (427) $ 265 $ 5 4,278 (95) 63 3 (7,008) 187 (1,724) $ (6,177) $ 578 $ 4,453 $ (6,755) (3.88) $ (14.49) $ 1.37 (3.88) $ (14.49) $ 1.37 $ $ 10.61 10.61 $ $ (15.86) (15.86) 15 Summary of Results of Operations — 2017 Compared with 2016 Financial results for FirstEnergy’s business segments in 2017 and 2016 were as follows: 2017 Financial Results Revenues: External Electric Other Internal Total Revenues Operating Expenses: Fuel Purchased power Other operating expenses Pension and OPEB mark-to-market adjustment Provision for depreciation Amortization of regulatory assets, net General taxes Impairment of assets and related charges Total Operating Expenses Operating Income (Loss) Other Income (Expense): Investment income (loss) Interest expense Capitalized financing costs Total Other Expense Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated (In millions) $ 9,559 $ 1,325 $ 3,063 $ (170) $ 13,777 175 — 9,734 493 2,924 2,517 102 724 292 727 — 7,779 1,955 54 (535) 22 (459) — — 1,325 — — 203 — 224 16 173 41 657 668 — (156) 29 (127) 541 205 336 80 386 3,529 890 656 1,777 39 118 — 99 2,365 5,944 (15) (386) (571) — (386) (265) — 72 — 44 — 240 — 14,017 1,383 3,194 4,232 141 1,138 308 1,043 2,406 (535) 13,845 (2,415) (36) 172 81 (179) 27 (71) (2,486) 155 (37) (308) 1 (344) (380) (45) 98 (1,178) 79 (1,001) (829) 895 $ (2,641) $ (335) $ (1,724) Income (Loss) Before Income Taxes (Benefits) Income taxes (benefits) Net Income (Loss) 1,496 580 916 $ $ 16 2016 Financial Results Revenues: External Electric Other Internal Total Revenues Operating Expenses: Fuel Purchased power Other operating expenses Pension and OPEB mark-to-market adjustment Provision for depreciation Amortization of regulatory assets, net General taxes Impairment of assets and related charges Total Operating Expenses Operating Income (Loss) Other Income (Expense): Investment income (loss) Interest expense Capitalized financing costs Total Other Expense Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated (In millions) $ 9,401 $ 1,144 $ 3,892 $ (174) $ 14,263 228 — 9,629 567 3,303 2,429 101 676 290 720 — 8,086 1,543 49 (586) 20 (517) — — 1,144 — — 154 1 187 7 153 — 502 642 — (158) 34 (124) 518 187 331 178 479 4,549 1,099 1,019 1,526 45 387 — 134 10,665 14,875 (107) (479) (760) — (479) (258) — 63 — 35 — (639) 299 — 14,562 1,666 3,843 3,851 147 1,313 297 1,042 10,665 22,824 (10,326) (121) (8,262) 66 (194) 37 (91) (10,417) (3,498) (31) (219) 12 (238) (359) (119) $ (6,919) $ (240) $ 84 (1,157) 103 (970) (9,232) (3,055) (6,177) Income (Loss) Before Income Taxes (Benefits) Income taxes (benefits) Net Income (Loss) 1,026 375 651 $ $ 17 Changes Between 2017 and 2016 Financial Results Increase (Decrease) Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated (In millions) $ 158 $ 181 $ (829) $ 4 $ Revenues: External Electric Other Internal Total Revenues Operating Expenses: Fuel Purchased power Other operating expenses Pension and OPEB mark-to-market adjustment Provision for depreciation Amortization of regulatory assets, net General taxes Impairment of assets and related charges Total Operating Expenses Operating Income Other Income (Expense): Investment income (loss) Interest expense Capitalized financing costs Total Other Income (Expense) Income (Loss) Before Income Taxes (Benefits) Income taxes (benefits) Net Income (Loss) $ (486) (59) — (545) (283) (649) 381 (6) (175) 11 1 (8,259) (8,979) 8,434 14 (21) (24) (31) 8,403 3,950 4,453 (53) — 105 (74) (379) 88 1 48 2 7 — (307) 412 5 51 2 58 470 205 265 — — 181 — — 49 (1) 37 9 20 41 155 26 — 2 (5) (3) 23 18 (98) (93) (1,020) (209) (363) 251 (6) (269) — (35) (8,300) (8,931) 7,911 15 15 (10) 20 7,931 3,653 $ 5 $ 4,278 $ 92 93 189 — 93 (7) — 9 — 9 — 104 85 (6) (89) (11) (106) (21) 74 (95) $ 18 Regulated Distribution — 2017 Compared with 2016 Regulated Distribution's operating results increased $265 million in 2017, as compared to 2016, primarily reflecting the implementation of approved rates in Ohio, Pennsylvania and New Jersey, and the absence of a $51 million regulatory charge recognized in 2016 resulting from the PUCO's March 31, 2016 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV, partially offset by a $30 million non-cash charge to Income tax expense as a result of the Tax Act and lower weather-related customer usage, as further described below. Revenues — The $105 million increase in total revenues resulted from the following sources: For the Years Ended December 31 Increase Revenues by Type of Service 2017 2016 (Decrease) (In millions) Distribution services $ 5,323 $ 4,721 $ 602 Generation sales: Retail Wholesale Total generation sales Other Total Revenues 3,767 469 4,236 175 4,183 497 4,680 228 $ 9,734 $ 9,629 $ (416) (28) (444) (53) 105 Distribution services revenues increased $602 million primarily resulting from the implementation of the DMR in Ohio, effective January 1, 2017, approved base distribution rate increases in Pennsylvania and New Jersey, effective January 27, 2017, and January 1, 2017, respectively, and higher revenue from the DCR in Ohio. Additionally, distribution revenues were impacted by higher rates associated with the recovery of deferred costs and the implementation of certain energy efficiency programs in Ohio. Partially offsetting these rate increases was a decline in MWH deliveries, primarily resulting from lower weather-related usage, as described below. Distribution deliveries by customer class are summarized in the following table: Electric Distribution MWH Deliveries 2017 2016 (Decrease) For the Years Ended December 31 Increase Residential Commercial Industrial Other (In thousands) 52,048 41,789 51,307 572 54,840 43,340 50,082 579 Total Electric Distribution MWH Deliveries 145,716 148,841 (5.1)% (3.6)% 2.4 % (1.2)% (2.1)% Lower distribution deliveries to residential and commercial customers primarily reflect lower weather-related usage resulting from heating degree days that were 4% below 2016, and 11% below normal as well as cooling degree days that were 19% below 2016, but 8% above normal. Deliveries to industrial customers increased reflecting higher shale and steel customer usage. 19 The following table summarizes the price and volume factors contributing to the $444 million decrease in generation revenues in 2017, as compared to 2016: 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 (250) (166) (416) 15 (30) (13) (28) Decrease in Generation Revenues $ (444) The decrease in retail generation sales volumes was primarily due to increased customer shopping in Ohio, Pennsylvania and New Jersey, as well as lower weather-related usage, as described above. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 86% from 83% for the Ohio Companies, to 68% from 67% for the Pennsylvania Companies and to 52% from 51% for JCP&L. The decrease in retail generation prices primarily resulted from lower default service auction prices in Ohio, Pennsylvania and New Jersey. Wholesale generation revenues decreased $28 million in 2017, as compared to 2016, primarily due to lower spot market energy prices and capacity revenue, partially offset by higher wholesale sales. The difference between current wholesale generation revenues and certain energy costs is deferred for future recovery or refund, with no material impact to earnings. Other revenues decreased $53 million, primarily related to the absence of a $29 million gain on the sale of oil and gas rights at WP recognized in 2016 as well as $20 million in lower transition cost recovery revenues in New Jersey. Operating Expenses — Total operating expenses decreased $307 million primarily due to the following: • • Fuel expense decreased $74 million in 2017, as compared to 2016, primarily related to lower unit costs. Purchased power costs decreased $379 million in 2017, as compared to 2016, primarily due to decreased volumes, as described above, as well as lower default service auction prices. Source of Change in Purchased Power Purchases from non-affiliates: Change due to decreased unit costs $ Change due to decreased volumes Purchases from affiliates: Change due to decreased unit costs Change due to decreased volumes Capacity expense Increase (Decrease) (In millions) (147) (151) (298) (26) (67) (93) 12 Decrease in Purchased Power Costs $ (379) 20 • Other operating expenses increased $88 million primarily due to: • Higher network transmission expenses of $35 million. 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; • Higher operating and maintenance expenses of $64 million, including increased expenses in Pennsylvania recovered through the new base distribution rates, effective January 27, 2017, and increased storm restoration costs, which were deferred for future recovery, resulting in no material impact on current period earnings; • Higher energy efficiency program expenses of $45 million in Ohio, which were recovered through higher • distribution rider revenues; partially offset by, Lower regulatory costs of $51 million resulting from the absence of economic development and energy efficiency obligations recognized in 2016 in accordance with the PUCO's March 31, 2016 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV. • Depreciation expenses increased $48 million due to a higher asset base as well as increased rates in Pennsylvania. Other Expense — Total other expense decreased $58 million in 2017, as compared to 2016, primarily related to lower interest expense resulting from various debt maturities at JCP&L, CEI and OE. Income Taxes — Regulated Distribution’s effective tax rate was 38.8% and 36.5% for 2017 and 2016, respectively. The increase primarily resulted from a $30 million charge to Income tax expense as a result of the remeasurement of accumulated deferred income taxes in conjunction with the Tax Act. Regulated Transmission — 2017 Compared with 2016 Regulated Transmission's operating results increased $5 million in 2017, as compared to 2016, primarily resulting from the impact of a higher rate base at ATSI and TrAIL partially offset by a pre-tax impairment charge of $41 million, as discussed below. Revenues — Total revenues increased $181 million in 2017, as compared to 2016, primarily due to recovery of incremental operating expenses and a higher rate base at ATSI and TrAIL, and the implementation of new rates at MAIT and JCP&L, as further discussed below under "FERC Matters." Revenues by transmission asset owner are shown in the following table: Revenues by Transmission Asset Owner 2017 2016 (Decrease) For the Years Ended December 31 Increase ATSI TrAIL MAIT(1) JCP&L Other $ (In millions) $ 657 282 110 125 151 $ 540 252 101 91 160 Total Revenues $ 1,325 $ 1,144 $ 117 30 9 34 (9) 181 (1) Revenues prior to January 31, 2017, represent transmission revenues under stated rates at ME and PN. Operating Expenses — Total operating expenses increased $155 million in 2017, as compared to 2016, principally due to higher operating and maintenance expenses, as well as higher property taxes and depreciation expense due to a higher asset base. Additionally, as a result of settlement agreements filed with FERC regarding the transmission rates for MAIT and JCP&L, a pre-tax impairment charge of $41 million was recognized in 2017. The settlement agreements are currently pending at FERC. 21 Income Taxes — Regulated Transmission’s effective tax rate was 37.9% and 36.1% for 2017 and 2016, respectively. The increase resulted from a $6 million charge to Income tax expense as a result of the remeasurement of accumulated deferred income taxes in conjunction with the Tax Act. CES — 2017 Compared with 2016 Operating results increased $4,278 million in 2017, as compared to 2016, primarily due to lower asset impairment and plant exit costs, as discussed in "Financial Overview," above, and lower depreciation expense, partially offset by a charge to Income tax expense of $1,062 million as a result of the Tax Act, pre-tax charges of $318 million associated with estimated losses on long-term coal and coal transportation contract disputes, as discussed in "Outlook - Environmental Matters" below, higher non-cash mark-to- market losses on commodity contract positions, lower capacity revenue, and the impact of lower contract sales. Revenues — Total revenues decreased $1,020 million in 2017, as compared to 2016, primarily due to lower capacity auction prices, lower contract sales volumes at lower prices, and lower net gains on financially settled contracts, partially offset by an increase in short-term (net hourly position) transactions, as further described below. The decrease in total revenues resulted from the following sources: Revenues by Type of Service 2017 2016 (Decrease) For the Years Ended December 31 Contract Sales: Direct Governmental Aggregation $ Mass Market POLR Structured Sales Total Contract Sales Wholesale Transmission Other Total Revenues MWH Sales by Channel Contract Sales: Direct Governmental Aggregation Mass Market POLR Structured Sales Total Contract Sales Wholesale Total MWH Sales (In millions) $ 735 396 127 504 346 2,108 1,300 41 80 $ 812 814 169 583 463 2,841 1,457 73 178 (77) (418) (42) (79) (117) (733) (157) (32) (98) $ 3,529 $ 4,549 $ (1,020) For the Years Ended December 31 2017 2016 (In thousands) Increase (Decrease) 15,157 7,431 1,867 9,140 8,972 42,567 22,492 65,059 15,310 13,730 2,431 9,969 11,414 52,854 15,201 68,055 (1.0)% (45.9)% (23.2)% (8.3)% (21.4)% (19.5)% 48.0 % (4.4)% 22 The following tables summarize the price and volume factors contributing to changes in revenues: Source of Change in Revenues Increase (Decrease) MWH Sales Channel: Sales Volumes Prices Direct $ (8) $ Governmental Aggregation Mass Market POLR Structured Sales Wholesale (373) (40) (49) (101) 202 (69) (45) (2) (30) (16) 23 Gain on Settled Contracts (In millions) Capacity Revenue Total $ — $ — $ (77) — — — — — — — — (156) (226) (418) (42) (79) (117) (157) Lower sales volumes in the Governmental Aggregation channel primarily reflects the termination of an FES customer contract in 2016. The Direct, Governmental Aggregation and Mass Market customer base was approximately 900,000 as of December 31, 2017, compared to 1.1 million as of December 31, 2016. Although unit pricing was lower year-over-year in the Direct, Governmental Aggregation and Mass Market channels, the decrease was primarily attributable to lower capacity rates, as discussed below, which is a component of the retail price. The decrease in POLR revenue of $79 million was primarily due to both lower volumes and lower unit prices. Structured revenue decreased $117 million, primarily due to the impact of lower market prices and lower structured transaction volumes. Wholesale revenues decreased $157 million, primarily due to a decrease in capacity revenue from lower capacity auction prices and lower net gains on financially settled contracts, partially offset by an increase in short-term (net hourly position) transactions at higher market prices. Transmission revenue decreased $32 million, primarily due to lower congestion revenue associated with less volatile market conditions. Other revenue decreased $98 million, primarily due to lower lease revenues from the expiration of a nuclear sale-leaseback agreement. CES earned lease revenue associated with the lessor equity interests it had purchased in sale-leaseback transactions, one of which expired in June 2017 and another in May 2016. Operating Expenses — Total operating expenses decreased $8,931 million in 2017 due to the following: • • Fuel costs decreased $209 million, primarily due to the absence of approximately $58 million in settlement and termination costs on coal contracts recognized in 2016, as well as lower generation associated with outages and economic dispatch of fossil units resulting from low wholesale spot market energy prices, as discussed above, partially offset by higher unit costs. Purchased power costs decreased $363 million primarily due to lower capacity expenses ($271 million) and lower unit costs ($126 million), partially offset by higher volumes ($34 million). The decrease in capacity expense, which is a component of CES' retail price, was primarily the result of lower contract sales and lower capacity rates associated with CES' retail sales obligations. Lower unit costs primarily resulted from lower wholesale spot market prices, as discussed above. • Charges of $318 million associated with estimated losses on long-term coal and coal transportation contract disputes was recognized in 2017, as discussed in "Outlook - Environmental Matters" below. • Fossil operating and maintenance expenses decreased $18 million, primarily due to lower outage costs. • Nuclear operating and maintenance expenses increased $14 million, primarily as a result of higher employee benefit costs, partially offset by lower refueling outage costs. • Retirement benefit costs decreased $14 million. • Transmission expenses decreased $60 million, primarily due to lower contract sales volumes. 23 • Other operating expenses increased $11 million, primarily due to higher non-cash mark-to-market losses on commodity contract positions, partially offset by the absence of a termination charge recognized in 2016 associated with an FES Governmental Aggregation customer contract and lower lease expense as a result of the expiration of a nuclear sale- leaseback agreement. • Depreciation expense decreased $269 million, primarily due to a lower asset base resulting from asset impairments recognized in 2016, partially offset by the absence of an out-of-period adjustment to reduce the depreciation of a hydroelectric generating station in the third quarter of 2016. • General taxes decreased $35 million, primarily due to lower property taxes and reduced gross receipts taxes associated with lower retail sales volumes. • Impairment of assets and related charges decreased $8,300 million, primarily due to the absence of impairments recognized in 2016 related to goodwill and the competitive generation assets primarily resulting from the strategic review announced in November 2016, partially offset by the impairments recognized in 2017 related to the nuclear generating assets and the Pleasants Power Station, as discussed further in "Executive Summary," above. Other Expense — Total other expense decreased $20 million in 2017, as compared to 2016, primarily due to lower OTTI on NDT investments and lower net financing costs resulting from PCRB repurchases by FG and NG in 2017 and 2016. Income Taxes (Benefits) — Absent the impact from the Tax Act, discussed above, CES' effective tax rate on pre-tax losses for 2017 and 2016 was 36.5% and 33.6%, respectively. The change in the effective tax rate year-over-year resulted primarily from the absence of 2016 charges, including $246 million of valuation allowances recorded against state and local deferred tax assets, that management believes, more likely than not, will not be realized, as well as the impairment of $800 million of goodwill recognized in 2016, of which $433 million was non-deductible for tax purposes. Corporate/Other — 2017 Compared with 2016 Financial results from the Corporate/Other operating segment and reconciling adjustments resulted in a $95 million decrease in consolidated earnings in 2017, as compared to 2016, primarily associated with higher interest expense and a charge to Income tax expense as a result of the remeasurement of accumulated deferred income taxes in conjunction with the Tax Act. Higher interest expense resulted from the issuance of $3 billion of senior notes in June 2017. 24 Summary of Results of Operations — 2016 Compared with 2015 Financial results for FirstEnergy’s business segments in 2016 and 2015 were as follows: 2016 Financial Results Revenues: External Electric Other Internal Total Revenues Operating Expenses: Fuel Purchased power Other operating expenses Pension and OPEB mark-to-market adjustment Provision for depreciation Amortization of regulatory assets, net General taxes Impairment of assets and related charges Total Operating Expenses Operating Income (Loss) Other Income (Expense): Investment income (loss) Impairment of equity method investment Interest expense Capitalized financing costs Total Other Expense Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated (In millions) $ 9,401 $ 1,144 $ 3,892 $ (174) $ 14,263 228 — 9,629 567 3,303 2,429 101 676 290 720 — 8,086 1,543 49 — (586) 20 (517) — — 1,144 — — 154 1 187 7 153 — 502 642 — — (158) 34 (124) 518 187 331 178 479 4,549 1,099 1,019 1,526 45 387 — 134 10,665 14,875 (107) (479) (760) — (479) (258) — 63 — 35 — (639) 299 — 14,562 1,666 3,843 3,851 147 1,313 297 1,042 10,665 22,824 (10,326) (121) (8,262) 66 — (194) 37 (91) (10,417) (3,498) (31) — (219) 12 (238) (359) (119) $ (6,919) $ (240) $ 84 — (1,157) 103 (970) (9,232) (3,055) (6,177) Income (Loss) Before Income Taxes (Benefits) Income taxes (benefits) Net Income (Loss) 1,026 375 651 $ $ 25 2015 Financial Results Revenues: External Electric Other Internal Total Revenues Operating Expenses: Fuel Purchased power Other operating expenses Pension and OPEB mark-to-market adjustment Provision for depreciation Amortization of regulatory assets, net General taxes Impairment of assets and related charges Total Operating Expenses Operating Income (Loss) Other Income (Expense): Investment income (loss) Impairment of equity method investment Interest expense Capitalized financing costs Total Other Expense Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated (In millions) $ 9,386 $ 1,046 $ 4,493 $ (165) $ 14,760 196 — 9,582 533 3,653 2,231 179 664 165 703 8 8,136 1,446 42 — (600) 25 (533) — — 1,046 — — 148 3 164 7 102 — 424 622 — — (147) 44 (103) 205 686 5,384 1,322 1,456 1,670 60 394 — 140 34 5,076 308 (16) — (192) 39 (169) 139 50 89 (135) (686) (986) — (686) (309) — 60 — 33 — 266 — 15,026 1,855 4,423 3,740 242 1,282 172 978 42 (902) 12,734 (84) 2,292 (48) (362) (193) 9 (594) (678) (251) $ (427) $ (22) (362) (1,132) 117 (1,399) 893 315 578 Income (Loss) Before Income Taxes (Benefits) Income taxes (benefits) Net Income (Loss) 913 325 588 $ 519 191 328 $ $ 26 Changes Between 2016 and 2015 Financial Results Increase (Decrease) Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated (In millions) Revenues: External Electric Other Internal Total Revenues Operating Expenses: Fuel Purchased power Other operating expenses Pension and OPEB mark-to-market adjustment Provision for depreciation Amortization of regulatory assets, net General taxes Impairment of assets and related charges Total Operating Expenses Operating Income (Loss) Other Income (Expense): Investment income (loss) Impairment of equity method investment Interest expense Capitalized financing costs Total Other Expense Income (Loss) Before Income Taxes (Benefits) Income taxes (benefits) Net Income (Loss) $ $ $ 15 32 — 47 34 (350) 198 (78) 12 125 17 (8) (50) 97 7 — 14 (5) 16 113 50 63 98 — — 98 — — 6 (2) 23 — 51 — 78 20 — — (11) (10) (21) (1) (4) $ (601) $ (9) $ (497) (27) (207) (835) (223) (437) (144) (15) (7) — (6) 10,631 9,799 28 207 226 — 207 51 — 3 — 2 — 263 33 — (464) (189) (580) 111 (95) 31 125 64 10,623 10,090 (10,634) (37) (10,554) 82 — (2) (2) 78 (10,556) (3,548) 17 362 (26) 3 356 319 132 187 106 362 (25) (14) 429 (10,125) (3,370) (6,755) $ $ 3 $ (7,008) $ 27 Regulated Distribution — 2016 Compared with 2015 Regulated Distribution's operating results increased $63 million in 2016, as compared to 2015, including a $78 million decrease in its Pension and OPEB mark-to-market adjustment, partially offset by regulatory charges of $51 million resulting from the PUCO's March 31, 2016 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV. Excluding the impact of these adjustments, year-over-year earnings reflect higher distribution deliveries and the full year impact of net rate increases implemented in 2015 as a result of approved rate cases at certain of the Utilities, as further described below, partially offset by higher retirement benefit costs and other operating expenses. Revenues — The $47 million increase in total revenues resulted from the following sources: For the Years Ended December 31 Increase Revenues by Type of Service 2016 2015 (Decrease) (In millions) Distribution services $ 4,721 $ 4,459 $ 262 Generation sales: Retail Wholesale Total generation sales Other Total Revenues 4,183 497 4,680 228 4,354 573 4,927 196 $ 9,629 $ 9,582 $ (171) (76) (247) 32 47 Distribution services revenues increased $262 million, primarily resulting from the full year impact of approved base distribution rate increases at the Pennsylvania Companies, effective May 3, 2015, and MP and PE in West Virginia, effective February 25, 2015, partially offset by a distribution rate decrease at JCP&L, including the recovery of 2011 and 2012 storm costs, effective April 1, 2015. Additionally, distribution revenues were impacted by higher rates associated with the recovery of deferred costs as well as higher weather-related usage, as described below. Distribution deliveries by customer class are summarized in the following table: Electric Distribution MWH Deliveries 2016 2015 (Decrease) For the Years Ended December 31 Increase Residential Commercial Industrial Other (In thousands) 54,840 43,340 50,082 579 54,466 43,091 50,269 585 Total Electric Distribution MWH Deliveries 148,841 148,411 0.7 % 0.6 % (0.4)% (1.0)% 0.3 % Higher distribution deliveries to residential and commercial customers reflect increased weather-related usage resulting from cooling degree days that were 18% above 2015, and 37% above normal, partially offset by heating degree days that were 6% below 2015, and 9% below normal. Additionally, distribution deliveries to residential and commercial customers were impacted by declining average customer usage associated with more energy efficient products and services. Year-to-date deliveries to industrial customers declined slightly as the increase from shale customer usage was more than offset by a decrease from steel and chemical customer usage. 28 The following table summarizes the price and volume factors contributing to the $247 million decrease in generation revenues in 2016 as compared to 2015: 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 Decrease in Generation Revenues $ (196) 25 (171) 47 (107) (16) (76) (247) The decrease in retail generation sales volumes was primarily due to increased customer shopping in Ohio, Pennsylvania, and New Jersey. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 83% from 80% for the Ohio Companies, to 67% from 65% for the Pennsylvania Companies and to 51% from 50% for JCP&L. The increase in retail generation prices primarily resulted from an ENEC rate increase in West Virginia, effective January 1, 2016, partially offset by lower default service auction prices in Ohio and Pennsylvania. Wholesale generation revenues decreased $76 million, in 2016 as compared to 2015, primarily due to lower spot market energy prices, partially offset by higher wholesale sales. The difference between current wholesale generation revenues and certain energy costs incurred is deferred for future recovery or refund, with no material impact to earnings. Other revenues increased $32 million, primarily related to a $29 million gain on the sale of oil and gas rights at WP. Operating Expenses — Total operating expenses decreased $50 million primarily due to the following: • • Fuel expense increased $34 million, in 2016 as compared 2015, primarily related to higher generation. Purchased power costs decreased $350 million, in 2016 as compared to 2015, primarily due to lower volumes resulting from increased customer shopping, as described above, as well as lower unit costs reflecting lower default service auction prices in Ohio and Pennsylvania. Source of Change in Purchased Power Decrease (In millions) Purchases from non-affiliates: Change due to decreased unit costs $ Change due to decreased volumes Purchases from affiliates: Change due to decreased unit costs Change due to decreased volumes Capacity expense Decrease in Purchased Power Costs $ (133) (6) (139) (2) (204) (206) (5) (350) 29 • Other operating expenses increased $198 million primarily due to: • An increase of $51 million resulting from the recognition of economic development and energy efficiency obligations in accordance with the PUCO's March 31, 2016 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV. • Higher retirement benefit costs of $57 million. • Higher transmission expenses of $56 million primarily related to an increase in network transmission expenses at the Ohio Companies, partially offset by lower congestion expenses at MP. 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. • Higher operating and maintenance expense of $33 million, primarily due to increased storm restoration costs, which are deferred for future recovery resulting in no material impact on current period earnings. • Pension and OPEB mark-to-market adjustments decreased $78 million to $101 million in 2016. The 2016 adjustment resulted from a 25 bps decrease in the discount rate used to measure benefit obligations partially offset by higher than expected asset returns and changes in certain actuarial assumptions. • Depreciation expenses increased $12 million due to a higher asset base. • Net amortization of regulatory assets increased $125 million primarily due to: • A full year recovery of storm costs in New Jersey, Pennsylvania, and West Virginia, effective with the implementation of new rates as discussed above ($35 million), • Recovery of West Virginia vegetation management program costs ($40 million) • • Higher deferral of storm restoration costs ($39 million). The recovery of previously deferred energy and fuel costs ($75 million), partially offset by • General taxes increased $17 million primarily due to higher revenue-related taxes in Pennsylvania and higher property taxes in Ohio. Other Expense — Total other expense decreased $16 million primarily related to lower interest expense resulting from various debt maturities at JCP&L and OE in 2016. Income Taxes — Regulated Distribution’s effective tax rate was 36.5% and 35.6% for 2016 and 2015, respectively. Regulated Transmission — 2016 Compared with 2015 Regulated Transmission's operating results increased $3 million, in 2016 as compared to 2015, primarily resulting from a higher rate base, partially offset by adjustments associated with ATSI and TrAIL's annual rate filing for costs previously recovered, a lower return on equity at ATSI, and lower capitalized financing costs. Revenues — Total revenues increased $98 million principally due to recovery of incremental operating expenses and a higher rate base at ATSI and TrAIL, partially offset by adjustments associated with ATSI's and TrAIL's annual rate filing for costs previously recovered as well as a lower ROE at ATSI under its FERC-approved comprehensive settlement related to the implementation of its forward- looking rate effective January 1, 2015. 30 Revenues by transmission asset owner are shown in the following table: Revenues by Transmission Asset Owner 2016 2015 Increase For the Years Ended December 31 ATSI TrAIL MAIT(1) JCPL Other $ (In millions) $ 540 252 101 91 160 $ 446 252 100 89 159 Total Revenues $ 1,144 $ 1,046 $ (1) Revenues represent transmission revenues under stated rates at ME and PN. Operating Expenses — 94 — 1 2 1 98 Total operating expenses increased $78 million principally due to higher property taxes and depreciation expense at ATSI, which are recovered through ATSI's forward-looking formula rate. Other Expenses — Other expense increased $21 million, in 2016 as compared to 2015, primarily due to lower capitalized financing costs resulting from lower construction work in progress balances at ATSI as well as increased interest expense resulting from a long-term debt issuance of $150 million at ATSI in the fourth quarter of 2015, the proceeds of which, in part, paid off short-term borrowings. Income Taxes — Regulated Transmission’s effective tax rate was 36.1% and 36.8% for 2016 and 2015, respectively. CES — 2016 Compared with 2015 Operating results decreased $7,008 million, in 2016 as compared to 2015, primarily resulting from pre-tax asset impairment charges of $10,665 million discussed above, partially offset by lower mark-to-market gains on commodity contract positions, a lower Pension and OPEB mark-to-market adjustment and lower settlement and termination costs related to coal contracts. Excluding these items, year-over-year operating results were impacted by lower capacity revenues, lower sales volumes, a termination charge associated with an FES customer contract, and higher retirement and employee benefit costs, partially offset by lower fuel costs, reduced transmission expenses, and lower purchased power. Revenues — Total revenues decreased $835 million, in 2016 as compared to 2015, primarily due to decreased sales volumes and lower capacity revenue, partially offset by higher net gains on financially settled contracts and an increase in short-term (net hourly position) transactions, as further described below. 31 The decrease in total revenues resulted from the following sources: Revenues by Type of Service 2016 2015 (Decrease) For the Years Ended December 31 Increase Contract Sales: Direct Governmental Aggregation $ Mass Market POLR Structured Sales Total Contract Sales Wholesale Transmission Other Total Revenues MWH Sales by Channel Contract Sales: Direct Governmental Aggregation Mass Market POLR Structured Sales Total Contract Sales Wholesale Total MWH Sales (In millions) $ 1,269 $ 1,012 265 712 558 3,816 1,225 138 205 812 814 169 583 463 2,841 1,457 73 178 $ 4,549 $ 5,384 $ (457) (198) (96) (129) (95) (975) 232 (65) (27) (835) For the Years Ended December 31 Increase 2016 2015 (Decrease) (In thousands) 15,310 13,730 2,431 9,969 11,414 52,854 15,201 68,055 23,585 15,443 3,878 11,950 12,902 67,758 7,326 75,084 (35.1)% (11.1)% (37.3)% (16.6)% (11.5)% (22.0)% 107.5 % (9.4)% The following tables summarize the price and volume factors contributing to changes in revenues: Source of Change in Revenues Increase (Decrease) MWH Sales Channel: Sales Volumes Prices Direct $ (445) $ Governmental Aggregation Mass Market POLR Structured Sales Wholesale (112) (99) (118) (64) 223 (12) (86) 3 (11) (31) (10) Gain on Settled Contracts (In millions) Capacity Revenue Total $ — $ — $ (457) — — — — 98 — — — — (79) (198) (96) (129) (95) 232 Lower sales volumes in the Direct, Governmental Aggregation and Mass Market sales channels primarily reflects FES' strategy to more effectively hedge its generation. The Direct, Governmental Aggregation, and Mass Market customer base was 1.1 million as 32 of December 31, 2016, compared to 1.6 million as of December 31, 2015. Although unit pricing was lower year-over-year in the Direct and Governmental Aggregation channels, the decrease was primarily attributable to lower capacity expenses, as discussed below, which is a component of the retail price. The decrease in POLR sales of $129 million was primarily due to lower volumes. Structured Sales decreased $95 million, primarily due to the impact of lower market prices and lower structured transaction volumes. Wholesale revenues increased $232 million, primarily due to an increase in short-term (net hourly position) transactions and higher net gains on financially settled contracts, partially offset by a decrease in capacity revenue from lower capacity auction prices and lower spot market energy prices. Transmission revenue decreased $65 million, primarily due to lower congestion revenue associated with less volatile market conditions. Other revenue decreased $27 million, primarily due to the absence of a gain on the sale of property to a regulated affiliate in 2015 and lower lease revenues from the expiration of a nuclear sale-leaseback agreement. Operating Expenses — Total operating expenses increased $9,799 million in 2016 due to the following: • • Fuel costs decreased $223 million, primarily due to lower generation associated with outages and lower economic dispatch of fossil units resulting from low wholesale spot market energy prices, as discussed above, as well as lower unit prices on fossil fuel contracts. Purchased power costs decreased $437 million due to lower capacity expenses ($234 million) and lower volumes ($203 million). The decrease in capacity expense, which is a component of CES' retail price, was primarily the result of lower contract sales and lower capacity rates associated with CES' retail sales obligations. Lower volumes primarily resulted from lower contract sales, as discussed above, partially offset by higher economic purchases, resulting from the low wholesale spot market price environment. • Nuclear operating costs decreased $39 million, primarily as a result of lower refueling outage costs, partially offset by higher employee benefit costs. There were two refueling outages in 2016 as compared to three refueling outages in 2015. • Retirement benefit costs increased $31 million. • Transmission expenses decreased $175 million, primarily due to lower congestion and market-based ancillary costs associated with less volatile market conditions as compared to 2015, as well as lower load requirements. • Other operating expenses increased $39 million, primarily due to lower mark-to-market gains on commodity contract positions of $84 million and a $37 million charge associated with the termination of an FES customer contract, partially offset by lower lease expense as a result of the expiration of a nuclear sale-leaseback agreement. • • Pension and OPEB mark-to-market adjustments decreased $15 million to $45 million in 2016. The 2016 adjustment resulted from a 25 bps decrease in the discount rate used to measure benefit obligations, partially offset by higher than expected asset returns and changes in other actuarial assumptions. Impairment of assets and related charges increased $10,631 million, primarily due to impairments of goodwill and the competitive generation assets further discussed above. Other Expense — Total other expense decreased $78 million, in 2016 compared to 2015, primarily due to lower OTTI on NDT investments. Income Taxes (Benefits) — CES' effective tax rate was 33.6% on pre-tax losses and 36.0% on pre-tax income for 2016 and 2015, respectively. The change in the effective tax rate is primarily due to $246 million of valuation allowances recorded against deferred tax assets, that management believes, more likely than not, will not be realized, as well as the impairment of $800 million of goodwill, of which $433 million was non-deductible for tax purposes. 33 Corporate/Other — 2016 Compared with 2015 Financial results and reconciling items included in Corporate/Other resulted in a $187 million increase in net income in 2016 compared to 2015 primarily due to the absence of a $362 million pre-tax impairment of FirstEnergy's equity method investment in Global Holding recognized in 2015. Excluding the impact of this adjustment, year-over-year results were impacted by higher operating and maintenance costs, higher interest expense and changes in the consolidated effective tax rate, which for 2016 was 33.1% on pre-tax losses and for 2015 was 35.5% on pre-tax income. The increased interest expense primarily relates to debt redemption costs related to the FE revolving credit facility and term loans, as discussed in "Capital Resources and Liquidity." The higher consolidated effective tax rate primarily resulted from the absence of tax benefits recognized in 2015 associated with an IRS- approved change in accounting method that increased the tax basis in certain assets resulting in higher future tax deductions, as well as from changes in state apportionment factors. 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 and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions. As a result of the Tax Act, FirstEnergy adjusted its net deferred tax liabilities at December 31, 2017, for the reduction in the corporate income tax rate from 35% to 21%. For the portions of FirstEnergy’s business that apply regulatory accounting, the impact of reducing the net deferred tax liabilities was offset with a regulatory liability, as appropriate, for amounts expected to be refunded to rate payers in future rates, with the remainder recorded to deferred income tax expense. The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2017 and December 31, 2016, and the changes during the year ended December 31, 2017: Net Regulatory Assets (Liabilities) by Source December 31, 2017 December 31, 2016 Increase (Decrease) (In millions) Regulatory transition costs $ 46 $ 90 $ Customer receivables (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 (2,765) (323) (774) 187 198 258 118 329 46 468 (304) (770) 122 331 296 153 397 74 (44) (3,233) (19) (4) 65 (133) (38) (35) (68) (28) Net Regulatory Assets (Liabilities) included on the Consolidated Balance Sheets $ (2,680) $ 857 $ (3,537) Regulatory assets that do not earn a current return totaled approximately $7 million and $153 million as of December 31, 2017 and 2016, respectively, primarily related to storm damage costs, and are currently being recovered through rates. 34 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. 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 preferred shares will receive the same dividend paid on common stock on an as-converted basis and are non-voting except in certain limited circumstances. The new preferred shares contain an optional conversion for holders beginning in July 2018, and will mandatorily convert in 18-months from the issuance, subject to limited exceptions. Proceeds from the investment were used to reduce holding company debt by $1.45 billion and fund the company’s pension plan by $750 million, with the remainder used for general corporate purposes. The equity investment allows FirstEnergy to strengthen its balance sheet and supports the company's transition to a fully regulated utility company. By deleveraging the company, the investment will also enable FirstEnergy to enhance its investment grade credit metrics and FirstEnergy does not currently anticipate the need to issue additional equity through at least 2021 outside of its regular stock investment and employee benefit plans. In addition to this equity investment, FE and its utility 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 2018 and beyond, FE and its utility 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 at certain utility 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. FirstEnergy’s unregulated subsidiaries, specifically FES and AE Supply, expect to rely on, in the case of AE Supply, internal sources, an unregulated companies' money pool (which also includes FE, FET, FEV and certain other unregulated subsidiaries of FE but excludes FENOC, FES and its subsidiaries) and proceeds generated from previously disclosed asset sales, subject to closing, and in the case of FES, its current access to a separate unregulated companies' money pool, which includes FE, FES' subsidiaries and FENOC, and a two-year secured line of credit from FE of up to $500 million, as further described below. FES subsidiaries have debt maturities of $515 million in 2018, (excluding intra-company debt), beginning with a $100 million principal payment due April 2, 2018. Based on FES' current senior unsecured debt rating, capital structure and long-term cash flow projections, the debt maturities are unlikely to be refinanced. Although management continues to explore cost reductions and other options to improve cash flow, these obligations and their impact to liquidity raise substantial doubt about FES’ ability to meet its obligations as they come due over the next twelve months and, as such, its ability to continue as a going concern. Furthermore, the inability to obtain legislative support under the Department of Energy’s recent NOPR, which was rejected by FERC, limits FES’ strategic options to plant deactivations, restructuring its debt and other financial obligations with its creditors, and/or to seek protection under U.S. bankruptcy laws. In 2016, FirstEnergy satisfied its minimum required funding obligations of $382 million and addressed 2017 funding obligations to its qualified pension plan with total contributions of $882 million (of which $138 million was cash contributions from FES), including $500 million of FE common stock contributed to the qualified pension plan on December 13, 2016. In January 2018, FirstEnergy satisfied its minimum required funding obligations of $500 million and, as discussed above, addressed funding obligations for future years to its qualified pension plan with additional contributions of $750 million. FirstEnergy's capital expenditures for 2018 are expected to be approximately $2.6 billion to $2.9 billion, excluding CES. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency directives. 35 Capital expenditures for 2017 and anticipated expenditures for 2018 by reportable segment are included below: Reportable Segment 2017 Actual(1) 2017 Pension/ OPEB Mark- to-Market Capital Adjustment 2017 Actual Excluding Pension/OPEB Mark-to-Market Capital Costs (In millions) Regulated Distribution Regulated Transmission CES Corporate/Other Total $ $ 1,342 $ (20) $ 1,032 279 99 1 (1) — 1,362 1,031 280 99 2,752 $ (20) $ 2,772 $2,600 - $2,900 2018 Forecast(2) $1,500 - $1,600 1,000 - 1,200 — (3) 100 (1) Includes a decrease of approximately $20 million related to the capital component of the pension and OPEB mark-to-market adjustment. (2) Excludes the capital component for pension and OPEB mark-to-market adjustments, which cannot be estimated. (3) Planned capital expenditures will be dependent on the outcome of the strategic review of CES. Additionally, planned capital expenditures for Regulated Distribution includes $1.4 billion to $1.7 billion, annually, 2019 through 2021, while planned capital expenditures for Regulated Transmission are expected to be approximately $1.0 billion to $1.2 billion, annually, 2019 through 2021. Capital expenditures for 2017 and 2018 forecast by subsidiary are included in the following table. Operating Company 2017 Actual(1) 2017 Pension/ OPEB Mark- to-Market Capital Adjustment 2017 Actual Excluding Pension/OPEB Mark-to-Market Capital Costs (In millions) 2018 Forecast(2)(3) OE Penn CEI TE JCP&L ME PN MP PE WP ATSI TrAIL FES AE Supply MAIT Other subsidiaries Total $ 143 $ (12) $ 155 $ 55 134 37 317 142 162 269 112 199 541 45 250 34 242 70 (1) 4 (3) 3 (4) (12) 9 — (2) — — (3) 2 (1) — 56 130 40 314 146 174 260 112 201 541 45 253 32 243 70 $ 2,752 $ (20) $ 2,772 $ 160 45 145 50 380 185 195 280 150 260 375 55 — (4) — (4) 400 70 2,750 (1) Includes a decrease of approximately $20 million related to the capital component of the pension and OPEB mark-to-market adjustment. (2) Excludes the capital component for pension and OPEB mark-to-market adjustments, which cannot be estimated. (3) 2018 Forecast represents the mid-point of Regulated Distribution and Regulated Transmission's 2018 forecasted capital expenditures. (4) Planned capital expenditures will be dependent on the outcome of the strategic review of CES. FirstEnergy's strategy is to focus on investments in its regulated operations. The centerpiece of this strategy is the Energizing the Future transmission plan, pursuant to which FirstEnergy plans to invest $4.0 to $4.8 billion in capital investments from 2018 to 2021, with $4.4 billion in capital investment from 2014 through 2017 to upgrade FirstEnergy's transmission system. This program is focused on projects that enhance system performance, physical security and add operating flexibility and capacity starting with the ATSI system and moving east across FirstEnergy's service territory over time. In total, FirstEnergy has identified over $20 billion in 36 transmission investment opportunities across the 24,500 mile transmission system, making this a continuing platform for investment in the years beyond 2021. As of December 31, 2017, FirstEnergy’s and FES' net deficit in working capital (current assets less current liabilities) was due in large part to currently payable long-term debt. Currently payable long-term debt as of December 31, 2017, included the following: Currently Payable Long-Term Debt FirstEnergy FES Unsecured notes FMBs Secured PCRBs Unsecured PCRBs Sinking fund requirements Other notes $ (In millions) $ 150 325 141 374 61 31 $ 1,082 $ — — 141 374 — 9 524 Short-Term Borrowings / Revolving Credit Facilities FE and the Utilities and FET and its subsidiaries participate in two separate five-year syndicated revolving credit facilities with aggregate commitments of $5.0 billion (Facilities), which are available through December 6, 2021. FE and the Utilities and FET and its subsidiaries may use borrowings under their Facilities 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 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 Facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FirstEnergy had $300 million and $2,675 million of short-term borrowings as of December 31, 2017 and 2016, respectively. FirstEnergy’s available liquidity from external sources as of January 31, 2018 was as follows: Borrower(s) Type Maturity Commitment Available Liquidity FirstEnergy(1) FET(2) Revolving December 2021 $ 4,000 $ Revolving December 2021 1,000 (In millions) Subtotal $ 5,000 $ Cash — Total $ 5,000 $ 3,740 1,000 4,740 358 5,098 (1) (2) FE and the Utilities. Available liquidity includes impact of $10 million of LOCs issued under various terms. Includes FET, ATSI, MAIT and TrAIL. FES had $105 million and $101 million of short-term borrowings as of December 31, 2017 and December 31, 2016, respectively. Of such amounts, $102 million and $101 million, respectively, represents a currently outstanding promissory note due April 2, 2018, payable to AE Supply with any additional short-term borrowings representing borrowings under an unregulated companies' money pool, which also includes FE, FET, FEV and certain other unregulated subsidiaries of FE, but excludes FENOC, FES and its subsidiaries. In addition to FES' access to a separate unregulated companies' money pool, which includes FE, FES' subsidiaries and FENOC, FES' available liquidity as of January 31, 2018, was as follows: Type Commitment Available Liquidity (In millions) 500 $ — 500 $ 500 1 501 Two-year secured credit facility with FE $ Cash $ 37 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, 2018: 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 $ 4,000 $ — $ — 500 500 300 600 300 300 200 500 150 — 50 — — 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, other than the FET facility, which is based on its subsidiaries' credit ratings. 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, 2017, the borrowers were in compliance with the applicable debt-to-total-capitalization covenants, as well as in the case of FE, the minimum interest coverage ratio requirement, in each case as defined under the respective Facilities. Separately, in December 2016, FE and FES entered into a two-year secured credit facility in which FE provides a committed line of credit to FES of up to $500 million and additional credit support of up to $200 million to cover surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR and the Hatfield's Ferry disposal site, respectively. So long as FES remains in an unregulated companies' money pool, which includes FE, FES' subsidiaries and FENOC, the $500 million secured line of credit provides FES the needed liquidity in order for FES to, among other things, satisfy its nuclear support obligation to NG in the event of extraordinary circumstances with respect to its nuclear facilities. The new facility matures on December 31, 2018, and is secured by FMBs issued by FG ($250 million) and NG ($450 million). Additionally, FES maintains access to an unregulated companies' money pool, which includes FE, FES' subsidiaries and FENOC, and continues to conduct its ordinary course of business under that money pool in lieu of borrowing under the new facility. Term Loans As of December 31, 2017, FE had a $1.2 billion variable rate syndicated term loan and two separate $125 million term loans. On January 22, 2018, FE repaid these term loans in full using the proceeds from the $2.5 billion equity investment. 38 FirstEnergy Money Pools FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and the holding company 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 of FE participating in a money pool and FE (as a lender only), FENOC, FES and its subsidiaries participating in a similar money pool. FESC administers these money pools and tracks surplus funds of FirstEnergy 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 2017 was 1.48% per annum for the regulated companies’ money pool and 2.30% per annum for the unregulated companies’ money pools. As discussed above, FES currently maintains access to its unregulated companies' money pool in lieu of borrowing under its $500 million secured line of credit. FE expects to provide ongoing liquidity to FES within such unregulated companies' money pool through March 2018. As of December 31, 2017, FES, its subsidiaries, and FENOC had no borrowings in the aggregate under the unregulated companies' money pool. Long-Term Debt Capacity 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 January 31, 2018: Issuer FE FES AE Supply AGC ATSI CEI FET JCP&L ME MAIT MP OE PN Penn PE TE TrAIL WP Senior Secured Moody’s Fitch S&P — CCC+ BB — — — B3 — — — BBB+ Baa1 — — — — BBB+ BBB+ — — — BBB+ — BBB+ — — — — A3 A2 — A2 — Baa1 — A1 — — BB — — A- — — — — BBB+ A- — A- — A- — A- Senior Unsecured Moody’s Baa3 Ca B1 Baa3 Baa1 Baa3 Baa2 Baa2 A3 Baa1 — Baa1 Baa1 — — — A3 — Fitch BBB- C BB- BB BBB+ BBB+ BBB- BBB BBB+ BBB — BBB+ BBB+ — — — BBB+ — S&P BB+ C BB- BB- BBB- BBB- BB+ BBB- BBB- BBB- — BBB- BBB- — — — BBB- — Debt capacity is subject to the consolidated debt-to-total-capitalization limits in the credit facilities previously discussed. As of January 31, 2018, FE and its subsidiaries could issue additional debt of approximately $6.6 billion, or incur a $3.5 billion reduction to equity, and remain within the limitations of the financial covenants required by the FE Facility. 39 Changes in Cash Position As of December 31, 2017, FirstEnergy had $589 million of cash and cash equivalents compared to $199 million of cash and cash equivalents as of December 31, 2016. As of December 31, 2017 and 2016, FirstEnergy had approximately $54 million and $61 million, respectively, of restricted cash included in Other Current Assets on the Consolidated Balance Sheets. Cash Flows From Operating Activities FirstEnergy's most significant sources of cash are derived from electric service provided by its utility operating subsidiaries and the sales of energy and related products and services by its unregulated competitive subsidiaries. The most significant use of cash from operating activities is to buy electricity in the wholesale market and pay fuel suppliers, employees, tax authorities, lenders and others for a wide range of material and services. Net cash provided from operating activities was $3,808 million during 2017, $3,383 million during 2016 and $3,460 million during 2015. 2017 compared with 2016 Cash flows from operations increased $425 million in 2017 as compared with 2016. The year-over-year change in cash from operations increased due to the following: • • • • the absence of $382 million in cash contributions to the qualified pension plan in 2016; higher transmission revenue, reflecting recovery of incremental operating expenses, a higher rate base at ATSI and TrAIL, and the implementation of new rates at MAIT and JCP&L; higher distribution services retail receipts reflecting implementation of approved rates in Ohio, Pennsylvania and New Jersey, as further described above; partially offset by lower receipts from a decrease in capacity revenue and contract sales at CES. 2016 compared with 2015 Cash flows from operations decreased $77 million in 2016 compared with 2015 due to the following: • • • • a $239 million increase in cash contributions to the qualified pension plan, partially offset by higher distribution deliveries and the full year impact of net rate increases implemented in 2015 at certain Utilities; higher transmission revenue, reflecting recovery of incremental operating expenses and a higher rate base; lower disbursements for fuel and purchased power resulting from the lower sales volumes partially offset by lower capacity revenues at CES. 40 Cash Flows From Financing Activities In 2017, cash used for financing activities was $702 million compared to $34 million in 2016 and $292 million in 2015. The following table summarizes new debt financing, redemptions, repayments, short-term borrowings and dividends: Securities Issued or Redeemed / Repaid 2017 2016 2015 For the Years Ended December 31 New Issues Unsecured notes PCRBs FMBs Term loan Senior secured notes Redemptions / Repayments Unsecured notes PCRBs FMBs Term loan Senior secured notes Short-term borrowings (repayments), net Common stock dividend payments $ $ $ (In millions) $ 3,800 $ — $ — 625 250 — 471 305 1,200 — 475 339 295 200 2 $ 4,675 $ 1,976 $ 1,311 $ (1,330) $ (300) $ (158) (725) — (78) (483) (246) (1,200) (102) (2,291) $ (2,331) $ — (313) (215) (200) (151) (879) (2,375) $ 975 $ (91) (639) $ (611) $ (607) On March 1, 2017, FG retired $28 million of PCRBs at maturity. On March 15, 2017, MP retired $150 million of FMBs at maturity. On April 3, 2017, CEI retired $130 million of 5.70% senior notes at maturity. On May 16, 2017, MP issued $250 million of 3.55% FMBs due 2027. Proceeds received from the issuance of the FMBs were used: (i) to repay short-term borrowings, (ii) to fund capital expenditures and (iii) for working capital needs and other general business purposes. On June 1, 2017, FG repurchased approximately $130 million of PCRBs, which were subject to a mandatory put on such date. FG is currently holding these PCRBs indefinitely. On June 1, 2017, JCP&L retired $250 million of 5.65% senior notes at maturity. On June 21, 2017, FE issued the aggregate principal amount of $3.0 billion of its senior notes in three series: $500 million of 2.85% notes due 2022; $1.5 billion of 3.90% notes due 2027; and $1.0 billion of 4.85% notes due 2047. Proceeds from the issuance of the notes were used: (i) to redeem $650 million of FE's 2.75% notes due in 2018 on July 25, 2017, and (ii) for general corporate purposes, including the repayment of short-term borrowings under the FE Facility. On August 31, 2017, ATSI issued $150 million of 3.66% senior unsecured notes maturing in 2032. Proceeds from the issuance of the notes were used: (i) to repay short-term borrowings, (ii) to fund capital expenditures and (iii) for working capital needs and other general business purposes. On September 8, 2017, PN issued $300 million of 3.25% senior notes maturing in 2028. Proceeds from the issuance of the notes were used to repay short-term borrowings that were used to repay at maturity $300 million of PN's 6.05% senior notes due September 1, 2017. On September 15, 2017, WP issued $100 million of 4.09% FMBs due 2047. Proceeds from the issuance of the FMBs were used: (i) to repay short-term borrowings, (ii) to fund capital expenditures and (iii) for other general business purposes. 41 On October 5, 2017, CEI issued $350 million of 3.50% senior notes maturing in 2028. Proceeds from the issuance of the notes were used: (i) to refinance existing indebtedness, including $300 million of 7.88% FMBs due November 1, 2017, and borrowings outstanding under FirstEnergy's regulated utility money pool and the Facility, (ii) to fund capital expenditures and (iii) for working capital and other general business purposes. On December 15, 2017, WP issued $275 million of 4.14% FMBs maturing in 2047. Proceeds from the issuance of the FMBs were used to repay at maturity $275 million of WP's 5.95% FMBs due December 15, 2017. Cash Flows From Investing Activities Cash used for investing activities in 2017 principally represented cash used for property additions. The following table summarizes investing activities for 2017, 2016 and 2015: Cash Used for Investing Activities 2017 2016 2015 For the Years Ended December 31 Property Additions: Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/Other Nuclear fuel Proceeds from asset sales Investments Asset removal costs Other 2017 compared with 2016 (In millions) $ 1,191 $ 1,063 $ 1,030 1,101 317 49 254 (388) 98 172 (7) 619 52 232 (15) 111 145 (27) 1,040 1,020 588 56 190 (20) 114 142 (8) $ 2,716 $ 3,281 $ 3,122 Cash used for investing activity in 2017 decreased $565 million, as compared to 2016, primarily due to lower property additions. The decline in property additions was due to the following: • • • a decrease of $302 million at CES, resulting from lower capital investments associated with outages, MATS compliance and the Mansfield dewatering facility, a decrease of $71 million at Regulated Transmission due to timing of capital investments associated with its Energizing the Future investment program; partially offset by, an increase of $128 million at Regulated Distribution due to an increase in storm restoration work and smart meter investments in Pennsylvania. 2016 compared with 2015 Cash used for investing activity in 2016 increased $159 million, as compared to 2015, primarily due to increases in nuclear fuel purchases and property additions. Property additions increased primarily due to higher transmission investment and CES' purchase of the remaining non-affiliated leasehold interest in Perry Unit 1. The increase in nuclear fuel was due to the scheduled Davis-Besse refueling and maintenance outage in 2016. 42 CONTRACTUAL OBLIGATIONS As of December 31, 2017, FirstEnergy's estimated cash payments under existing contractual obligations that it considers firm obligations are as follows: Contractual Obligations Total 2018 2019-2020 2021-2022 Thereafter Long-term debt(1) Short-term borrowings Interest on long-term debt(2) Operating leases(3) Capital leases(3) Fuel and purchased power(4) Capital expenditures (5) Pension funding(6) Total (In millions) $ 22,266 $ 1,051 $ 2,548 $ 3,460 $ 15,207 300 13,972 1,874 117 9,110 1,778 2,217 300 1,081 146 28 1,260 558 1,250 — 1,951 230 41 1,956 625 — — 1,773 235 28 1,395 595 460 — 9,167 1,263 20 4,499 — 507 $ 51,634 $ 5,674 $ 7,351 $ 7,946 $ 30,663 Interest on variable-rate debt based on rates as of December 31, 2017. (1) Excludes unamortized discounts and premiums, fair value accounting adjustments and capital leases. (2) (3) See Note 7, "Leases," of the Combined Notes to Consolidated Financial Statements. (4) Amounts under contract with fixed or minimum quantities based on estimated annual requirements. (5) Amounts represent committed capital expenditures as of December 31, 2017. (6) In January 2018, FirstEnergy satisfied its minimum required funding obligations of $500 million and addressed funding obligations through 2020 to its qualified pension plan with additional contributions of $750 million. The impact of the contributions is reflected in the table above. 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 $2.8 billion in 2018, of which $300 million are expected to relate to the Utilities' contracts with FES. The table above also excludes regulatory liabilities (see Note 15, "Regulatory Matters"), AROs (see Note 14, "Asset Retirement Obligations"), reserves for litigation, injuries and damages, environmental remediation, and annual insurance premiums, including nuclear insurance (see Note 16, "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 The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $13.4 billion (assuming 102 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $450 million; and (ii) $13.0 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $127 million (but not more than $19 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s and NG's maximum potential assessment under these provisions would be $509 million per incident but not more than $76 million in any one year for each incident. In addition to the public liability insurance provided pursuant to the Price-Anderson Act, NG purchases insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. NG is a Member Insured of NEIL, which provides coverage for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. NG, as the Member Insured and each entity with an insurable interest, purchases policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $1.4 billion for replacement power costs incurred during an outage after an initial 12-week waiting period. NG, as the Member Insured and each entity with an insurable interest, is insured under property damage insurance provided by NEIL. Under these arrangements, up to $2.75 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. Member Insureds of NEIL pay annual premiums and are subject to retrospective premium assessments if losses exceed the accumulated funds available to the insurer. NG purchases insurance through NEIL that will pay its obligation in the event a retrospective premium call is made by NEIL, subject to the terms of the policy. FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs 43 arising from a nuclear incident at any of NG'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 FirstEnergy’s insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs. The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.06 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds. 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. The maximum potential amount of future payments FirstEnergy and its subsidiaries could be required to make under these guarantees as of December 31, 2017, was approximately $3.8 billion, as summarized below: Guarantees and Other Assurances FE's Guarantees on Behalf of its Subsidiaries Energy and Energy-Related Contracts(1) Deferred compensation arrangements(2) AE Supply asset sales(3) Fuel-Related(4) Other(5) Subsidiaries’ Guarantees Energy and Energy-Related Contracts(6) FES’ guarantee of FG’s sale and leaseback obligations FE's Guarantees on Behalf of Business Ventures Global Holding Facility Other Assurances Surety Bonds - Wholly Owned Subsidiaries Surety Bonds(7),(8) Sale leaseback indemnity LOCs(9) Total Guarantees and Other Assurances Maximum Exposure (In millions) $ 7 592 555 72 4 1,230 265 1,574 1,839 275 128 263 58 10 459 3,803 $ Issued for open-ended terms, with a 10-day termination right by FirstEnergy. (1) (2) CES related portion is $149 million, including $58 million and $91 million at FES and FENOC, respectively. (3) As a condition to closing the sale of the natural gas generating plants, FE provided the purchaser two limited three-year guarantees totaling (4) (5) (6) (7) (8) (9) $555 million of certain obligations of AE Supply and AGC arising under the amended and restated purchase agreement. FE is the guarantor of the remaining payments due to CSX/BNSF in connection with the definitive settlement on a transportation agreement. Includes guarantees of $4 million for various leases. Includes energy and energy-related contracts associated with FES. 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 and the Hatfield's Ferry disposal site, respectively. FE provides credit support for $23 million of surety bonds held by AE Supply. Includes $10 million issued for various terms pursuant to LOC capacity available under FirstEnergy's revolving credit facilities. 44 FES' debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each of FG and NG. Accordingly, present and future holders of indebtedness of FES, FG and NG would have claims against each of FES, FG and NG, regardless of whether their primary obligor is FES, FG or NG. 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 CES' power portfolio exposure as of December 31, 2017, FES has posted collateral of $123 million and AE Supply has posted collateral of $4 million. The Regulated Distribution Segment has posted collateral of $4 million. 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, 2017: Potential Collateral Obligations FES AE Supply Regulated FE Corp Total (In millions) Contractual Obligations for Additional Collateral At Current Credit Rating Upon Further Downgrade Surety Bonds (Collateralized Amount)(1) Total Exposure from Contractual Obligations $ $ 4 $ — 16 20 $ 1 — 1 2 $ $ — $ — $ 41 107 148 $ — 237 237 $ 5 41 361 407 (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 and the Hatfield's Ferry disposal site, respectively. Excluded from the preceding table are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment. As of December 31, 2017, FES has $2 million of collateral posted with its affiliates. Other Commitments and Contingencies FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding's outstanding principal balance is $275 million. 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. OFF-BALANCE SHEET ARRANGEMENTS FES has obligations that are not included on its Consolidated Balance Sheet related to the 2007 Bruce Mansfield Unit 1 sale and leaseback arrangements (expiring in 2040), which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, was $862 million as of December 31, 2017. As of December 31, 2017, FES' leasehold interest was 93.83% of Bruce Mansfield Unit 1. On June 1, 2017, NG completed the purchase of the 2.60% lessor equity interests of the remaining non-affiliated leasehold interests in Beaver Valley Unit 2 for $38 million. In addition, the Beaver Valley Unit 2 leases expired in accordance with their terms on June 1, 2017, resulting in NG being the sole owner of Beaver Valley Unit 2. 45 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 is exposed to financial risks resulting from fluctuating commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy's 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 uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 10, "Fair Value Measurements," of the Combined Notes to Consolidated Financial Statements). Sources of information for the valuation of net commodity derivative assets and liabilities as of December 31, 2017, are summarized by year in the following table: Source of Information- Fair Value by Contract Year 2018 2019 2020 2021 2022 Thereafter Total (In millions) Other external sources(1) Prices based on models Total(2) $ $ (25) $ (35) $ (11) $ — $ — $ — $ 1 — — — — — (24) $ (35) $ (11) $ — $ — $ — $ (71) 1 (70) (1) Primarily represents contracts based on broker and ICE quotes. (2) Includes $(79) 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 changes in market values do not impact earnings. FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts as of December 31, 2017, not subject to regulatory accounting, an increase in commodity prices of 10% would decrease net income by approximately $6 million during the next twelve months. Equity Price Risk NDT funds have been established to satisfy NG’s and other FirstEnergy subsidiaries' nuclear decommissioning obligations. As of December 31, 2017, approximately 55% of the funds were invested in fixed income securities, 41% of the funds were invested in equity securities and 4% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $1,491 million, $1,104 million and $90 million for fixed income securities, equity securities and short-term investments, respectively, as of December 31, 2017, excluding $(7) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $110 million reduction in fair value as of December 31, 2017. Certain FirstEnergy subsidiaries recognize in earnings the unrealized losses on AFS securities held in its NDT as OTTI. A decline in the value of FirstEnergy’s NDT funds or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2017, FirstEnergy made no contributions to the NDTs. 46 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. As discussed in Note 7, "Leases," of the Combined Notes to Consolidated Financial Statements, FirstEnergy’s investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk. Comparison of Carrying Value to Fair Value Year of Maturity 2018 2019 2020 2021 2022 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(1) Average interest rate $ $ $ — $ —% — $ —% — $ —% — $ —% — $ 1,738 —% 3.3% $ 1,738 $ 1,738 3.3% 679 6.8% — $ —% $ 1,035 $ $ 541 5.5% 250 2.4% $ 490 5.7% $ 1,200 $ 2.4% 6.5% 9 1.1% $ 1,100 $ 16,957 $ 20,802 $21,579 4.1% — $ —% 5.0% 4.9% — $ 1,459 —% 2.4% $ 1,459 (1) As of December 31, 2017, FE had a $1.2 billion variable rate syndicated term loan and two separate $125 million term loans. On January 22, 2018, FE repaid these term loans in full using the proceeds from the $2.5 billion equity investment. CREDIT RISK Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. FirstEnergy evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. FirstEnergy may impose specific collateral requirements and use standardized agreements that facilitate the netting of cash flows. FirstEnergy monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk. Wholesale Credit Risk FirstEnergy measures wholesale credit risk as the replacement cost for derivatives in power, natural gas, coal and emission allowances, adjusted for amounts owed to, or due from, counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where FirstEnergy has a legally enforceable right of offset. FirstEnergy monitors and manages the credit risk of wholesale marketing, risk management and energy transacting operations through credit policies and procedures, which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral and the use of master netting agreements. The majority of FirstEnergy's energy contract counterparties maintain investment-grade credit ratings. Retail Credit Risk FirstEnergy's principal retail credit risk exposure relates to its competitive electricity activities, which serve residential, commercial and industrial companies. Retail credit risk results when customers default on contractual obligations or fail to pay for service rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers. Retail credit risk is managed through established credit approval policies, monitoring customer exposures and the use of credit mitigation measures such as deposits in the form of LOCs, cash or prepayment arrangements. Retail credit quality is affected by the economy and the ability of customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, FirstEnergy's retail credit risk may be adversely impacted. 47 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 Ohio by the PUCO, in New Jersey by the NJBPU, 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. As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates. In addition, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility. Following the adoption of the Tax Act, various state regulatory proceedings have been initiated to investigate the impact of the Tax Act on the Utilities’ rates and charges. State proceedings which have arisen are discussed below. The Utilities continue to monitor and investigate the impact of state regulatory impacts resulting from the Tax Act. MARYLAND PE 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 Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption and demand and requiring each electric utility to file a plan every three years. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the goal of 0.97% savings achieved under PE's current plan for 2016, and increasing 0.2% per year thereafter to reach 2%. The Maryland legislature in April 2017 adopted a statute requiring the same 0.2% per year increase, 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. The costs of PE's 2015-2017 plan approved by the MDPSC in December 2014 were approximately $60 million. PE filed its 2018-2020 EmPOWER Maryland plan on August 31, 2017. The 2018-2020 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. On December 22, 2017, the MDPSC issued an order approving the 2018-2020 plan with various modifications. 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 February 27, 2013, the MDPSC issued an order requiring the Maryland electric utilities to submit analyses relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations. PE's responsive filings discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 2013 Order, and projected that it would require approximately $2.7 billion in infrastructure investments over 15 years to attempt to achieve the quickest level of response for the largest storm projected in the February 2013 Order. On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting, as well as the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that the Maryland utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not issued a ruling on any of those matters. On September 26, 2016, the MDPSC initiated a new 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. Comments were filed and a hearing was held in late 2016. On January 31, 2017, the MDPSC issued a notice establishing five working groups to address these issues over the following eighteen months, and also directed the retention of an outside consultant to prepare a report on costs and benefits of distributed solar generation in Maryland. 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. If approved, PE will launch an electric vehicle charging infrastructure program on January 1, 2019, offering up to 2,000 rebates for electric vehicle charging equipment to residential customers, and deploying up to 259 chargers at non-residential customer service locations at a projected total cost of $12 million. PE is proposing to recover program costs subject to a five-year amortization. On February 6, 2018, the MDPSC opened a new proceeding to consider the petition and directed that comments be filed by March 16, 2018. 48 On January 12, 2018, the MDPSC instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of Maryland utilities. PE must track and apply regulatory accounting treatment for the impacts beginning January 1, 2018, and submitted a report to the MDPSC on February 15, 2018, estimating that the Tax Act impacts would be approximately $7 million to $8 million annually for PE’s customers and proposed to file a base rate case in the third quarter of 2018 where the benefits from the effects of the Tax Act will be realized by customers through a lower rate increase than would otherwise be necessary. NEW JERSEY JCP&L currently 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. The supply for BGS is comprised of two components, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers. The second BGS component provides a fixed price service and is intended for smaller commercial and residential customers. 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. JCP&L currently operates under rates that were approved by the NJBPU on December 12, 2016, effective as of January 1, 2017. These rates provide an annual increase in operating revenues of approximately $80 million from those previously in place and are intended to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses. In addition, on January 25, 2017, the NJBPU approved the acceleration of the amortization of JCP&L’s 2012 major storm expenses that are recovered through the SRC in order for JCP&L to achieve full recovery by December 31, 2019. Pursuant to the NJBPU's March 26, 2015 final order in JCP&L's 2012 rate case proceeding directing that certain studies be completed, on July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which included operational and financial components. The independent consultant conducting the review issued a final report on July 27, 2016, recognizing that JCP&L is meeting the NJBPU requirements and making various operational and financial recommendations. The NJBPU issued an Order on August 24, 2016, that accepted the independent consultant’s final report and directed JCP&L, the Division of Rate Counsel and other interested parties to address the recommendations. In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases, the NJBPU stated that it would continue to apply its current CTA policy in base rate cases, subject to incorporating the following modifications: (i) calculating savings using a five-year look back from the beginning of the test year; (ii) allocating savings with 75% retained by the company and 25% allocated to rate payers; and (iii) excluding transmission assets of electric distribution companies in the savings calculation. On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the generic CTA proceeding to the Superior Court of New Jersey Appellate Division and JCP&L filed to participate as a respondent in that proceeding supporting the order. On September 18, 2017, the Superior Court of New Jersey Appellate Division reversed the NJBPU's Order on the basis that the NJBPU's modification of its CTA methodology did not comply with the procedures of the NJAPA. JCP&L's existing rates are not expected to be impacted by this order. On December 19, 2017, the NJBPU approved the issuance of proposed rules to modify the CTA methodology consistent with its October 22, 2014 Generic Order. The proposed rule was published in the NJ Register on January 16, 2018, and was republished on February 6, 2018, to correct an error. Interested parties have sixty days to comment on the proposed rulemaking. At the December 19, 2017 NJBPU public meeting, 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. JCP&L expects to make a filing in 2018. 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. JCP&L must track and apply regulatory accounting treatment for the impacts effective January 1, 2018, and file a petition with the NJBPU by March 2, 2018, regarding the expected impacts of the Tax Act on JCP&L’s expenses and revenues and how the effects will be passed through to its customers. OHIO The Ohio Companies currently operate under ESP IV which commenced June 1, 2016 and expires May 31, 2024. The material terms of ESP IV, as approved in the PUCO’s Opinion and Order issued on March 31, 2016 and Fifth Entry on Rehearing on October 12, 2016, include Rider DMR, which provides for the Ohio Companies to collect $132.5 million annually for three years, with the possibility of a two-year extension. Rider DMR will be grossed up for federal income taxes, resulting in an approved amount of approximately $204 million annually. Revenues from Rider DMR will be excluded from the significantly excessive earnings test for the initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension. The PUCO set three conditions for continued recovery under Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO. ESP IV also continues a base distribution rate freeze through May 31, 2024. In addition, ESP IV continues the supply of power to non-shopping customers at a market-based price set through an auction process. 49 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 $30 million per year from June 1, 2016 through May 31, 2019; $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. Other material terms of ESP IV include: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (2) an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016, and remains pending); (3) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; (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; and (5) an agreement to file an application to transition to a straight fixed variable cost recovery mechanism for residential customers' base distribution rates (which filing was made on April 3, 2017, and remains pending). Several parties, including the Ohio Companies, filed applications for rehearing regarding the Ohio Companies’ ESP IV with the PUCO. The Ohio Companies’ application for rehearing challenged, among other things, the PUCO’s failure to adopt the Ohio Companies’ suggested modifications to Rider DMR. The Ohio Companies had previously suggested that a properly designed Rider DMR would be valued at $558 million annually for eight years, and include an additional amount that recognizes the value of the economic impact of FirstEnergy maintaining its headquarters in Ohio. Other parties’ applications for rehearing argued, among other things, that the PUCO’s adoption of Rider DMR is not supported by law or sufficient evidence. On August 16, 2017, the PUCO denied all remaining intervenor applications for rehearing, denied the Ohio Companies’ challenges to the modifications to Rider DMR and added a third-party monitor to ensure that Rider DMR funds are spent appropriately. On September 15, 2017, the Ohio Companies filed an application for rehearing of the PUCO’s August 16, 2017 ruling on the issues of the third-party monitor and the ROE calculation for advanced metering infrastructure. On October 11, 2017, the PUCO denied the Ohio Companies' application for rehearing on both issues. On October 16, 2017, the Sierra Club and the Ohio Manufacturer's Association Energy Group filed notices of appeal with the Supreme Court of Ohio appealing various PUCO entries on their applications for rehearing. On November 16, 2017, the Ohio Companies intervened in the appeal. Additional parties subsequently filed notices of appeal with the Supreme Court of Ohio challenging various PUCO entries on their applications for rehearing. For additional information, see “FERC Matters - Ohio ESP IV PPA,” below. Under ORC 4928.66, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. Starting in 2017, ORC 4928.66 requires the energy savings benchmark to increase by 1% and the peak demand reduction benchmark to increase by 0.75% annually thereafter through 2020 and the energy savings benchmark to increase by 2% annually from 2021 through 2027, with a cumulative benchmark of 22.2% by 2027. On April 15, 2016, the Ohio Companies filed an application for approval of their three-year energy efficiency portfolio plans for the period from January 1, 2017 through December 31, 2019. The plans as proposed comply with benchmarks contemplated by ORC 4928.66 and provisions of the ESP IV, and include a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities. On December 9, 2016, the Ohio Companies filed a Stipulation and Recommendation with several parties that contained changes to the plan and a decrease in the plan costs. The Ohio Companies anticipate the cost of the plans will be approximately $268 million over the life of the portfolio plans 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 filed Stipulation and Recommendation 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 as reported on FERC Form 1. On December 21, 2017, the Ohio Companies filed an application for rehearing challenging the PUCO’s modification of the Stipulation and Recommendation to include the 4% cost cap, which was denied by the PUCO on January 10, 2018. Ohio law requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage amount through 2026, except that in 2014 SB310 froze 2015 and 2016 requirements at the 2014 level (2.5%), pushing back scheduled increases, which resumed in 2017 (3.5%), and increases 1% each year through 2026 (to 12.5%) and shall remain at 12.5% in 2027 and each year thereafter. The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements. In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs. The PUCO issued an Opinion and Order on August 7, 2013, approving the Ohio Companies' acquisition process and their purchases of RECs to meet statutory mandates in all instances except for certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of $43.4 million, plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent. On December 24, 2013, following the denial of their application for rehearing, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted. The OCC and the ELPC also filed appeals of the PUCO's order. On January 24, 2018, the Supreme Court of Ohio reversed the PUCO order finding that the order violated the rule against prohibiting retroactive ratemaking. On February 5, 2018, the OCC and ELPC filed a motion for reconsideration, to which the Ohio Companies responded in opposition on February 15, 2018. On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for 50 Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers. On January 13, 2016, the PUCO granted reconsideration for further consideration of the matters specified in the applications for rehearing. On March 29, 2017, the PUCO issued a Second Entry on Rehearing that granted, in part, the applications for rehearing filed by FES and other parties, finding that the PUCO’s guidelines regarding fixed-price contracts should not apply to large mercantile customers. This finding changes the original order, which applied the guidelines to all customers, including mercantile customers. The PUCO also reaffirmed several provisions of the original order, including that the fixed-price guidelines only apply on a going-forward basis and not to existing contracts and that regulatory-out clauses in contracts are permissible. On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan. The DPM Plan is a portfolio of approximately $450 million in 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. The Ohio Companies have requested that the PUCO issue an order approving the DPM Plan and associated cost recovery no later than May 2, 2018, so that the Ohio Companies can expeditiously commence the DPM Plan and customers can begin to realize the associated benefits. On January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act and determine the appropriate course of action to pass benefits on to customers. The Ohio Companies must establish a regulatory liability, effective January 1, 2018, for the estimated reduction in federal income tax resulting from the Tax Act, and filed comments on February 15, 2018, explaining that customers will save nearly $40 million annually as a result of updating tariff riders for the tax rate changes and that the Ohio Companies’ base distribution rates are not impacted by the Tax Act changes because they are frozen through May 2024. PENNSYLVANIA The Pennsylvania Companies operate under DSPs for the June 1, 2017 through May 31, 2019 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 DSPs, the supply will be provided by wholesale suppliers through a mix of 12 and 24-month energy contracts, as well as one RFP for 2-year SREC contracts for ME, PN and Penn. The DSPs include modifications to the Pennsylvania Companies’ POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges. On December 11, 2017, the Pennsylvania Companies filed DSPs for the June 1, 2019 through May 31, 2023 delivery period. Under the 2019-2023 DSPs, the supply is proposed to 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 as proposed also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program term. The 2019-2023 DSPs also introduce a retail market enhancement rate mechanism designed to stimulate residential customer shopping, and modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW. A hearing has been scheduled for April 10-11, 2018, and the PPUC is expected to issue a final order on these DSPs by mid-September 2018. The Pennsylvania Companies operate under rates that were approved by the PPUC on January 19, 2017, effective as of January 27, 2017. These rates provide annual increases in operating revenues of approximately $96 million at ME, $100 million at PN, $29 million at Penn, and $66 million at WP, and are intended to benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements. Pursuant to Pennsylvania's EE&C legislation in Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at 1.8% for ME, 1.7% for Penn, 1.8% for WP, and 0% for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at 4.0% for ME, 3.9% for PN, 3.3% for Penn, and 2.6% for WP. 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. Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. Pennsylvania EDCs must file LTIIPs outlining infrastructure improvement plans for PPUC review and approval prior to approval of a DSIC. On February 11, 2016, the PPUC approved LTIIPs for each of the Pennsylvania Companies. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. The LTIIPs estimated costs for the remaining period of 2018 to 2020, as modified, are: WP $50.1 million; PN $44.8 million; Penn $33.2 million; and ME $51.3 million. On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery, which were approved by the PPUC on June 9, 2016, and went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. On January 19, 2017, in the PPUC’s order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On 51 February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016, which is pending PPUC approval. The ADIT issue is subject to further litigation and a hearing was held on May 12, 2017. On August 31, 2017, the ALJ issued a decision recommending that the complaint of the Pennsylvania OCA be granted by the PPUC such that the Pennsylvania Companies reflect all federal and state income tax deductions related to DSIC-eligible property in the currently effective DSIC rates. If the decision is approved by the PPUC, the impact is not expected to be material to FirstEnergy. The Pennsylvania Companies filed exceptions to the decision on September 20, 2017, and reply exceptions on October 2, 2017. On February 12, 2018, the PPUC initiated a proceeding to determine the effects of the Tax Act on the tax liability of utilities and the feasibility of reflecting such impacts in rates charged to customers. By March 9, 2018, the Pennsylvania Companies must submit information to the PPUC to calculate the net effect of the Tax Act on income tax expense and rate base, and comments addressing whether rates should be adjusted to reflect the tax rate changes, and if so, how and when such modifications should take effect. WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP's and PE's ENEC rate is updated annually. On September 23, 2016, the WVPSC approved the Phase II energy efficiency program for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, which includes three energy efficiency programs to meet the Phase II requirement of energy efficiency reductions of 0.5% of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, which was approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of Harrison Power Station to MP. The costs for the Phase II program are expected to be $10.4 million and are eligible for recovery through the existing energy efficiency rider which is reviewed in the fuel (ENEC) case each year. On December 15, 2017, the WVPSC approved MP's and PE's proposed annual decrease in their EE&C rates, effective January 1, 2018, which is not material to FirstEnergy. On December 9, 2016, the WVPSC approved the annual ENEC case for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, resulting in an increase in the ENEC rate of $25 million annually beginning January 1, 2017. In addition, ENEC rates will be maintained at the same level for a two year period. On December 30, 2015, MP and PE filed an IRP with the WVPSC identifying a capacity shortfall starting in 2016 and exceeding 700 MWs by 2020 and 850 MWs by 2027. On June 3, 2016, the WVPSC accepted the IRP. On December 16, 2016, MP issued an RFP to address its generation shortfall, along with issuing a second RFP to sell its interest in Bath County. Bids were received by an independent evaluator in February 2017 for both RFPs. AE Supply was the winning bidder of the RFP to address MP’s generation shortfall and on March 6, 2017, MP and AE Supply signed an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station (1,300 MWs) for approximately $195 million, subject to customary and other closing conditions, including regulatory approvals. In addition, on March 7, 2017, MP and PE filed an application with the WVPSC and MP and AE Supply filed an application with FERC requesting authorization for such purchase. Various intervenors filed protests challenging the RFP and requesting FERC deny the application, set it for hearing to allow discovery into the RFP process, or delay an order pending the conclusion of the WVPSC proceeding. On January 12, 2018, FERC issued an order denying authorization for the transaction, holding that MP and AE Supply did not demonstrate that the sale was consistent with the public interest and the transaction did not fall within the safe harbors for meeting FERC’s affiliate cross-subsidization analysis. In the order FERC also revised and clarified certain details of its standards for the review of transactions resulting from competitive solicitations, and concluded that MP’s RFP did not meet the revised and clarified standards. FERC allowed that MP may submit a future application for a transaction resulting from a new RFP. The WVPSC issued its order on January 26, 2018, denying the petition as filed but granting the transfer of Pleasants Power Station under certain conditions, which included MP assuming significant commodity risk. MP, PE and AE Supply have determined not to seek rehearing at FERC in light of the adverse decisions at FERC and the WVPSC. Based on the FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement. With respect to the Bath County RFP, MP does not plan to move forward with that sale of its ownership interest. In the future, MP may re-evaluate its options with respect to its interest in Bath County. On September 1, 2017, MP and PE filed with the WVPSC for a reconciliation of their VMS to confirm that rate recovery matches VMP costs and for a regular review of that program. MP and PE proposed a $15 million annual decrease in VMS rates effective January 1, 2018, and an additional $15 million decrease in rates for 2019. This is an overall decrease in total revenue and average rates of 1%. On December 15, 2017, the WVPSC issued an order adopting a unanimous settlement without modification. On January 3, 2018, the WVPSC initiated a proceeding to investigate the effects of the Tax Act on the revenue requirements of utilities. MP and PE must track the tax savings resulting from the Tax Act on a monthly basis, effective January 1, 2018, and file written testimony explaining the impact of the Tax Act on federal income tax and revenue requirements by May 30, 2018. On January 26, 2018, the WVPSC issued an order clarifying that regulatory accounting should be implemented as of January 1, 2018, including the recording of any regulatory liabilities resulting from the Tax Act. 52 RELIABILITY MATTERS Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES and certain of its subsidiaries, AE Supply, FENOC, ATSI, MAIT and TrAIL. 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 eight regional entities, including RFC. All of FirstEnergy's facilities 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, including FES, believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy, including FES, 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, including FES, 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, including FES, part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, and obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations and cash flows. FERC MATTERS Ohio ESP IV PPA On August 4, 2014, the Ohio Companies filed an application with the PUCO seeking approval of their ESP IV. ESP IV included a proposed Rider RRS, which would flow through to customers either charges or credits representing the net result of the price paid to FES through an eight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, against the revenues received from selling such output into the PJM markets. The Ohio Companies entered into stipulations which modified ESP IV, and on March 31, 2016, the PUCO issued an Opinion and Order adopting and approving the Ohio Companies’ stipulated ESP IV with modifications. FES and the Ohio Companies entered into the ESP IV PPA on April 1, 2016, but subsequently agreed to suspend it and advised FERC of this course of action. On March 21, 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in the PJM capacity markets by state-subsidized generation, in particular alleged price suppression that could result from the ESP IV PPA and other similar agreements. The complaint requested that FERC direct PJM to initiate a stakeholder process to develop a long-term MOPR reform for existing resources that receive out-of-market revenue. On January 9, 2017, the generation owners filed to amend their complaint to include challenges to certain legislation and regulatory programs in Illinois. On January 24, 2017, FESC, acting on behalf of its affected affiliates and along with other utility companies, filed a motion to dismiss the amended complaint for various reasons, including that the ESP IV PPA matter is now moot. In addition, on January 30, 2017, FESC along with other utility companies filed a substantive protest to the amended complaint, demonstrating that the question of the proper role for state participation in generation development should be addressed in the PJM stakeholder process. On August 30, 2017, the generation owners requested expedited action by FERC. This proceeding remains pending before FERC. PJM Transmission Rates PJM and its stakeholders have been debating the proper method to allocate costs for certain transmission facilities. While FirstEnergy and other parties advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM. This question has been the subject of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit. On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines. The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole. The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings. On June 15, 2016, various parties, including ATSI and the Utilities, filed a settlement agreement at FERC agreeing to apply a combined usage based/socialization approach to cost allocation for charges to transmission customers in the PJM Region for transmission projects operating at or above 500 kV. Certain other parties in the proceeding did not agree to the settlement and filed protests to the settlement seeking, among other issues, to strike certain of the evidence advanced by FirstEnergy and certain of the other settling parties in support of the settlement, as well as provided further comments in opposition to the settlement. FirstEnergy and certain of the other parties responded to such opposition. On October 20, 2017, the settling and non-opposing parties requested expedited action by FERC. The settlement is pending before FERC. 53 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. On March 17, 2016, FERC denied FirstEnergy's request for rehearing of FERC's earlier order rejecting the settlement agreement and affirmed its prior ruling that ATSI must submit the cost/benefit analysis. Separately, ATSI resolved a dispute regarding responsibility for certain costs for the “Michigan Thumb” transmission project. Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings before FERC and certain U.S. appellate courts. On October 29, 2015, FERC issued an order finding that ATSI and the ATSI zone do not have to pay MISO MVP charges for the Michigan Thumb transmission project. MISO and the MISO TOs filed a request for rehearing, which FERC denied on May 19, 2016. The MISO TOs subsequently filed an appeal of FERC's orders with the Sixth Circuit. FirstEnergy intervened and participated in the proceedings on behalf of ATSI, the Ohio Companies and Penn. On June 21, 2017, the Sixth Circuit issued its decision denying the MISO TOs' appeal request. MISO and the MISO TOs did not seek review by the U.S. Supreme Court, effectively resolving the dispute over the "Michigan Thumb" transmission project. On a related issue, FirstEnergy joined certain other PJM TOs in a protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region. On July 13, 2016, FERC issued its order finding it appropriate for MISO to assess an MVP usage charge for transmission exports from MISO to PJM. Various parties, including FirstEnergy and the PJM TOs, requested rehearing or clarification of FERC’s order. The requests for rehearing remain pending before FERC. In addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM approved before ATSI joined PJM could be charged to transmission customers in the ATSI zone. The amount to be paid, and the question of derived benefits, is pending before FERC as a result of the Seventh Circuit's June 25, 2014 order described above under "PJM Transmission Rates." The outcome of the proceedings that address the remaining open issues related to MVP costs and "legacy RTEP" transmission projects cannot be predicted at this time. Transfer of Transmission Assets to MAIT Following receipt of necessary regulatory approvals, on January 31, 2017, MAIT issued membership interests to FET, PN and ME in exchange for their respective cash and transmission asset contributions. MAIT, a transmission-only subsidiary of FET, owns and operates all of the FERC-jurisdictional transmission assets previously owned by ME and PN. Subsequently, on March 13, 2017, FERC issued an order authorizing MAIT to issue short- and long-term debt securities, permitting MAIT to participate in the FirstEnergy regulated companies’ money pool for working capital, to fund day-to-day operations, support capital investment and establish an actual capital structure for ratemaking purposes. MAIT Transmission Formula Rate On October 28, 2016, as amended on January 10, 2017, MAIT submitted an application to FERC requesting authorization to implement a forward-looking formula transmission rate to recover and earn a return on transmission assets effective February 1, 2017. Various intervenors submitted protests of the proposed MAIT formula rate. Among other things, the protest asked FERC to suspend the proposed effective date for the formula rate until June 1, 2017. On March 10, 2017, FERC issued an order accepting the MAIT formula transmission rate for filing, suspending the formula transmission rate for five months to become effective July 1, 2017, and establishing hearing and settlement judge procedures. On April 10, 2017, MAIT requested rehearing of FERC’s decision to suspend the effective date of the formula rate. FERC's order on rehearing remains pending. MAIT’s rates went into effect on July 1, 2017, subject to refund pending the outcome of the hearing and settlement procedures. On October 13, 2017, MAIT and certain parties filed a settlement agreement with FERC. The settlement agreement provides for certain changes to MAIT's formula rate, changes MAIT's ROE from 11% to 10.3%, sets the recovery amount for certain regulatory assets, and establishes that MAIT's capital structure will not exceed 60% equity over the period ending December 31, 2021. The settlement agreement further provides that the ROE and the 60% cap on the equity component of MAIT's capital structure will remain in effect unless changed pursuant to section 205 or 206 of the FPA provided the effective date for any change shall be no earlier than January 1, 2022. The settlement agreement currently is pending at FERC. As a result of the settlement agreement, MAIT recognized a pre-tax impairment charge of $13 million in the third quarter of 2017. JCP&L Transmission Formula Rate On October 28, 2016, after withdrawing its request to the NJBPU to transfer its transmission assets to MAIT, JCP&L submitted an application to FERC requesting authorization to implement a forward-looking formula transmission rate to recover and earn a return on transmission assets effective January 1, 2017. A group of intervenors, including the NJBPU and New Jersey Division of Rate Counsel, filed a protest of the proposed JCP&L transmission rate. Among other things, the protest asked FERC to suspend the 54 proposed effective date for the formula rate until June 1, 2017. On March 10, 2017, FERC issued an order accepting the JCP&L formula transmission rate for filing, suspending the transmission rate for five months to become effective June 1, 2017, and establishing hearing and settlement judge procedures. On April 10, 2017, JCP&L requested rehearing of FERC’s decision to suspend the effective date of the formula rate. FERC's order on rehearing remains pending. JCP&L’s rates went into effect on June 1, 2017, subject to refund pending the outcome of the hearing and settlement procedures. On December 21, 2017, JCP&L and certain parties filed a settlement agreement with FERC. The settlement agreement provides for a $135 million stated annual revenue requirement for Network Integration Transmission Service and an average of $20 million stated annual revenue requirement for certain projects listed on the PJM Tariff where the costs are allocated in part beyond the JCP&L transmission zone within the PJM Region. The revenue requirements are subject to a moratorium on additional revenue requirements proceedings through December 31, 2019, other than limited filings to seek recovery for certain additional costs. Also on December 21, 2017, JCP&L filed a motion for authorization to implement the settlement rate on an interim basis. On December 27, 2017, FERC granted the motion authorizing JCP&L to implement the settlement rate effective January 1, 2018, pending a final commission order on the settlement agreement. The settlement agreement is pending at FERC. As a result of the settlement agreement, JCP&L recognized a pre-tax impairment charge of $28 million in the fourth quarter of 2017. DOE NOPR: Grid Reliability and Resilience Pricing On September 28, 2017, the Secretary of Energy released a NOPR requesting FERC to issue rules directing RTOs to incorporate pricing for defined “eligible grid reliability and resiliency resources” into wholesale energy markets. Specifically, as proposed, RTOs would develop and implement tariffs providing a just and reasonable rate for energy purchases from eligible grid reliability and resiliency resources and the recovery of fully allocated costs and a fair ROE. The NOPR followed the August 23, 2017, release of the DOE’s study regarding whether federally controlled wholesale energy markets properly recognize the importance of coal and nuclear plants for the reliability of the high-voltage grid, as well as whether federal policies supporting renewable energy sources have harmed the reliability of the energy grid. The DOE requested for the final rules to be effective in January 2018. On October 2, 2017, FERC established a docket and requested comments on the NOPR. FESC and certain of its affiliates submitted comments and reply comments. On January 8, 2018, FERC issued an order terminating the NOPR proceeding, finding that the NOPR did not satisfy the statutory threshold requirements under the FPA for requiring changes to RTO/ISO tariffs to address resilience concerns. FERC in its order instituted a new administrative proceeding to gather additional information regarding resilience issues, and directed that each RTO/ISO respond to a provided list of questions. There is no deadline or requirement for FERC to act in this new proceeding. At this time, we are uncertain as to the potential impact that final action by FERC, if any, would have on FES and our strategic options, and the timing thereof, with respect to the competitive business. Competitive Generation Asset Sale FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement with a subsidiary of LS Power, 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) for an all-cash purchase price of $825 million, subject to adjustments and through multiple, independent closings. On December 13, 2017, AE Supply completed the sale of the natural gas generating plants with net proceeds, subject to post-closing adjustments, of approximately $388 million. The sale of AE Supply's interests in the Bath County hydroelectric power station and the Buchanan Generating facility is expected to generate net proceeds of $375 million and is anticipated to close in the first half of 2018, subject in each case to various customary and other closing conditions, including, without limitation, receipt of regulatory approvals. As part of the closing of the natural gas generating plants, FE provided the purchaser two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC arising under the amended and restated purchase agreement. With the sale of the gas plants completed, upon the consummation of the sale of AGC's interest in the Bath County hydroelectric power station or the sale or deactivation of the Pleasants Power Station, AE Supply is obligated under the amended and restated purchase agreement and AE Supply's applicable debt agreements to satisfy and discharge approximately $305 million of currently outstanding senior notes, as well as its $142 million of pollution control notes and AGC's $100 million senior notes, which are expected to require the payment of "make-whole" premiums currently estimated to be approximately $95 million based on current interest rates. On October 20, 2017, the parties filed an application with the VSCC for approval of the sale of approximately 59% of AGC's interest in the Bath County hydroelectric power station. On December 12, 2017, FERC issued an order authorizing the partial transfer of the related hydroelectric license for Bath County under Part I of the FPA. In December 2017, AGC, AE Supply and MP filed with FERC and AGC and AE Supply filed with the VSCC, applications for approval of AGC redeeming AE Supply’s shares in AGC upon consummation of the Bath County transaction. On February 2, 2018, the VSCC issued an order finding that approval of the proposed stock redemption is not required, and on February 16, 2018, FERC issued an order authorizing the redemption. Upon the consummation of the redemption, AGC will become a wholly-owned subsidiary of MP. On December 28, 2017, FERC issued an order authorizing the sale of BU Energy’s Buchanan interests. Additional filings have been submitted to FERC for the purpose of amending affected FERC-jurisdictional rates and implementing the transaction once 55 the sales are consummated. There can be no assurance that all regulatory approvals will be obtained and/or all closing conditions will be satisfied or that the remaining transactions will be consummated. As a result of the amended asset purchase agreement, CES recorded non-cash pre-tax impairment charges of $193 million in 2017, reflecting the $825 million purchase price as well as certain purchase price adjustments based on timing of the closing of the transaction. PATH Transmission Project In 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia through Virginia and into Maryland. As a result of PJM canceling the project, approximately $62 million and approximately $59 million in costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery. PATH-Allegheny and PATH-WV requested authorization from FERC to recover the costs with a proposed ROE of 10.9% (10.4% base plus 0.5% for RTO membership) from PJM customers over five years. FERC issued an order denying the 0.5% ROE adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to hearing and settlement procedures. On January 19, 2017, FERC issued an order reducing the PATH formula rate ROE from 10.4% to 8.11% effective January 19, 2017, and allowing recovery of certain related costs. On February 21, 2017, PATH filed a request for rehearing with FERC, seeking recovery of disallowed costs and requesting that the ROE be reset to 10.4%. The Edison Electric Institute submitted an amicus curiae request for reconsideration in support of PATH. On March 20, 2017, PATH also submitted a compliance filing implementing the January 19, 2017 order. Certain affected ratepayers commented on the compliance filing, alleging inaccuracies in and lack of transparency of data and information in the compliance filing, and requested that PATH be directed to recalculate the refund provided in the filing. PATH responded to these comments in a filing that was submitted on May 22, 2017. On July 27, 2017, FERC Staff issued a letter to PATH requesting additional information on, and edits to, the compliance filing, as directed by the January 19, 2017 order. PATH filed its response on September 27, 2017. FERC orders on PATH's requests for rehearing and compliance filing remain pending. Market-Based Rate Authority, Triennial Update The Utilities, AE Supply, FES and certain of its subsidiaries, Buchanan Generation and Green Valley each hold authority from FERC to sell electricity at market-based rates. One condition for retaining this authority is that every three years each entity must file an update with FERC that demonstrates that each entity continues to meet FERC’s requirements for holding market-based rate authority. On December 23, 2016, FESC, on behalf of its affiliates with market-based rate authority, submitted to FERC the most recent triennial market power analysis filing for each market-based rate holder for the current cycle of this filing requirement. On July 27, 2017, FERC accepted the triennial filing as submitted. ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Pursuant to a March 28, 2017 executive order, the EPA and other federal agencies are to review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof, in particular with respect to existing environmental regulations, may impact its business, results of operations, cash flows and financial condition. Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. 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, generating more electricity from lower or non-emitting plants 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. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the 56 EPA and the states ultimately implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's and FES' operations may result. The EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015. The EPA stated the vast majority of U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and state rules and programs but the EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017. The EPA missed the October 1, 2017, deadline and has not yet promulgated the attainment designations. States will then have roughly three years to develop implementation plans to attain the new 2015 ozone NAAQS. On December 5, 2017, fourteen states and the District of Columbia filed complaints in the U.S. District Court of Northern California seeking an order that the EPA promulgate the attainment designations for the new 2015 ozone NAAQS. Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be material and changes to FirstEnergy’s and FES’ operations may result. 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 seeks a short-term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. On September 27, 2016, the EPA extended the time frame for acting on the State of Delaware's CAA Section 126 petition by six months to April 7, 2017, but has not taken any further action. On January 2, 2018, the State of Delaware provided the EPA a notice required at least 60 days prior to filing a suit seeking to compel the EPA to either approve or deny the August 2016 CAA Section 126 petition. 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, Mansfield Unit 1 and Pleasants Units 1 and 2, significantly contribute to Maryland's inability to attain the ozone NAAQS. The petition seeks NOx emission rate limits for the 36 EGUs by May 1, 2017. On January 3, 2017, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to July 15, 2017, but has not taken any further action. On September 27, 2017, and October 4, 2017, the State of Maryland and various environmental organizations filed complaints in the U.S. District Court for the District of Maryland seeking an order that the EPA either approve or deny the CAA Section 126 petition of November 16, 2016. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss. MATS imposed emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired EGUs effective in April 2015 with averaging of emissions from multiple units located at a single plant. The majority of FirstEnergy's MATS compliance program and related costs have been completed. On August 3, 2015, FG, a wholly owned subsidiary of FES, submitted to the AAA office in New York, N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure event that excuses FG’s performance under its coal transportation contract with these parties. Specifically, the dispute arose from a contract for the transportation by BNSF and CSX of a minimum of 3.5 million tons of coal annually through 2025 to certain coal-fired power plants owned by FG that are located in Ohio. As a result of and in compliance with MATS, all plants covered by this contract were deactivated by April 16, 2015. Separately, on August 4, 2015, BNSF and CSX submitted to the AAA office in Washington, D.C., a demand for arbitration and statement of claim against FG alleging that FG breached the contract and that FG’s declaration of a force majeure under the contract is not valid and seeking damages under the contract through 2025. On May 31, 2016, the parties agreed to a stipulation that if FG’s force majeure defense is determined to be wholly or partially invalid, liquidated damages are the sole remedy available to BNSF and CSX. The arbitration panel consolidated the claims and held a hearing in November and December 2016. On April 12, 2017, the arbitration panel ruled on liability in favor of BNSF and CSX. In the liability award, the panel found, among other things, that FG’s demand for declaratory judgment that force majeure excused FG’s performance was denied, that FG breached and repudiated the coal transportation contract and that the panel retains jurisdiction of claims for liquidated damages for the years 2015-2025. On May 1, 2017, FE and FG and CSX and BNSF entered into a definitive settlement agreement, which resolved all claims related to this consolidated proceeding on the terms and conditions set forth below. Pursuant to the settlement agreement, FG will pay CSX and BNSF an aggregate amount equal to $109 million, which is payable in three annual installments, the first of which was made on May 1, 2017. FE agreed to unconditionally and continually guarantee the settlement payments due by FG pursuant to the terms of the settlement agreement. The settlement agreement further provides that in the event of the initiation of bankruptcy proceedings or failure to make timely settlement payments, the unpaid settlement amount will immediately accelerate and become due and payable in full. Further, FE and FG, and CSX and BNSF, agreed to release, waive and discharge each other from any further obligations under the claims covered by the settlement agreement upon payment in full of the settlement amount. Until such time, CSX and BNSF will retain the claims covered by the settlement agreement and in the event of a bankruptcy proceeding with respect to FG, to the extent the remaining settlement payments are not paid in full by FG or FE, CSX and BNSF shall be entitled to seek damages for such claims in an amount to be determined by the arbitration panel or otherwise agreed by the parties. On December 22, 2016, FG, a wholly owned subsidiary of FES, received a demand for arbitration and statement of claim from BNSF and NS which are the counterparties to the coal transportation contract covering the delivery of 2.5 million tons annually through 2025, for FG’s coal-fired Bay Shore Units 2-4, deactivated on September 1, 2012, as a result of the EPA’s MATS and for FG’s W.H. Sammis generating station. The demand for arbitration was submitted to the AAA office in Washington, D.C., against FG alleging, among other things, that FG breached the agreement in 2015 and 2016 and repudiated the agreement for 2017-2025. The counterparties are seeking liquidated damages through 2025, and a declaratory judgment that FG's claim of force majeure is invalid. The arbitration hearing is scheduled for June 2018. The parties have exchanged settlement proposals to resolve all claims related to this proceeding, however, discussions have been terminated and settlement is unlikely. FirstEnergy and FES recorded a pre-tax charge of $116 million in 2017 based on an estimated range of losses regarding the ongoing litigation with respect to this agreement. If the case proceeds to arbitration, the amount of damages owed to BNSF and NS could be materially higher and may 57 cause FES to seek protection under U.S. bankruptcy laws. FG intends to vigorously assert its position in this arbitration proceeding, and if it were ultimately determined that the force majeure provisions or other defenses do not excuse the delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. As to a specific coal supply agreement, AE Supply, the party thereto, asserted termination rights effective in 2015 as a result of MATS. In response to notification of the termination, on January 15, 2015, Tunnel Ridge, LLC, the coal supplier, commenced litigation in the Court of Common Pleas of Allegheny County, Pennsylvania, alleging AE Supply did not have sufficient justification to terminate the agreement and seeking damages for the difference between the market and contract price of the coal, or lost profits plus incidental damages. AE Supply filed an answer denying any liability related to the termination. On May 1, 2017, the complaint was amended to add FE, FES and FG, although not parties to the underlying contract, as defendants and to seek additional damages based on new claims of fraud, unjust enrichment, promissory estoppel and alter ego. On June 27, 2017, after oral argument, defendants' preliminary objections to the amended complaint were denied. On February 18, 2018, the parties reached an agreement in principle settling all claims in dispute. The agreement in principle includes, among other matters, a $93 million payment by AE Supply, as well as certain coal supply commitments for Pleasants Power Station during its remaining operation by AE Supply. Certain aspects of the final settlement agreement will be guaranteed by FE, including the $93 million payment. In September 2007, AE received an NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia. The EPA's NOV alleges equipment replacements during maintenance outages triggered the pre-construction permitting requirements under the NSR and PSD programs. On June 29, 2012, January 31, 2013, March 27, 2013 and October 18, 2016, the EPA issued CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. On December 12, 2014, the EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009. FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss. Climate Change FirstEnergy has established a goal to reduce CO2 emissions by 90% below 2005 levels by 2045. 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. The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act,” in December 2009, 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. On June 23, 2014, the U.S. Supreme Court decided that CO2 or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies. The EPA released its final CPP regulations in August 2015 (which have been stayed by the U.S. Supreme Court), to reduce CO2 emissions from existing fossil fuel-fired EGUs. The EPA also 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 January 21, 2016, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument. 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. Depending on the outcomes of the review pursuant to the executive order, of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material. 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 and in September 2016, 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 was ratified by the requisite number of countries (i.e., at least 55 countries representing at least 55% of global GHG emissions) in October 2016 and its non-binding obligations to limit global warming to well 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. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators. 58 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 plants. 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. The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits. On April 13, 2017, the EPA granted a Petition for Reconsideration and administratively stayed (effective upon publication in the Federal Register) all deadlines in the effluent limits rule pending a new rulemaking. Also, on September 18, 2017, the EPA postponed certain compliance deadlines for two years. 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 and FES' operations may result. In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the effluent limits that were effective immediately under the terms of the NPDES permit. MP appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require an initial capital investment ranging from $150 million to $300 million in order to install technology to meet the TDS and sulfate limits, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of the appeal or estimate the possible loss or range of loss. FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the loss or range of loss. 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. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although not currently expected, changes in timing and closure plan requirements in the future, including changes resulting from the strategic review at CES, could materially and adversely impact FirstEnergy's and FES' AROs. Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRs by December 31, 2016, and FG to provide bonding for 45 years of closure and post- closure activities and to complete closure within a 12-year period, but authorizing FG to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCRs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The CCRs from the Bruce Mansfield plant are being beneficially reused with the majority used for reclamation of a site owned by the Marshall County Coal Company in Moundsville, W. Va., and the remainder recycled into drywall by National Gypsum. These beneficial reuse options should be sufficient for ongoing plant operations, however, the Bruce Mansfield plant is pursuing other options. On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR. The Sierra Club's Notices of Appeal before the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility were resolved through a Consent Adjudication between FG, PA DEP and the Sierra Club requiring operational changes that became effective November 3, 2017. 59 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, 2017, based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $125 million have been accrued through December 31, 2017. Included in the total are accrued liabilities of approximately $80 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FirstEnergy 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, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of December 31, 2017, FirstEnergy had approximately $2.7 billion (FES $1.9 billion) invested in external trusts to be used for the decommissioning and environmental remediation of its nuclear generating facilities. The values of FirstEnergy's NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, FirstEnergy's obligation 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. As part of routine inspections of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. These inspections revealed that the cracking condition had propagated a small amount in select areas. FENOC's analysis confirms that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions. In a May 28, 2015, Inspection Report regarding the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation for FENOC’s failure to request and obtain a license amendment for its method of evaluating the significance of the shield building cracking. The NRC also concluded that the shield building remained capable of performing its design safety functions despite the identified laminar cracking and that this issue was of very low safety significance. In 2017, FENOC commenced a multi-year effort to implement repairs to the shield building. In addition to these ongoing repairs, FENOC intends to submit a license amendment application to the NRC to reconcile the shield building laminar cracking concern. FES provides a parental support agreement to NG of up to $400 million. The NRC typically relies on such parental support agreements to provide additional assurance that U.S. merchant nuclear plants, including NG's nuclear units, have the necessary financial resources to maintain safe operations, particularly in the event of extraordinary circumstances. So long as FES remains in the unregulated companies' money pool, the $500 million secured line of credit with FE discussed above provides FES the needed liquidity in order for FES to satisfy its nuclear support obligations to NG. Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The loss or range of loss in these matters is not expected to be material to FirstEnergy or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 15, "Regulatory Matters," of the Combined Notes to Consolidated Financial Statements. 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 FirstEnergy 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 FirstEnergy'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 Combined Notes to Consolidated Financial Statements. Revenue Recognition 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 60 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. See Note 1, "Organization and Basis of Presentation," for additional details. Regulatory Accounting FirstEnergy’s regulated distribution and regulated transmission segments are subject to regulations that set the prices (rates) the Utilities, AGC, ATSI, MAIT and TrAIL 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. 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 15, "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. 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, 2017, 2016, and 2015 were $141 million, $147 million, and $242 million, 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 discount rates for pension were 3.75%, 4.25% and 4.50% as of December 31, 2017, 2016 and 2015, respectively. The assumed discount rates for OPEB were 3.50%, 4.00% and 4.25% as of December 31, 2017, 2016 and 2015, respectively. 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 2017, FirstEnergy’s qualified pension and OPEB plan assets experienced gains of $999 million or 15.1% compared to gains of $472 million, or 8.2% in 2016 and losses of $(172) million, or (2.7)% in 2015 and assumed a 7.50% rate of return on plan assets in 2017 and 2016 and a 7.75% expected rate of return in 2015 which generated $478 million, $429 million and $476 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 increase or decrease 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 2018 is 7.50%. During 2017, the Society of Actuaries released its updated mortality improvement scale for pension plans, MP-2017, incorporating three additional years of SSA data on U.S. population mortality. MP-2017 incorporates SSA mortality data from 2013 to 2015 and a slight modification of two input values designed to improve the model’s year-over-year stability. The updated improvement scale indicates a slight decline in life expectancy. Due to the additional years of data on population mortality, the RP2014 mortality table with the projection scale MP-2017 was utilized to determine the 2017 benefit cost and obligation as of December 31, 2017 for the FirstEnergy pension and OPEB plans. The impact of using the projection scale MP-2017 resulted in a decrease in the projected pension benefit obligation of $62 million and was included in the 2017 pension and OPEB mark-to-market adjustment. Based on discount rates of 3.75% for pension, 3.50% for OPEB and an estimated return on assets of 7.50%, FirstEnergy expects its 2018 pre-tax net periodic benefit credit (including amounts capitalized) to be approximately $50 million (excluding any actuarial 61 mark-to-market adjustments that would be recognized in 2018). 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, 2017. Postemployment Benefits Expense (Credits) 2017 2016 2015 Pension OPEB Total (In millions) 247 $ 277 $ (45) (40) 202 $ 237 $ $ $ 316 (61) 255 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 2017 and 2016, 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 2018 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 .25% Long-term return on assets Decrease by .25% $ $ Health care trend rate Increase by 1.0% 315 19 $ $ N/A $ 18 1 21 $ $ $ 333 20 21 See Note 4, "Pension and Other Postemployment Benefits," for additional information. Long-Lived Assets 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. See Note 1, "Organization and Basis of Presentation." See Note 2, "Asset Sales and Impairments," for impairments recognized in 2017 and 2016. Asset Retirement Obligations FE recognizes an ARO for the future decommissioning of its nuclear power plants 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 FE'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. FE uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO, considering the expected timing of settlement of the ARO based on the expected economic useful life of the plants (including the likelihood that the facilities will be deactivated before the end of their estimated useful lives). 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. 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, 2017, are described further in Note 14, "Asset Retirement Obligations." 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 62 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 recognized in its financial statements. We account for uncertain income tax positions 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. That amount is computed 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 6, "Taxes," for additional information. On December 22, 2017, the President signed into law the Tax Act. Substantially all of the provisions of the Tax Act are effective for taxable years beginning after December 31, 2017. The Tax Act includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated public utilities including FirstEnergy’s regulated distribution and transmission subsidiaries. The more significant changes that impact FirstEnergy included in the Tax Act are the following: • 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; 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. The most significant change that impacts FirstEnergy in the current year is the reduction of the corporate federal income tax rate. Other provisions are not expected to have a significant impact on the financial statements, but may impact the effective tax rate in future years. Under US GAAP, specifically ASC Topic 740, Income Taxes, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted, or December 22, 2017, for the Tax Act. ASC 740 also requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Thus, at the date of enactment, FirstEnergy’s deferred taxes were re-measured based upon the new tax rate, which resulted in a material decrease to FirstEnergy’s net deferred income tax liabilities. For FirstEnergy’s unregulated operations, the change in deferred taxes are recorded as an adjustment to FirstEnergy’s deferred income tax provision. FirstEnergy’s regulated entities recorded a corresponding net regulatory liability to the extent the change in deferred taxes would result in amounts previously collected from utility customers to be subject to refunds to such customers, generally through reductions in future rates. All other amounts were recorded as an adjustment to FirstEnergy’s regulated entities’ deferred income tax provision. FirstEnergy has completed its assessment of the accounting for certain effects of the provisions in the Tax Act, and as allowed under SEC Staff Accounting Bulletin 118 (SAB 118), has recorded provisional income tax amounts as of December 31, 2017 related to depreciation for which the impacts of the Tax Act could not be finalized, but for which a reasonable estimate could be determined. Under the new law, property acquired and placed into service after September 27, 2017, will be eligible for full expensing for all taxpayers other than regulated utilities. As a result, FirstEnergy will need to evaluate the contractual terms of its capital expenditures to determine eligibility for full expensing. As of December 31, 2017, FirstEnergy has not yet completed this analysis, but has recorded a reasonable estimate of the effects of these changes based on capital costs incurred prior to year-end. In addition, SAB 118 allows for a measurement period for companies to finalize the provisional amounts recorded as of December 31, 2017. FirstEnergy expects to record any final adjustments to the provisional amounts by the fourth quarter of 2018, which could result in a material impact to FirstEnergy’s income tax provision or financial position. FirstEnergy’s assessment of accounting for the Tax Act are based upon management’s current understanding of the Tax Act. However, it is expected that further guidance will be issued during 2018, which may result in adjustments that could have a material impact to FirstEnergy’s future results of operations, cash flows, or financial position. As a result of the Tax Act, FirstEnergy recognized a non-cash charge to income tax expense of $1.2 billion (FES - $1.1 billion) and resulted in excess deferred taxes of $2.3 billion for the regulated businesses, of which the revenue impact was recorded as a regulatory liability. These adjustments had no impact on our 2017 cash flows. Goodwill In a business combination, the excess of the purchase price over the estimated fair values 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 63 of a reporting unit is less than its carrying value or bypasses the qualitative assessment, then the two-step quantitative goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any. As of July 31, 2017, 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 value and a quantitative analysis was not necessary. See Note 2, "Asset Sales and Impairments," for further discussion of CES goodwill impairment charge recognized in 2016. NEW ACCOUNTING PRONOUNCEMENTS ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting" (Issued March 2016): ASU 2016-09 simplifies several aspects of the accounting for employee share-based payments. The new guidance requires all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also does not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. FirstEnergy adopted ASU 2016-09 on January 1, 2017. Upon adoption, FirstEnergy elected to account for forfeitures as they occur. The change was applied on a modified retrospective basis with a cumulative effect adjustment to retained earnings of approximately $6 million as of January 1, 2017. Additionally, FirstEnergy retrospectively applied the cash flow presentation requirement to present cash paid to tax authorities when shares are withheld to satisfy statutory tax withholding obligations as financing activities by reclassifying $12 million and $13 million from operating activities to financing activities in the 2016 and 2015 Consolidated Statements of Cash Flows, respectively. ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments" (Issued August 2016): The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments are presented and classified in the Consolidated Statements of Cash Flows, including the presentation of debt prepayment or debt extinguishment costs, all of which will be classified as financing activities. ASU 2016-15 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. FirstEnergy early adopted this ASU as of January 1, 2017. There was no impact to prior periods. Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB was not adopted in 2017. 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 and has not included these standards based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. ASU 2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to address implementation questions): The new revenue recognition guidance: establishes a new control-based revenue recognition model, changes the basis for deciding when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific topics and expands and improves disclosures about revenue. FirstEnergy has evaluated its revenues and the new guidance will have limited impacts to current revenue recognition practices upon adoption on January 1, 2018. As part of the adoption, FirstEnergy elected to apply the new guidance on a modified retrospective basis. FirstEnergy will not record a cumulative adjustment to retained earnings for initially applying the new guidance as no revenue recognition differences were identified in the timing or amount of revenue. In addition, upon adoption, certain immaterial financial statement presentation changes will be implemented. FirstEnergy expects to disaggregate revenue by type of service in future revenue disclosures. ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities" (issued January 2016): ASU 2016-01 primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. Upon adoption, January 1, 2018, FirstEnergy will recognize all gains and losses for equity securities in income with the exception of those that are accounted for under the equity method of accounting. The NDT’s equity portfolios of JCP&L, ME and PN will not be impacted as unrealized gains and losses will continue to be offset against regulatory assets or liabilities. As a result of adopting the standard, FirstEnergy and FES will record a cumulative effect adjustment to retained earnings of $115 million (pre-tax) on January 1, 2018 representing unrealized gains on equity securities that were previously recorded to AOCI. ASU 2016-02, "Leases (Topic 842)" (Issued February 2016) and ASU 2018-01,"Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842" (Issued January 2018): ASU 2016-02 will require 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. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. ASU 2018-01 (same effective date and transition requirements as ASU 2016-02) provides an optional transition practical expedient that, if elected, would not require an entity to reconsider its accounting for existing land easements that are not currently accounted for under the old leases standard. FirstEnergy does not plan to adopt these standards early. Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial 64 statements. Any leases that expire before the initial application date will not require any accounting adjustment. FirstEnergy expects an increase in assets and liabilities, however, it is currently assessing the impact on its Consolidated Financial Statements. This assessment includes monitoring utility industry implementation guidance. FirstEnergy is in the process of conducting outreach activities across its business units and analyzing its lease population. In addition, it has begun implementation of a third-party software tool that will assist with the initial adoption and ongoing compliance. ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (issued June 2016): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that 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. Early adoption is permitted for fiscal years beginning after December 15, 2018. ASU 2016-16, "Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory" (issued October 2016): ASU 2016-16 eliminates the exception for all intra-entity sales of assets other than inventory, which allows companies to defer the tax effects of intra-entity asset transfers. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the intra-entity transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted and the modified retrospective approach will be required for transition to the new guidance, with a cumulative- effect adjustment recorded in retained earnings as of the beginning of the period of adoption. FirstEnergy will not be impacted upon its adoption of this ASU on January 1, 2018. ASU 2016-18, "Restricted Cash" (issued November 2016): ASU 2016-18 addresses the presentation of changes in restricted cash and restricted cash equivalents in the statement of cash flows. The guidance is required to be applied retrospectively. In its first quarter 2018 Form 10-Q, FirstEnergy will show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. In addition, FirstEnergy will disclose the nature of its restricted cash and restricted cash equivalent balances within the footnotes. ASU 2017-01, "Business Combinations: Clarifying the Definition of a Business" (Issued January 2017): ASU 2017-01 assists entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. The ASU will be applied prospectively to any transactions occurring within the period of adoption. FirstEnergy will not early adopt this standard. ASU 2017-07, "Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" (Issued March 2017): ASU 2017-07 requires entities to retrospectively (1) disaggregate the current- service-cost component from the other components of net benefit cost (the “other components”) and present it with other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations if such a subtotal is presented. As a result of the retrospective presentation, FirstEnergy will reclassify approximately $62 million of non-service costs, excluding the annual mark-to-market, to Other Income/ Expense related to the fiscal year 2017 within the 2018 financial statements. In addition, ASU 2017-07 requires service costs to be capitalized as appropriate and non-service costs to be charged to earnings. FirstEnergy will present non-service costs in the caption “Miscellaneous Income” with the exception of the annual mark-to-market adjustment which will be disclosed separately. ASU 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income" (Issued February 2018): ASU 2018-02 allows entities to reclassify from AOCI to retained earnings stranded tax effects resulting from the Tax Act. ASU 2018-02 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2018. Early adoption of the ASU is permitted including adoption in any interim period. ASU 2018-02 should be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the income tax rate change resulting from the Tax Act is recognized. FirstEnergy did not adopt this ASU as of December 31, 2017. 65 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." 66 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA MANAGEMENT REPORT Management’s Responsibility for Financial Statements The consolidated financial statements of FirstEnergy Corp. (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2017 consolidated financial statements as stated in their audit report included herein. As discussed in Note 1 to the consolidated financial statements, FirstEnergy Corp. is engaged in a strategic review of its competitive operations and its wholly-owned subsidiary, FirstEnergy Solutions Corp. (FES), is facing challenging market conditions impacting FES' liquidity. The Company’s internal auditors, who are responsible to the Audit Committee of the Company’s Board of Directors, review the results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls. The Company’s Audit Committee consists of five independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held eight meetings in 2017. 67 Report of Independent Registered Public Accounting Firm To the Stockholders and Board of Directors of FirstEnergy Corp. 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 as of December 31, 2017 and December 31, 2016, and the related consolidated statements of income (loss), comprehensive income (loss), common stockholders’ equity, and of cash flows for each of the three years in the period ended December 31, 2017, 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, 2017, 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, 2017 and December 31, 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 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, 2017, 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 Management's Report on Internal Control over Financial Reporting appearing under Item 9A. 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. Emphasis of Matter As discussed in Note 1 to the consolidated financial statements, FirstEnergy Corp.'s wholly-owned subsidiary, FirstEnergy Solutions Corp. (FES), is facing challenging market conditions impacting FES' liquidity. 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. 68 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. /s/ PricewaterhouseCoopers LLP Cleveland, Ohio February 20, 2018 We have served as the Company’s auditor since 2002. 69 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions) REVENUES: Regulated Distribution Regulated Transmission Unregulated businesses Total revenues* OPERATING EXPENSES: Fuel Purchased power Other operating expenses Pension and OPEB mark-to-market adjustment Provision for depreciation Amortization of regulatory assets, net General taxes Impairment of assets and related charges (Note 2) Total operating expenses OPERATING INCOME (LOSS) OTHER INCOME (EXPENSE): Investment income (loss) Impairment of equity method investment (Note 1) Interest expense Capitalized financing costs Total other expense INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) INCOME TAXES (BENEFITS) NET INCOME (LOSS) EARNINGS (LOSS) PER SHARE OF COMMON STOCK: Basic Diluted WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING: Basic Diluted DIVIDENDS DECLARED PER SHARE OF COMMON STOCK For the Years Ended December 31 2015 2016 2017 $ $ $ $ $ $ 9,734 1,325 2,958 14,017 1,383 3,194 4,232 141 1,138 308 1,043 2,406 13,845 172 98 — (1,178) 79 (1,001) (829) 895 $ 9,629 1,144 3,789 14,562 1,666 3,843 3,851 147 1,313 297 1,042 10,665 22,824 (8,262) 84 — (1,157) 103 (970) (9,232) (3,055) (1,724) $ (6,177) $ (3.88) $ (3.88) $ (14.49) $ (14.49) $ 444 444 426 426 1.44 $ 1.44 $ 9,625 1,003 4,398 15,026 1,855 4,423 3,740 242 1,282 172 978 42 12,734 2,292 (22) (362) (1,132) 117 (1,399) 893 315 578 1.37 1.37 422 424 1.44 * Includes excise tax collections of $390 million, $406 million and $416 million in 2017, 2016 and 2015, respectively. The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements. 70 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In millions) NET INCOME (LOSS) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs Amortized losses on derivative hedges Change in unrealized gain on available-for-sale securities Other comprehensive income (loss) Income taxes (benefits) on other comprehensive income (loss) Other comprehensive income (loss), net of tax For the Years Ended December 31 2017 2016 2015 $ (1,724) $ (6,177) $ 578 (85) 10 22 (53) (21) (32) (59) 8 55 4 1 3 (116) 5 (11) (122) (47) (75) 503 COMPREHENSIVE INCOME (LOSS) $ (1,756) $ (6,174) $ The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements. 71 FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS (In millions, except share amounts) CURRENT ASSETS: Cash and cash equivalents Receivables- ASSETS Customers, net of allowance for uncollectible accounts of $51 in 2017 and $53 in 2016 Other, net of allowance for uncollectible accounts of $1 in 2017 and 2016 Materials and supplies, at average cost Derivatives Collateral Prepaid taxes and other PROPERTY, PLANT AND EQUIPMENT: In service Less — Accumulated provision for depreciation Construction work in progress INVESTMENTS: Nuclear plant decommissioning trusts Other ASSETS HELD FOR SALE (Note 2) DEFERRED CHARGES AND OTHER ASSETS: Goodwill Regulatory assets Other LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt Short-term borrowings Accounts payable Accrued taxes Accrued compensation and benefits Collateral Other CAPITALIZATION: Common stockholders’ equity- Common stock, $0.10 par value, authorized 700,000,000 and 490,000,000 shares - 445,334,111 and 442,344,218 shares outstanding as of December 31, 2017 and December 31, 2016, respectively $ $ Other paid-in capital Accumulated other comprehensive income Accumulated deficit Total common stockholders' equity Long-term debt and other long-term obligations NONCURRENT LIABILITIES: Accumulated deferred income taxes Retirement benefits Regulatory liabilities Asset retirement obligations Deferred gain on sale and leaseback transaction Adverse power contract liability Other December 31, 2017 December 31, 2016 $ 589 $ $ $ 1,463 191 463 37 146 219 3,108 39,778 11,925 27,853 1,026 28,879 2,678 506 3,184 375 5,618 40 1,053 6,711 42,257 1,082 300 1,027 571 336 39 722 4,077 44 10,001 142 (6,262) 3,925 21,115 25,040 1,359 3,975 2,720 2,515 723 130 1,718 13,140 199 1,440 175 564 140 176 256 2,950 43,767 15,731 28,036 1,351 29,387 2,514 512 3,026 — 5,618 1,014 1,153 7,785 43,148 1,685 2,675 1,043 580 363 42 738 7,126 44 10,555 174 (4,532) 6,241 18,192 24,433 3,765 3,719 157 1,482 757 162 1,547 11,589 COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 16) $ 42,257 $ 43,148 The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements. 72 CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY FIRSTENERGY CORP. (In millions, except share amounts) Common Stock Number of Shares Par Value Other Paid-In Capital Accumulated Other Comprehensive Income Retained Earnings (Accumulated Deficit) Balance, January 1, 2015 421,102,570 $ 42 $ 9,847 $ 246 $ Net income Amortized gains on derivative hedges, net of $1 million of income taxes Change in unrealized gain on investments, net of $4 million of income tax benefits Pensions and OPEB, net of $44 million of income tax benefits (Note 4) Stock-based compensation Cash dividends declared on common stock Stock Investment Plan and certain share- based benefit plans Balance, December 31, 2015 Net loss Amortized gains on derivative hedges, net of $3 million of income taxes Change in unrealized gain on investments, net of $21 million of income taxes Pensions and OPEB, net of $23 million of income tax benefits (Note 4) Stock-based compensation Cash dividends declared on common stock Stock Investment Plan and certain share- based benefit plans Stock issuance (Note 12) Balance, December 31, 2016 Net loss Amortized gains on derivative hedges, net of $4 million of income taxes Change in unrealized gain on investments, net of $7 million of income taxes Pensions and OPEB, net of $32 million of income tax benefits (Note 4) Stock-based compensation Cash dividends declared on common stock Stock Investment Plan and certain share- based benefit plans Reclass to liability awards (Note 5) Share-based compensation accounting change (Note 1) 2,457,827 423,560,397 42 2,685,946 16,097,875 442,344,218 2 44 2,989,893 45 60 9,952 49 56 498 10,555 36 (639) 56 (7) 4 (7) (72) 171 5 34 (36) 174 6 15 (53) 2,285 578 (607) 2,256 (6,177) (611) (4,532) (1,724) (6) Balance, December 31, 2017 445,334,111 $ 44 $ 10,001 $ 142 $ (6,262) The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements. 73 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (In millions) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income (loss) 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- related costs Impairment of assets and related charges (Note 2) Investment impairments, including equity method investments Pension and OPEB mark-to-market adjustment Deferred income taxes and investment tax credits, net Deferred costs on sale leaseback transaction, net Asset removal costs charged to income Retirement benefits, net of payments Unrealized (gain) loss on derivative transactions (Note 11) Pension trust contributions Gain on sale of investment securities held in trusts Lease payments on sale and leaseback transaction Changes in current assets and liabilities- Receivables Materials and supplies Prepaid taxes and other Accounts payable Accrued taxes Accrued compensation and benefits Other current liabilities Cash collateral, net Other Net cash provided from operating activities CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt Short-term borrowings, net Redemptions and Repayments- Long-term debt Short-term borrowings, net Common stock dividend payments Other Net cash 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 Asset removal costs Other Net cash used for investing activities Net change in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period SUPPLEMENTAL CASH FLOW INFORMATION: Non-cash transaction: stock contribution to pension plan Cash paid (received) during the year - Interest (net of amounts capitalized) Income taxes, net of refunds For the Years Ended December 31 2017 2016 2015 $ (1,724) $ (6,177) $ 578 1,700 2,406 13 141 839 49 22 29 81 — (63) (73) (39) (6) 30 72 (9) (27) 20 27 320 3,808 4,675 — (2,291) (2,375) (639) (72) (702) (2,587) (254) 388 2,170 (2,268) (172) 7 (2,716) 1,974 10,665 21 147 (3,063) 49 54 64 9 (382) (50) (120) (11) 41 27 (37) 61 29 56 (116) 142 3,383 1,976 975 (2,331) — (611) (43) (34) (2,835) (232) 15 1,678 (1,789) (145) 27 (3,281) 390 199 589 $ 68 131 199 $ 1,826 42 464 242 284 48 55 (20) (73) (143) (23) (131) 184 (15) (10) (243) 29 5 69 140 152 3,460 1,311 — (879) (91) (607) (26) (292) (2,704) (190) 20 1,534 (1,648) (142) 8 (3,122) 46 85 131 — $ 500 $ — 1,039 53 $ $ 1,050 $ (16) $ 1,028 37 $ $ $ $ The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements. 74 FIRSTENERGY CORP. AND SUBSIDIARIES COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note Number Page Number 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Organization and Basis of Presentation Asset Sales and Impairments Accumulated Other Comprehensive Income Pension and Other Postemployment Benefits Stock-Based Compensation Plans Taxes Leases Intangible Assets Variable Interest Entities Fair Value Measurements Derivative Instruments Capitalization Short-Term Borrowings and Bank Lines of Credit Asset Retirement Obligations Regulatory Matters Commitments, Guarantees and Contingencies Transactions with Affiliated Companies Supplemental Guarantor Information Segment Information Summary of Quarterly Financial Data (Unaudited) Subsequent Events 75 76 84 87 90 96 99 105 106 106 108 113 120 124 126 127 135 141 143 152 154 155 COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND BASIS OF PRESENTATION 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, FES and its principal subsidiaries (FG and NG), AE Supply, MP, PE, WP, FET and its principal subsidiaries (ATSI, MAIT and TrAIL), and AESC. In addition, FE holds all of the outstanding equity of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., GPU Nuclear, Inc. and Allegheny Ventures, Inc. FE and its subsidiaries are principally involved in the generation, transmission and distribution 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. Its regulated and unregulated generation subsidiaries control over 16,000 MWs of capacity from a diverse mix of non-emitting nuclear, scrubbed coal, natural gas, hydroelectric and other renewables. FirstEnergy’s transmission operations include approximately 24,500 miles of lines and two regional transmission operation centers. FES, a subsidiary of FE, was incorporated under Ohio law in 1997. FES provides energy-related products and services to retail and wholesale customers. FES also owns and operates, through its FG subsidiary, fossil generating facilities and owns, through its NG subsidiary, nuclear generating facilities, which are operated by FENOC. On December 21, 2015, FES agreed, under a PSA, to physically purchase all the output of AE Supply's generation facilities effective April 1, 2016. FES and AE Supply terminated the PSA effective on April 1, 2017. FES complies with the regulations, orders, policies and practices prescribed by the SEC, FERC, NRC and applicable state regulatory authorities. 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. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 9, "Variable Interest Entities"). 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). These Notes to Consolidated Financial Statements are combined for FirstEnergy and FES. Certain prior year amounts have been reclassified to conform to the current year presentation, including the reclassification of $30 million and $105 million of deferred purchased power and fuel costs previously included in Purchased power to Amortization of regulatory assets, net, for the years ended December 31, 2016 and 2015, respectively. Strategic Review of Competitive Operations FirstEnergy’s strategy is to be a fully regulated utility company, focusing on stable and predictable earnings and cash flow from its regulated business units - Regulated Distribution and Regulated Transmission. The Company continues to focus on its regulated growth strategy and in November 2016, FirstEnergy announced a strategic review to exit its commodity-exposed generation at CES, which is primarily comprised of the operations of FES and AE Supply. In connection with this strategic review, AE Supply and AGC entered into an asset purchase agreement with a subsidiary of LS Power, 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) for an all-cash purchase price of $825 million, subject to adjustments and through multiple, independent closings. On December 13, 2017, AE Supply completed the sale of the natural gas generating plants with net proceeds, subject to post-closing adjustments, of approximately $388 million. The sale of AE Supply’s interests in the Bath County hydroelectric power station and the Buchanan Generating facility is expected to generate net proceeds of $375 million and is anticipated to close in the first half of 2018, subject in each case to various customary and other closing conditions, including, without limitation, receipt of regulatory approvals. Additionally, on March 6, 2017, AE Supply and MP entered into an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station (1,300 MWs) for approximately $195 million, resulting from an RFP issued by MP to address its generation 76 shortfall. On January 12, 2018, FERC issued an order denying authorization for the transaction, holding that MP and AE Supply did not demonstrate the sale was consistent with the public interest and the transaction did not fall within the safe harbors for meeting FERC’s affiliate cross-subsidization analysis. On January 26, 2018, the WVPSC approved the transfer of the Pleasants Power Station, subject to certain conditions as further described in Note 15, "Regulatory Matters - West Virginia," below, which included MP assuming significant commodity risk. Based on the FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement and on February 16, 2018, AE Supply announced its intent to exit operations of the Pleasants Power Station by January 1, 2019, through either sale or deactivation, which resulted in a pre-tax impairment charge of $120 million. With the sale of the gas plants completed, upon the consummation of the sale of AGC's interest in the Bath County hydroelectric power station or the sale or deactivation of the Pleasants Power Station, AE Supply is obligated under the amended and restated purchase agreement and AE Supply's applicable debt agreements to satisfy and discharge approximately $305 million of currently outstanding senior notes, as well as its $142 million of pollution control notes and AGC's $100 million senior notes, which are expected to require the payment of “make-whole” premiums currently estimated to be approximately $95 million based on current interest rates. For additional information see Note 2, "Asset Sales and Impairments." The strategic options to exit the remaining portion of the CES portfolio, which is primarily at FES, are limited. The credit quality of FES, including its unsecured debt rating of Ca at Moody’s, C at S&P, and C at Fitch and the negative outlook from Moody’s and S&P, has challenged its ability to consummate asset sales. Furthermore, the inability to obtain legislative support under the Department of Energy’s recent NOPR, which was rejected by FERC, limits FES’ strategic options to plant deactivations, restructuring its debt and other financial obligations with its creditors, and/or to seek protection under U.S. bankruptcy laws. As part of the strategic review, FES evaluated its options with respect to its nuclear power plants. Factors considered as part of this review included current and forecasted market conditions, such as wholesale power and capacity prices, legislative and regulatory solutions that recognize their environmental and energy security benefits, and many other factors, including the significant capital and operating costs associated with operating a safe and reliable nuclear fleet. Based on this analysis, given the weak power and capacity price environment and the lack of legislative and regulatory solutions achieved to date, FES concluded that it would be increasingly difficult to operate these facilities in this environment and absent significant change concluded that it was probable that the facilities would be either deactivated or sold before the end of their estimated useful lives. As a result, FES recorded a pre- tax charge of $2.0 billion in the fourth quarter of 2017 to fully impair the nuclear facilities, including the generating plants and nuclear fuel as well as to reserve against the value of materials and supplies inventory and to increase its asset retirement obligation. For additional information see Note 2, "Asset Sales and Impairments." Going Concern at FES Although FES has access to a $500 million secured line of credit with FE, all of which was available as of January 31, 2018, its current credit rating and the current forward wholesale pricing environment present significant challenges to FES. As previously disclosed, FES has $515 million of maturing debt in 2018 (excluding intra-company debt), beginning with a $100 million principal payment due April 2, 2018. Based on FES' current senior unsecured debt rating, capital structure and long-term cash flow projections, the debt maturities are unlikely to be refinanced. Although management continues to explore cost reductions and other options to improve cash flow, these obligations and their impact to liquidity raise substantial doubt about FES’ ability to meet its obligations as they come due over the next twelve months and, as such, its ability to continue as a going concern. ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities, AGC, ATSI, MAIT and TrAIL 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 and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions. As a result of the Tax Act, FirstEnergy adjusted its net deferred tax liabilities at December 31, 2017, for the reduction in the corporate income tax rate from 35% to 21%. For the portions of FirstEnergy’s business that apply regulatory accounting, the impact of reducing the net deferred tax liabilities was offset with a regulatory liability, as appropriate, for amounts expected to be refunded to rate payers in future rates, with the remainder recorded to deferred income tax expense. 77 The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2017 and December 31, 2016, and the changes during the year ended December 31, 2017: Net Regulatory Assets (Liabilities) by Source December 31, 2017 December 31, 2016 Increase (Decrease) (In millions) Regulatory transition costs $ 46 $ 90 $ Customer receivables (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 (2,765) (323) (774) 187 198 258 118 329 46 468 (304) (770) 122 331 296 153 397 74 (44) (3,233) (19) (4) 65 (133) (38) (35) (68) (28) Net Regulatory Assets (Liabilities) included on the Consolidated Balance Sheets $ (2,680) $ 857 $ (3,537) Regulatory assets that do not earn a current return totaled approximately $7 million and $153 million as of December 31, 2017 and 2016, respectively, primarily related to storm damage costs, and are currently being recovered through rates. REVENUES AND RECEIVABLES Electric revenues are recorded based on energy delivered through the end of the calendar month. 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, FirstEnergy accrues the estimated unbilled amount as revenue and reverses the related prior period estimate. Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers for the Utilities, and retail and wholesale sales to customers for FES. There was no material concentration of receivables as of December 31, 2017 and 2016 with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2017 and 2016 are included below. Customer Receivables FirstEnergy FES December 31, 2017 Billed Unbilled Total December 31, 2016 Billed Unbilled Total (In millions) $ 860 603 1,463 $ $ 833 607 1,440 $ 106 75 181 123 90 213 $ $ $ $ EARNINGS (LOSS) PER SHARE OF COMMON STOCK Basic earnings per share of common stock are computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. As discussed below in "New Accounting Pronouncements," FirstEnergy adopted ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," beginning January 1, 2017. For the year ended December 31, 2017, there were no material impacts to the basic or diluted earnings per share due to the new standard. 78 Reconciliation of Basic and Diluted Earnings (Loss) per Share of Common Stock Net income (loss) 2017 2016 2015 (In millions, except per share amounts) $ (1,724) $ (6,177) $ 578 Weighted average number of basic shares outstanding Assumed exercise of dilutive stock options and awards(1) Weighted average number of diluted shares outstanding 444 — 444 426 — 426 Basic earnings (loss) per share of common stock Diluted earnings (loss) per share of common stock $ $ (3.88) $ (3.88) $ (14.49) $ (14.49) $ 422 2 424 1.37 1.37 (1) For the years ended December 31, 2017, 2016 and 2015, approximately three million, three million and one million shares were excluded from the calculation of diluted shares outstanding, respectively, as their inclusion would be antidilutive, and in the case of 2016 and 2017, a result of the net loss for the period. 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. The cost of nuclear fuel is capitalized within the CES segment's Property, plant and equipment and charged to fuel expense using the specific identification method. Property, plant and equipment balances by segment as of December 31, 2017 and 2016 were as follows: Property, Plant and Equipment In Service(1) Accum. Depr. Net Plant CWIP Total PP&E December 31, 2017 Regulated Distribution Regulated Transmission Competitive Energy Services(2) Corporate/Other Total Property, Plant and Equipment Regulated Distribution Regulated Transmission Competitive Energy Services(2) Corporate/Other Total $ $ $ $ (In millions) 25,950 $ (7,503) $ 18,447 $ 10,102 2,902 824 (2,055) (1,958) (409) 8,047 944 415 $ 469 480 28 49 18,916 8,527 972 464 39,778 $ (11,925) $ 27,853 $ 1,026 $ 28,879 In Service(1) Accum. Depr. Net Plant CWIP Total PP&E December 31, 2016 (In millions) 24,979 $ (7,169) $ 17,810 $ 9,342 8,680 766 (1,948) (6,267) (347) 7,394 2,413 419 472 383 453 43 $ 18,282 7,777 2,866 462 43,767 $ (15,731) $ 28,036 $ 1,351 $ 29,387 (1) Includes capital leases of $238 million and $244 million at December 31, 2017 and 2016, respectively. (2) Primarily consists of generating assets and nuclear fuel as discussed above. In 2017, FirstEnergy fully impaired the value of its nuclear generating assets and nuclear fuel. The major classes of Property, plant and equipment are largely consistent with the segment disclosures above, with the exception of Regulated Distribution, which has approximately $2.1 billion of regulated generation property, plant and equipment. 79 Property, plant and equipment balances for FES as of December 31, 2017 and 2016 were as follows: Property, Plant and Equipment In Service Accum. Depr. Net Plant CWIP Total PP&E December 31, 2017 (In millions) Fossil Generation Other Total $ $ 2,344 $ (1,743) $ 151 (80) 2,495 $ (1,823) $ 601 $ 71 672 $ 19 $ 3 22 $ 620 74 694 December 31, 2016 Property, Plant and Equipment In Service Accum. Depr. Net Plant CWIP Total PP&E Fossil Generation Nuclear Generation Nuclear Fuel Other Total (In millions) 2,212 $ (1,720) $ 2,065 2,637 143 (1,723) (2,418) (68) 492 342 219 75 $ 63 $ 118 241 5 555 460 460 80 7,057 $ (5,929) $ 1,128 $ 427 $ 1,555 $ $ 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 rates for FirstEnergy's and FES' electric plant in 2017, 2016 and 2015 are shown in the following table: Annual Composite Depreciation Rate 2017 2016 2015 FirstEnergy FES 2.4% 4.4% 2.5% 3.3% 2.5% 3.2% During the third quarter of 2016, FirstEnergy recorded a reduction to depreciation expense of $21 million ($19 million prior to January 1, 2016) that related to prior periods. The out-of-period adjustment related to the utilization of an accelerated useful life for a component of a certain power station. Management determined this adjustment was not material to 2016 or any prior periods. For the years ended December 31, 2017, 2016 and 2015, capitalized financing costs on FirstEnergy's Consolidated Statements of Income (Loss) include $35 million, $37 million and $49 million, respectively, of allowance for equity funds used during construction and $44 million, $66 million and $68 million, respectively, of capitalized interest. For the years ended December 31, 2017, 2016 and 2015, capitalized financing costs on FES' Consolidated Statements of Income (Loss) includes $26 million, $34 million and $35 million, respectively, of capitalized interest. Jointly Owned Plants FE, through its subsidiary, AGC, owns an undivided 40% interest (1,200 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 $531 million representing AGC's share in this facility as of December 31, 2017 of which $365 million is unregulated and included within the CES segment. AGC is obligated to pay its share of the costs of this jointly-owned facility in the same proportion as its ownership interest 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). Approximately 59% of AGC is owned by AE Supply and approximately 41% by MP. As part of FE's strategic review of its competitive operations, on January 18, 2017, AGC entered into an asset purchase agreement (which was subsequently amended and restated) with a subsidiary of LS Power to sell AE Supply's indirect interest (23.75%) in Bath County, as discussed in Note 2, "Asset Sales and Impairments." Asset Retirement Obligations FE recognizes an ARO for the future decommissioning of its nuclear power plants 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 FE'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. FE uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO, considering the expected 80 timing of settlement of the ARO based on the expected economic useful life of the plants (including the likelihood that the facilities will be deactivated before the end of their estimated useful lives). 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. 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, 2017, are described further in Note 14, "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. See Note 2, "Asset Sales and Impairments," for long-lived asset impairments recognized in 2017 and 2016. 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's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated Transmission, and CES. The following table presents goodwill by reporting unit for the year ended December 31, 2017: Goodwill Regulated Distribution Regulated Transmission Consolidated (In millions) Balance as of December 31, 2017 $ 5,004 $ 614 $ 5,618 FirstEnergy tests goodwill for impairment annually as of July 31 and considers more frequent testing if indicators of potential impairment arise. As of July 31, 2017, 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 value and a quantitative analysis was not necessary. See Note 2, "Asset Sales and Impairments," for goodwill impairment recognized in 2016 at CES. 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 held-to-maturity securities and AFS securities. At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value. Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of OTTI. The NDTs of JCP&L, ME and PN are subject to regulatory accounting with unrealized gains and losses offset against regulatory assets or liabilities. In 2017, 2016 and 2015, FirstEnergy recognized $13 million, $21 million 81 and $102 million, respectively, of OTTI. During the same periods, FES recognized OTTI of $13 million, $19 million and $90 million, respectively. The fair values of FirstEnergy’s investments are disclosed in Note 10, "Fair Value Measurements." 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. FirstEnergy 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. In 2015, Global Holding incurred losses primarily as a result of declines in coal prices due to weakening global and U.S. coal demand. Based on the significant decline in coal pricing and the outlook for the coal market, including the significant decline in the market capitalization of coal companies in 2015, FirstEnergy assessed the value of its investment in Global Holding and determined there was a decline in the fair value of the investment below its carrying value that was other than temporary, resulting in a pre-tax impairment charge of $362 million recognized in 2015. Key assumptions incorporated into the discounted cash flow analysis utilized in the impairment analysis included the discount rate, future long-term coal prices, production levels, sales forecasts, projected capital and operating costs. The impairment charge is classified as a component of Other Income (Expense) in the Consolidated Statement of Income (Loss). See Note 9, "Variable Interest Entities," for further discussion of FirstEnergy's investment in Global Holding. 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. See Note 2, "Asset Sales and Impairments," for inventory-related charges recognized in 2017. NEW ACCOUNTING PRONOUNCEMENTS Recently Adopted Pronouncements ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting" (Issued March 2016): ASU 2016-09 simplifies several aspects of the accounting for employee share-based payments. The new guidance requires all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also does not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. FirstEnergy adopted ASU 2016-09 on January 1, 2017. Upon adoption, FirstEnergy elected to account for forfeitures as they occur. The change was applied on a modified retrospective basis with a cumulative effect adjustment to retained earnings of approximately $6 million as of January 1, 2017. Additionally, FirstEnergy retrospectively applied the cash flow presentation requirement to present cash paid to tax authorities when shares are withheld to satisfy statutory tax withholding obligations as financing activities by reclassifying $12 million and $13 million from operating activities to financing activities in the 2016 and 2015 Consolidated Statements of Cash Flows, respectively. ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments" (Issued August 2016): The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments are presented and classified in the Consolidated Statements of Cash Flows, including the presentation of debt prepayment or debt extinguishment costs, all of which will be classified as financing activities. ASU 2016-15 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. FirstEnergy early adopted this ASU as of January 1, 2017. There was no impact to prior periods. Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB was not adopted in 2017. 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 and has not included these standards based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. ASU 2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to address implementation questions): The new revenue recognition guidance: establishes a new control-based revenue recognition model, changes the basis for deciding when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific topics and expands and improves disclosures about revenue. FirstEnergy has evaluated its revenues and the new guidance will have limited impacts to current revenue recognition practices upon adoption on January 1, 2018. As part of the adoption, FirstEnergy elected to apply the new guidance on a modified retrospective basis. FirstEnergy will not record a cumulative adjustment to retained earnings for initially applying the new guidance as no revenue recognition differences were identified in the timing or amount of revenue. In addition, upon adoption, certain immaterial financial statement presentation changes will be implemented. FirstEnergy expects to disaggregate revenue by type of service in future revenue disclosures. ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities" (issued January 2016): ASU 2016-01 primarily affects the accounting for equity investments, financial liabilities under the fair value option, 82 and the presentation and disclosure requirements for financial instruments. Upon adoption, January 1, 2018, FirstEnergy will recognize all gains and losses for equity securities in income with the exception of those that are accounted for under the equity method of accounting. The NDT’s equity portfolios of JCP&L, ME and PN will not be impacted as unrealized gains and losses will continue to be offset against regulatory assets or liabilities. As a result of adopting the standard, FirstEnergy and FES will record a cumulative effect adjustment to retained earnings of $115 million (pre-tax) on January 1, 2018 representing unrealized gains on equity securities that were previously recorded to AOCI. ASU 2016-02, "Leases (Topic 842)" (Issued February 2016) and ASU 2018-01,"Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842" (Issued January 2018): ASU 2016-02 will require 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. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. ASU 2018-01 (same effective date and transition requirements as ASU 2016-02) provides an optional transition practical expedient that, if elected, would not require an entity to reconsider its accounting for existing land easements that are not currently accounted for under the old leases standard. FirstEnergy does not plan to adopt these standards early. Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment. FirstEnergy expects an increase in assets and liabilities, however, it is currently assessing the impact on its Consolidated Financial Statements. This assessment includes monitoring utility industry implementation guidance. FirstEnergy is in the process of conducting outreach activities across its business units and analyzing its lease population. In addition, it has begun implementation of a third-party software tool that will assist with the initial adoption and ongoing compliance. ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (issued June 2016): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that 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. Early adoption is permitted for fiscal years beginning after December 15, 2018. ASU 2016-16, "Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory" (issued October 2016): ASU 2016-16 eliminates the exception for all intra-entity sales of assets other than inventory, which allows companies to defer the tax effects of intra-entity asset transfers. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the intra-entity transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted and the modified retrospective approach will be required for transition to the new guidance, with a cumulative- effect adjustment recorded in retained earnings as of the beginning of the period of adoption. FirstEnergy will not be impacted upon its adoption of this ASU on January 1, 2018. ASU 2016-18, "Restricted Cash" (issued November 2016): ASU 2016-18 addresses the presentation of changes in restricted cash and restricted cash equivalents in the statement of cash flows. The guidance is required to be applied retrospectively. In its first quarter 2018 Form 10-Q, FirstEnergy will show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. In addition, FirstEnergy will disclose the nature of its restricted cash and restricted cash equivalent balances within the footnotes. ASU 2017-01, "Business Combinations: Clarifying the Definition of a Business" (Issued January 2017): ASU 2017-01 assists entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. The ASU will be applied prospectively to any transactions occurring within the period of adoption. FirstEnergy will not early adopt this standard. ASU 2017-07, "Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" (Issued March 2017): ASU 2017-07 requires entities to retrospectively (1) disaggregate the current- service-cost component from the other components of net benefit cost (the “other components”) and present it with other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations if such a subtotal is presented. As a result of the retrospective presentation, FirstEnergy will reclassify approximately $62 million of non-service costs, excluding the annual mark-to-market, to Other Income/ Expense related to the fiscal year 2017 within the 2018 financial statements. In addition, ASU 2017-07 requires service costs to be capitalized as appropriate and non-service costs to be charged to earnings. FirstEnergy will present non-service costs in the caption “Miscellaneous Income” with the exception of the annual mark-to-market adjustment which will be disclosed separately. ASU 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income" (Issued February 2018): ASU 2018-02 allows entities to reclassify from AOCI to retained earnings stranded tax effects resulting from the Tax Act. ASU 2018-02 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2018. Early adoption of the ASU is permitted including adoption in any interim period. ASU 2018-02 should be applied either in the period of 83 adoption or retrospectively to each period (or periods) in which the effect of the income tax rate change resulting from the Tax Act is recognized. FirstEnergy did not adopt this ASU as of December 31, 2017. 2. ASSET SALES AND IMPAIRMENTS YEAR ENDED DECEMBER 31, 2017 Early Retirement of Nuclear Generating Assets As previously disclosed, FirstEnergy announced a strategic review to exit commodity-exposed generation at CES, which included one or more of the following options: • • • • legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits, restructuring FES' debt with its creditors, seeking protection under U.S. bankruptcy laws for FES and likely FENOC, and/or asset sales and/or plant deactivations. As part of the strategic review, FES evaluated its options with respect to its nuclear power plants. Factors considered as part of this review included current and forecasted market conditions, such as wholesale power and capacity prices, legislative and regulatory solutions that recognize their environmental and energy security benefits, and many other factors, including the significant capital and operating costs associated with operating a safe and reliable nuclear fleet. Based on this analysis, given the weak power and capacity price environment and the lack of legislative and regulatory solutions achieved to date, FES concluded that it would be increasingly difficult to operate these facilities in this environment and absent significant change concluded that it was probable that the facilities would be either deactivated or sold before the end of their estimated useful lives. As a result, FES recorded a pre- tax charge of $2.0 billion in the fourth quarter of 2017 to fully impair the nuclear facilities, including the generating plants and nuclear fuel as well as to reserve against the value of materials and supplies inventory and to increase its asset retirement obligation. The charges consisted of the following: (In millions) Pre-tax charge Nuclear generating asset Beaver Valley Davis Besse Perry Nuclear fuel Materials and supplies Asset retirement obligation Total non-cash charges $ $ 107 420 124 369 81 944 2,045 The fair value analysis for the generating assets was based on the income approach, a discounted cash flow method, to determine the amount of the impairment. Key assumptions used in determining the pre-tax non-cash charge included forward power and capacity price projections, the expected economic useful life of the plants (including the likelihood that the facilities will be deactivated before the end of their estimated useful lives), the timing of decommissioning activities, and operating and capital costs, all of which are subject to a high degree of judgment and complexity. In addition to these one-time non-cash impairment charges, there will be ongoing charges to earnings primarily related to ongoing capital and nuclear fuel spend, as well as additional ARO accretion expense. Pleasants Power Station On March 6, 2017, AE Supply and MP entered into an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station (1,300 MWs) for approximately $195 million, resulting from an RFP issued by MP to address its generation shortfall. On January 12, 2018, FERC issued an order denying authorization for the transaction, holding that MP and AE Supply did not demonstrate the sale was consistent with the public interest and the transaction did not fall within the safe harbors for meeting FERC’s affiliate cross-subsidization analysis. On January 26, 2018, the WVPSC approved the transfer of Pleasants, subject to certain conditions as further described below, which included MP assuming significant commodity risk. Based on the FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement and on February 16, 2018, AE Supply announced its intent to exit operations of the Pleasants Power Station by January 1, 2019, through either sale or deactivation, which resulted in a pre-tax impairment charge of $120 million in the fourth quarter of 2017 to reduce the carrying value to $75 million. 84 Competitive Generation Asset Sale FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement with a subsidiary of LS Power, 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) for an all-cash purchase price of $825 million, subject to adjustments and through multiple, independent closings. On December 13, 2017, AE Supply completed the sale of the natural gas generating plants with net proceeds, subject to post-closing adjustments, of approximately $388 million. The sale of AE Supply's interests in the Bath County hydroelectric power station and the Buchanan Generating facility is expected to generate net proceeds of $375 million and is anticipated to close in the first half of 2018, subject in each case to various customary and other closing conditions, including, without limitation, receipt of regulatory approvals. As part of the closing of the natural gas generating plants, FE provided the purchaser two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC arising under the amended and restated purchase agreement. With the sale of the gas plants completed, upon the consummation of the sale of AGC's interest in the Bath County hydroelectric power station or the sale or deactivation of the Pleasants Power Station, AE Supply is obligated under the amended and restated purchase agreement and AE Supply's applicable debt agreements to satisfy and discharge approximately $305 million of currently outstanding senior notes, as well as its $142 million of pollution control notes and AGC's $100 million senior notes, which are expected to require the payment of "make-whole" premiums currently estimated to be approximately $95 million based on current interest rates. On October 20, 2017, the parties filed an application with the VSCC for approval of the sale of approximately 59% of AGC's interest in the Bath County hydroelectric power station. On December 12, 2017, FERC issued an order authorizing the partial transfer of the related hydroelectric license for Bath County under Part I of the FPA. In December 2017, AGC, AE Supply and MP filed with FERC and AGC and AE Supply filed with the VSCC, applications for approval of AGC redeeming AE Supply’s shares in AGC upon consummation of the Bath County transaction. On February 2, 2018, the VSCC issued an order finding that approval of the proposed stock redemption is not required, and on February 16, 2018, FERC issued an order authorizing the redemption. Upon the consummation of the redemption, AGC will become a wholly-owned subsidiary of MP. On December 28, 2017, FERC issued an order authorizing the sale of BU Energy’s Buchanan interests. Additional filings have been submitted to FERC for the purpose of amending affected FERC-jurisdictional rates and implementing the transaction once the sales are consummated. There can be no assurance that all regulatory approvals will be obtained and/or all closing conditions will be satisfied or that the remaining transactions will be consummated. As a result of the amended asset purchase agreement, CES recorded non-cash pre-tax impairment charges of $193 million in 2017, reflecting the $825 million purchase price as well as certain purchase price adjustments based on timing of the closing of the transaction. Assets held for sale related to this transaction as of December 31, 2017, include property, plant and equipment (net of accumulated provision for depreciation) of $354 million, investments of $19 million, and materials and supplies inventory of $2 million. Transmission Formula Rate Settlements As described in Note 15, "Regulatory Matters," on October 13, 2017, MAIT and certain parties filed a settlement agreement with FERC, which is subject to a final order. As a result of the settlement agreement, MAIT recorded a pre-tax impairment charge of $13 million in the third quarter of 2017. As described in Note 15, "Regulatory Matters," on December 21, 2017, JCP&L and certain parties filed a settlement agreement with FERC, which is subject to a final order. As a result of the settlement agreement, JCP&L recorded a pre-tax impairment charge of $28 million in the fourth quarter of 2017. YEAR ENDED DECEMBER 31, 2016 Competitive Generation Deactivations and Other Exit Activities On July 22, 2016, FirstEnergy and FES announced its intent to exit operations of the Bay Shore Unit 1 generating station (136 MWs) by October 1, 2020, through either sale or deactivation and to deactivate Units 1-4 of the W. H. Sammis generating station (720 MWs) by May 31, 2020. As a result, FirstEnergy recorded a non-cash pre-tax impairment charge of $647 million ($517 million - FES) in the second quarter of 2016. PJM and the Independent Market Monitor have approved the W.H. Sammis Units 1-4 and Bay Shore Unit 1 deactivations. In addition, FirstEnergy and FES recorded termination and settlement costs on fuel contracts of approximately $58 million (pre-tax) in the second quarter of 2016 resulting from plant retirements and deactivations, which is included in the caption of Fuel in the Consolidated Statement of Income (Loss). 85 As disclosed in Note 1, "Organization and Basis of Presentation," in November 2016, FirstEnergy announced a strategic review to exit its commodity-exposed generation as it transitions to a fully regulated utility. As part of assessing the viability of strategic alternatives, FirstEnergy determined that the carrying value of long-lived assets of the competitive business were not recoverable, specifically given FirstEnergy’s target to implement its exit from competitive operations by mid-2018, significantly before the end of the original useful lives, and the anticipated cash flows over this shortened period. As a result, CES recorded a non-cash pre-tax impairment charge of $9,218 million ($8,082 million at FES) in the fourth quarter of 2016 to reduce the carrying value of certain assets to their estimated fair value, including long-lived assets, such as generating plants and nuclear fuel, as well as other assets, such as materials and supplies. Key assumptions used in determining the impairment charges of long-lived assets included forward power price projections, the expected duration of ownership of the plants, environmental compliance costs and strategies, operating costs, and estimated sale proceeds. Those same cash flow assumptions, along with a discount rate were used to estimate the fair value of each plant. These assumptions are subject to a high degree of judgment and complexity. The fair value estimate of these long-lived assets was based on a combination of the income approach, which considers discounted cash flows, and corroboration with the market approach, which considers market comparisons for similar assets within the electric generation industry. Goodwill As a result of low capacity prices associated with the 2019/2020 PJM Base Residual Auction in May 2016, as well as its annual update to its fundamental long-term capacity and energy price forecast, FirstEnergy determined that an interim impairment analysis of the CES reporting unit’s goodwill was necessary during the second quarter of 2016. Consistent with FirstEnergy’s annual goodwill impairment test, a discounted cash flow analysis was used to determine the fair value of the CES reporting unit for purposes of step one of the interim goodwill impairment test. Key assumptions incorporated into the CES discounted cash flow analysis requiring significant management judgment included the following: • Future Energy and Capacity Prices: Observable market information for near-term forward power prices, PJM auction results for near term capacity pricing, and a longer-term fundamental pricing model for energy and capacity that considered the impact of key factors such as load growth, plant retirements, carbon and other environmental regulations, and natural gas pipeline construction, as well as coal and natural gas pricing. • Retail Sales and Margin: CES' current retail targeted portfolio to estimate future retail sales volume as well as historical financial results to estimate retail margins. • Operating and Capital Costs: Estimated future operating and capital costs, including the estimated impact on costs of pending carbon and other environmental regulations, as well as costs associated with capacity performance reforms in the PJM market. • Discount Rate: A discount rate of 9.50%, based on selected comparable companies' capital structure, return on debt and • return on equity. Terminal Value: A terminal value of 7.0x earnings before interest, taxes, depreciation and amortization based on consideration of peer group data and analyst consensus expectations. Based on the impairment analysis, FirstEnergy determined that the carrying value of goodwill exceeded its fair value and recognized a non-cash pre-tax impairment charge of $800 million ($23 million - FES) in the second quarter of 2016, which is included in Impairment of assets and related charges in the Consolidated Statement of Income (Loss). YEAR ENDED DECEMBER 31, 2015 During 2015, FirstEnergy and FES recognized impairment charges of $42 million and $33 million, respectively, associated with certain transportation equipment and facilities. In order to conform to current year presentation, the charges were reclassified from Other operating expenses in the Consolidated Statement of Income (Loss) to Impairment of assets and related charges. The impairment charges are included within the Regulated Distribution segment ($8 million) and the CES segment ($34 million). 86 3. ACCUMULATED OTHER COMPREHENSIVE INCOME The changes in AOCI for the years ended December 31, 2017, 2016 and 2015 for FirstEnergy are shown in the following table: FirstEnergy Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2015 $ (37) $ 25 $ 258 $ 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 — 5 5 1 4 14 (25) (11) (4) (7) 10 (126) (116) (44) (72) AOCI Balance, December 31, 2015 $ (33) $ 18 $ 186 $ 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 — 8 8 3 5 106 (51) 55 21 34 13 (72) (59) (23) (36) AOCI Balance, December 31, 2016 $ (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) 246 24 (146) (122) (47) (75) 171 119 (115) 4 1 3 174 74 (127) (53) (21) (32) AOCI Balance, December 31, 2017 $ (22) $ 67 $ 97 $ 142 87 The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2017, 2016 and 2015: FirstEnergy Reclassifications from AOCI (2) Gains & losses on cash flow hedges Commodity contracts Long-term debt Unrealized gains on AFS securities Realized gains on sales of securities Defined benefit pension and OPEB plans Prior-service costs Year Ended December 31 2017 2016 2015 Affected Line Item in Consolidated Statements of Income (Loss) (In millions) $ $ $ $ $ $ 2 8 10 (4) $ — $ (3) Other operating expenses 8 8 (3) 8 Interest expense 5 Total before taxes (1) Income taxes (benefits) 6 $ 5 $ 4 Net of tax (63) $ (51) $ (25) Investment income (loss) 23 19 9 Income taxes (benefits) (40) $ (32) $ (16) Net of tax (74) $ (72) $ (126) (1) 28 27 49 Income taxes (benefits) (46) $ (45) $ (77) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 4, "Pension and Other Postemployment Benefits," for additional details. (2) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. 88 The changes in AOCI for the years ended December 31, 2017, 2016 and 2015 for FES are shown in the following table: FES Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2015 $ (7) $ 21 $ 43 $ Other comprehensive income before reclassifications Amounts reclassified from AOCI Other comprehensive loss Income tax benefits on other comprehensive loss Other comprehensive loss, net of tax — (3) (3) (1) (2) 15 (24) (9) (4) (5) 10 (16) (6) (2) (4) AOCI Balance, December 31, 2015 $ (9) $ 16 $ 39 $ 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 — — — — — 100 (48) 52 20 32 — (14) (14) (5) (9) AOCI Balance, December 31, 2016 $ (9) $ 48 $ 30 $ 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 1 1 91 (61) 30 10 20 — (14) (14) (5) (9) AOCI Balance, December 31, 2017 $ (8) $ 68 $ 21 $ 57 25 (43) (18) (7) (11) 46 100 (62) 38 15 23 69 91 (73) 18 6 12 81 89 The following amounts were reclassified from AOCI for FES in the years ended December 31, 2017, 2016 and 2015: FES Reclassifications from AOCI (2) Gains & losses on cash flow hedges Commodity contracts Unrealized gains on AFS securities Realized gains on sales of securities Defined benefit pension and OPEB plans Prior-service costs Year Ended December 31 2017 2016 2015 (In millions) Affected Line Item in Consolidated Statements of Income (Loss) $ $ $ $ $ $ 2 $ — $ (3) Other operating expenses (1) — 1 Income taxes (benefits) 1 $ — $ (2) Net of tax (61) $ (48) $ (24) Investment income (loss) 23 18 9 Income taxes (benefits) (38) $ (30) $ (15) Net of tax (14) $ (14) $ (16) (1) 5 5 6 Income taxes (benefits) (9) $ (9) $ (10) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 4, "Pension and Other Postemployment Benefits," for additional details. (2) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. 4. 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. 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, 2017, 2016, and 2015 were $141 million, $147 million, and $242 million, respectively. In 2017, the pension and OPEB mark-to-market adjustment primarily reflects a 50 bps decrease in the discount rate used to measure benefit obligations, partially offset by higher than expected asset returns. FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. In 2016, FirstEnergy satisfied its minimum required funding obligations of $382 million and addressed 2017 funding obligations to its qualified pension plan with total contributions of $882 million (of which $138 million was cash contributions from FES), including $500 million of FE common stock contributed to the qualified pension plan on December 13, 2016. In January 2018, FirstEnergy satisfied its minimum required funding obligations of $500 million and addressed funding obligations for future years to its qualified pension plan with additional contributions of $750 million. 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. 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 2017, FirstEnergy’s qualified pension and OPEB plan assets experienced gains of $999 million, or 15.1%, compared to gains of $472 million, or 8.2%, in 2016 and losses of $(172) million, or (2.7)%, in 2015, and 90 assumed a 7.50% rate of return for 2017 and 2016 and a 7.75% rate of return for 2015 on plan assets which generated $478 million, $429 million and $476 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 increase or decrease 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 2017, the Society of Actuaries released its updated mortality improvement scale for pension plans, MP-2017, incorporating three additional years of SSA data on U.S. population mortality. MP-2017 incorporates SSA mortality data from 2013 to 2015 and a slight modification of two input values designed to improve the model’s year-over-year stability. The updated improvement scale indicates a slight decline in life expectancy. Due to the additional years of data on population mortality, the RP2014 mortality table with the projection scale MP-2017 was utilized to determine the 2017 benefit cost and obligation as of December 31, 2017 for the FirstEnergy pension and OPEB plans. The impact of using the projection scale MP-2017 resulted in a decrease in the projected pension benefit obligation of $62 million and was included in the 2017 pension and OPEB mark-to-market adjustment. 91 Obligations and Funded Status - Qualified and Non-Qualified Plans 2017 2016 2017 2016 Pension OPEB Change in benefit obligation: Benefit obligation as of January 1 Service cost Interest cost Plan participants’ contributions Plan amendments Medicare retiree drug subsidy Actuarial 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 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 Accumulated benefit obligation Amounts Recognized on the Balance Sheet: Noncurrent assets Current liabilities Noncurrent liabilities 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 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 Bonds Absolute return strategies Real estate funds Private equity funds Cash and short-term securities Total 92 (In millions) $ 9,426 $ 9,079 $ 711 $ 724 208 390 — 11 — 610 (478) 10,167 6,213 950 18 — (477) 6,704 (3,043) (420) (3,463) 9,583 $ $ $ $ $ $ — $ (19) (3,444) (3,463) $ 191 398 — — — 224 (466) 9,426 5,338 442 899 — (466) 6,213 (2,821) (392) (3,213) 8,913 9 (19) (3,203) (3,213) 32 $ 28 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 5 27 4 — 1 32 (49) 731 420 49 16 4 (50) 439 $ $ $ 5 30 5 (13) 1 14 (55) 711 431 30 9 5 (55) 420 (292) $ (291) — $ — — $ — (292) (292) $ — — (291) (291) (206) $ (288) 3.75% 4.20% 4.25% 4.20% 3.50% N/A 4.00% N/A N/A N/A N/A 42% 32% 10% 9% 1% 6% 100% N/A N/A N/A 44% 30% 8% 10% —% 8% 100% 6.0-5.5% 6.0-5.5% 4.5% 2028 50% 33% —% —% —% 17% 100% 4.5% 2027 53% 41% —% —% —% 6% 100% Components of Net Periodic Benefit Costs 2017 2016 2015 2017 Pension OPEB 2016 2015 Service cost Interest cost Expected return on plan assets Amortization of prior service cost (credit) Pension & OPEB mark-to-market adjustment Net periodic benefit cost (credit) (In millions) $ $ 208 390 (448) 7 108 265 $ $ 191 398 (399) 8 179 377 $ $ 193 383 (443) 8 344 485 $ 5 $ 5 $ 27 (30) (81) 13 30 (30) (80) 15 5 29 (33) (134) 25 $ (66) $ (60) $ (108) Assumptions Used to Determine Net Periodic Benefit Cost * for Years Ended December 31 Weighted-average discount rate Expected long-term return on plan assets Rate of compensation increase Pension 2017 2016 2015 2017 4.25% 7.50% 4.20% 4.50% 7.50% 4.20% 4.25% 7.75% 4.20% 4.00% 7.50% N/A OPEB 2016 4.25% 7.50% N/A 2015 4.00% 7.75% N/A *Excludes impact of pension and OPEB mark-to-market adjustment. 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. 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 2017 and 2016. December 31, 2017 Level 1 Level 2 Level 3 Total Asset Allocation (In millions) Cash and short-term securities $ — $ 379 $ — $ 379 Equity investments Domestic International Fixed income Government bonds Corporate bonds High yield debt Mortgage-backed securities (non- government) Alternatives Hedge funds (Absolute return) Derivatives Real estate funds Total (1) Private equity funds (2) Total Investments 695 514 — — — — — — — 27 1,569 251 1,237 689 31 635 (1) — $ 1,209 $ 4,817 $ — — — — — — — — 631 631 $ $ 722 2,083 251 1,237 689 31 635 (1) 631 6,657 57 (1) Excludes $(10) million as of December 31, 2017, 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. 93 6,714 100 % 6 % 11 % 31 % 4 % 18 % 10 % — % 10 % — % 9 % 99 % 1 % December 31, 2016 Level 1 Level 2 Level 3 Total Asset Allocation (In millions) Cash and short-term securities $ — $ 464 $ — $ 464 Equity investments Domestic (1) International Fixed income Government bonds Corporate bonds High yield debt Mortgage-backed securities (non- government) Alternatives Hedge funds (Absolute return) Derivatives Real estate funds Total (2) Private equity funds (3) Total Investments 1,048 422 — — — — — — — 13 1,269 106 1,245 372 112 500 (1) — $ 1,470 $ 4,080 $ — — — — — — — — 615 615 $ $ 1,061 1,691 106 1,245 372 112 500 (1) 615 6,165 33 6,198 8% 17% 27% 2% 20% 6% 2% 8% —% 10% 100% —% 100% (1) As a result of the $500 million equity contribution on December 13, 2016, there was $293 million of FE Stock included in the pension plan assets as of December 31, 2016. (2) Excludes $16 million as of December 31, 2016, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (3) Net asset value used as a practical expedient to approximate fair value. The following table provides a reconciliation of changes in the fair value of pension investments classified as Level 3 in the fair value hierarchy during 2017 and 2016: Balance as of January 1, 2016 Actual return on plan assets: Unrealized gains Realized gains (losses) Transfers in Balance as of December 31, 2016 Actual return on plan assets: Unrealized gains Realized gains Transfers in (out) Balance as of December 31, 2017 Real Estate Funds $ $ $ 587 29 14 (15) 615 3 10 3 631 94 As of December 31, 2017 and 2016, the OPEB trust investments measured at fair value were as follows: December 31, 2017 Level 1 Level 2 Level 3 Total Asset Allocation (In millions) Cash and short-term securities $ — $ 75 $ — $ Equity investment Domestic Fixed income Government bonds Corporate bonds Mortgage-backed securities (non- government) Total (1) 220 — — — 109 34 3 — — — — $ 220 $ 221 $ — $ 75 220 109 34 3 441 17% 50% 24% 8% 1% 100% (1) Excludes $(2) million as of December 31, 2017, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. December 31, 2016 Level 1 Level 2 Level 3 Total Asset Allocation (In millions) Cash and short-term securities $ — $ 27 $ — $ Equity investment Domestic Fixed income U.S. treasuries Government bonds Corporate bonds Mortgage-backed securities (non- government) Total (1) 223 — — — — — 40 108 24 2 — — — — — $ 223 $ 201 $ — $ 27 223 40 108 24 2 424 6% 53% 9% 26% 6% —% 100% (1) Excludes $(4) million as of December 31, 2016, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. 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 2017 and 2016 are shown in the following table: Target Asset Allocations Equities Fixed income Absolute return strategies Real estate Alternative investments Cash 95 38% 30% 8% 10% 8% 6% 100% Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage- point change in assumed health care cost trend rates would have the following effects: Effect on total of service and interest cost Effect on accumulated benefit obligation $ $ 1-Percentage- Point Increase 1-Percentage- Point Decrease (In millions) 1 21 $ $ (1) (18) 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: Pension OPEB Subsidy Receipts Benefit Payments (In millions) $ 2018 2019 2020 2021 2022 Years 2023-2027 $ 518 531 552 567 581 3,056 $ 55 54 53 53 52 241 (1) (1) (1) (1) (1) (3) FES’ share of the pension and OPEB net (liability) asset as of December 31, 2017 and 2016, was as follows: Pension OPEB 2017 2016 2017 2016 (In millions) Net (Liability) Asset(1) $ (97) $ (158) $ 40 $ 36 (1) Excludes $954 million and $866 million as of December 31, 2017 and 2016, respectively, of affiliated non-current liabilities related to pension and OPEB mark-to-market costs allocated to FES of which $626 million and $570 million, respectively, are from FENOC. FES’ share of the net periodic benefit cost (credit), including the pension and OPEB mark-to-market adjustment, for the three years ended December 31, 2017, was as follows: Pension 2017 2016 2015 2017 (In millions) OPEB 2016 2015 Net Periodic Cost (Credit) $ 60 $ (5) $ 10 $ (17) $ (26) $ (22) 5. 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, 2017, approximately 6 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 used under the ICP 2007 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods 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. Beginning in 2017, based upon the adoption of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," FE has elected to account 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 96 awards are exercised or settled. Actual income tax benefits realized during the years ended December 31, 2017, 2016 and 2015 were $15 million, $13 million and $10 million, respectively. The income tax effects of awards are recognized in the income statement when the awards vest or are settled. Stock-based compensation costs and the amount of stock-based compensation expense capitalized related to FirstEnergy and FES plans are included in the following tables: FirstEnergy Stock-based Compensation Plan Restricted Stock Units Restricted Stock Performance Shares 401(k) Savings Plan EDCP & DCPD Total Stock-based compensation costs capitalized FES Stock-based Compensation Plan Restricted Stock Units 401(k) Savings Plan Total Stock-based compensation costs capitalized Years Ended December 31 2017 2016 (In millions) 2015 $ 49 $ 62 $ 1 — 42 6 98 37 2 (3) 39 5 $ $ 105 38 $ $ Years Ended December 31 2017 2016 (In millions) 2015 4 3 7 1 $ $ $ 11 $ 5 16 2 $ $ $ $ $ $ $ 46 2 — 38 3 89 32 6 5 11 1 Outstanding stock options were fully amortized as of December 31, 2016. Stock option expense was not material for FirstEnergy or FES for the years December 31, 2016 and 2015. Income tax benefits associated with stock based compensation plan expense were $10 million, $14 million and $12 million (FES - $1 million, $2 million and $2 million) for the years ended 2017, 2016 and 2015, respectively. Restricted Stock Units Beginning with the performance-based restricted stock units granted in 2015, two-thirds will be paid in stock and one-third will be paid in cash. All performance-based restricted stock units granted prior to 2015 were payable in stock. 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. 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. 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 cash performance-based restricted stock units as of December 31, 2017 was $41 million. During 2017, restricted stock unit award agreements for certain employees were amended such that the two-thirds originally designated to be paid in stock will be paid in cash. These awards are included within the cash performance-based restricted stock unit liability. No cash was paid to settle the restricted stock unit obligations in 2017. The vesting period for each of the awards was 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. 97 Restricted stock unit activity for the year ended December 31, 2017, was as follows: Restricted Stock Unit Activity Shares Weighted- Average Grant Date Fair Value Nonvested as of January 1, 2017 Granted in 2017 Forfeited in 2017 Vested in 2017(1) Nonvested as of December 31, 2017 3,063,729 $ 1,577,844 (169,012) (1,156,810) 3,315,751 $ 32.98 31.71 32.66 30.81 33.24 (1) Excludes dividend equivalents of 159,274 shares earned during vesting period. The weighted-average fair value of awards granted in 2017, 2016 and 2015 was $31.71, $34.77 and $35.27, respectively. For the years ended December 31, 2017, 2016, and 2015, the fair value of restricted stock units vested was $42 million, $36 million, and $22 million, respectively. As of December 31, 2017, there was $33 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted for restricted stock units; that cost 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 FirstEnergy common stock on the date of grant. Dividends are received on the restricted stock and are reinvested in additional shares of restricted stock. Restricted common stock (restricted stock) activity for the year ended December 31, 2017, 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 2017. Stock option activity during 2017 was as follows: Stock Option Activity Balance, January 1, 2017 (1,376,821 options exercisable) Options forfeited Balance, December 31, 2017 (1,366,875 options exercisable) Number of Shares Weighted Average Exercise Price 1,376,821 $ (9,946) 1,366,875 $ 44.60 70.60 44.41 There was no cash received from the exercise of stock options in 2017 and 2016. Cash received from the exercise of stock options in 2015 was not material. The weighted-average remaining contractual term of options outstanding as of December 31, 2017, was 1.67 years. Performance Shares Prior to the 2015 grant of performance-based restricted stock units discussed above, the Company granted performance shares. Performance shares are share equivalents and do not have voting rights. The performance shares outstanding track the performance of FE's common stock over a three-year vesting period. Dividend equivalents accrue on performance shares and are reinvested into additional performance shares with the same performance conditions. The final account value may be adjusted based on the ranking of FE stock performance to a composite of peer companies. In 2016, $2 million cash was paid to settle performance shares that vested over the 2013-2015 performance cycle. In 2017, no cash was paid to settle performance shares that vested over the 2014-2016 performance cycle. FirstEnergy no longer has outstanding performance share awards. 401(k) Savings Plan In 2017 and 2016, 1,304,863 and 1,159,215 shares of FE common stock, respectively, were issued and contributed to participants' accounts. 98 EDCP Under the EDCP, covered 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 can 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, Short-Term 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 the Board of Directors can elect to allocate all or a portion of their equity retainers to deferred stock and their cash retainers, meeting fees and chair fees to deferred stock or deferred cash accounts. The net liability recognized for DCPD of approximately $8 million and $7 million as of December 31, 2017 and December 31, 2016, respectively, is included in the caption “Retirement benefits,” on the Consolidated Balance Sheets. 6. 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 are party to an intercompany income tax allocation agreement that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, are 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. On December 22, 2017, the President signed into law the Tax Act. Substantially all of the provisions of the Tax Act are effective for taxable years beginning after December 31, 2017. The Tax Act includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated public utilities including FirstEnergy’s regulated distribution and transmission subsidiaries. The more significant changes that impact FirstEnergy included in the Tax Act are the following: • 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; 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. The most significant change that impacts FirstEnergy in the current year is the reduction of the corporate federal income tax rate. Other provisions are not expected to have a significant impact on the financial statements, but may impact the effective tax rate in future years. Under US GAAP, specifically ASC Topic 740, Income Taxes, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted, or December 22, 2017, for the Tax Act. ASC 740 also requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Thus, at the date of enactment, FirstEnergy’s deferred taxes were re-measured based upon the new tax rate, which resulted in a material decrease to FirstEnergy’s net deferred income tax liabilities. For FirstEnergy’s unregulated operations, the change in deferred taxes are recorded as an adjustment to FirstEnergy’s deferred income tax provision. FirstEnergy’s regulated entities recorded a corresponding net regulatory liability to the extent the change in deferred taxes would result in amounts previously collected from utility customers to be subject to refunds to such customers, generally through reductions in future rates. All other amounts were recorded as an adjustment to FirstEnergy’s regulated entities’ deferred income tax provision. FirstEnergy has completed its assessment of the accounting for certain effects of the provisions in the Tax Act, and as allowed under SEC Staff Accounting Bulletin 118 (SAB 118), has recorded provisional income tax amounts as of December 31, 2017 related to depreciation for which the impacts of the Tax Act could not be finalized, but for which a reasonable estimate could be determined. 99 Under the new law, property acquired and placed into service after September 27, 2017, will be eligible for full expensing for all taxpayers other than regulated utilities. As a result, FirstEnergy will need to evaluate the contractual terms of its capital expenditures to determine eligibility for full expensing. As of December 31, 2017, FirstEnergy has not yet completed this analysis, but has recorded a reasonable estimate of the effects of these changes based on capital costs incurred prior to year-end. In addition, SAB 118 allows for a measurement period for companies to finalize the provisional amounts recorded as of December 31, 2017. FirstEnergy expects to record any final adjustments to the provisional amounts by the fourth quarter of 2018, which could result in a material impact to FirstEnergy’s income tax provision or financial position. FirstEnergy’s assessment of accounting for the Tax Act are based upon management’s current understanding of the Tax Act. However, it is expected that further guidance will be issued during 2018, which may result in adjustments that could have a material impact to FirstEnergy’s future results of operations, cash flows, or financial position. As a result of the Tax Act, FirstEnergy recognized a non-cash charge to income tax expense of $1.2 billion (FES - $1.1 billion) and resulted in excess deferred taxes of $2.3 billion for the regulated business, of which the revenue impact was recorded as a regulatory liability. These adjustments had no impact on our 2017 cash flows. INCOME TAXES (BENEFITS) 2017 2016 2015 FirstEnergy Currently payable (receivable)- Federal State Deferred, net- Federal State Investment tax credit amortization Total provision for income taxes (benefits) FES Currently payable (receivable)- Federal State Deferred, net- Federal State Investment tax credit amortization $ $ $ (In millions) $ (1) $ 9 8 (3,114) 59 (3,055) (8) 14 42 56 876 (29) 847 (8) 895 $ (3,055) $ (159) $ (67) $ (1) (160) 509 (52) 457 (2) (1) (68) (2,861) (57) (2,918) (2) Total provision for income taxes (benefits) $ 295 $ (2,988) $ 1 30 31 277 15 292 (8) 315 (56) 2 (54) 103 18 121 (2) 65 100 FirstEnergy and FES 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 three years ended December 31: 2017 2016 2015 (In millions) FirstEnergy Income (loss) before income taxes (benefits) Federal income tax expense (benefit) at statutory rate (35%) $ $ (829) (290) $ $ (9,232) (3,231) $ $ 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 Change in accounting method ESOP dividend Impairment of non-deductible goodwill Remeasurement of deferred taxes Uncertain tax positions Valuation allowances Other, net Total income taxes (benefits) Effective income tax rate FES Income (loss) before income taxes (benefits) Federal income tax expense (benefit) at statutory rate (35%) Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit Amortization of investment tax credits ESOP dividend Impairment of non-deductible goodwill Remeasurement of deferred taxes Uncertain tax positions Valuation allowances Other, net Total income taxes (benefits) Effective income tax rate (4) (15) (8) — (6) — 1,193 (3) 29 (1) (192) (13) (8) — (6) 157 — (16) 246 8 893 313 17 (16) (8) (8) (6) — — 1 18 4 $ $ $ 895 $ (3,055) $ (108.0)% 33.1% 315 35.3% (2,096) (734) $ $ (8,443) (2,955) $ $ 147 51 (52) (2) — — 1,067 — 18 (2) (188) (2) (1) 9 — (8) 151 6 $ 295 $ (2,988) $ 2 (2) (1) — — 5 14 (4) 65 (14.1)% 35.4% 44.2% Absent the impact from the Tax Act, discussed above, FirstEnergy’s effective tax rate on pre-tax losses for 2017 and 2016 was 35.9% and 33.1%, respectively. The change in the effective tax rate resulted primarily from the absence of 2016 charges, including $246 million of valuation allowances recorded against state and local deferred tax assets, that management believes, more likely than not, will not be realized, as well as the impairment of $800 million of goodwill, of which $433 million was non-deductible for tax purposes. Absent the impact from the Tax Act, discussed above, FES’ 2017 effective tax rate on pre-tax losses for 2017 and 2016 was 36.8%, and 35.4%, respectively. The change in the effective tax resulted primarily from the absence of $151 million of valuation allowances recorded against state and local deferred tax assets, that management believes, more likely than not, will not be realized, as well as the impairment of $23 million of goodwill, which was non-deductible for tax purposes. 101 Accumulated deferred income taxes as of December 31, 2017 and 2016, are as follows: FirstEnergy Property basis differences Deferred sale and leaseback gain Pension and OPEB Nuclear decommissioning activities Asset retirement obligations Regulatory asset/liability Deferred compensation Nuclear Fuel Loss carryforwards and AMT credits Valuation reserve All other Net deferred income tax liability FES Property basis differences Deferred sale and leaseback gain Pension and OPEB Lease market valuation liability Nuclear decommissioning activities Asset retirement obligations Nuclear Fuel Loss carryforwards and AMT credits Valuation reserve All other Net deferred income tax asset 2017 2016 (In millions) 3,662 (231) (952) 450 (453) 416 (177) (375) (1,467) 580 (94) 1,359 $ $ (677) $ (219) (244) 75 411 (296) (375) (587) 268 (110) (1,754) $ 7,088 (351) (1,347) 635 (669) 545 (269) (90) (2,251) 438 36 3,765 (1,009) (328) (366) 111 540 (453) (90) (830) 197 (51) (2,279) $ $ $ $ FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state taxing authorities. FirstEnergy's tax returns for all state jurisdictions are open from 2009-2016. In February 2017, the IRS completed its examination of FirstEnergy's 2015 federal income tax return and issued a Full Acceptance Letter with no changes or adjustments to FirstEnergy's taxable income. In August 2017, the IRS substantially completed its examination of FirstEnergy’s 2016 federal income tax return and, on January 18, 2018, issued a Full Acceptance Letter with no changes or adjustments to FirstEnergy’s taxable income. FirstEnergy and FES have 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, 2017, FirstEnergy's loss carryforwards and AMT credits consisted of $4.3 billion ($908 million, net of tax) of Federal NOL carryforwards that will begin to expire in 2031 and Federal AMT credits of $39 million that have an indefinite carryforward period. As of December 31, 2017, FES' loss carryforwards consisted of $2.0 billion ($429 million, net of tax) of Federal NOL carryforwards that will begin to expire in 2031. The table below summarizes pre-tax NOL carryforwards for state and local income tax purposes of approximately $10.5 billion ($496 million, net of tax) for FirstEnergy, of which approximately $1.8 billion ($81 million, net of tax) is expected to be utilized based on current estimates and assumptions. FES’ pre-tax NOL carryforwards for state and local income tax purposes is approximately $3.7 billion ($154 million, net of tax), of which $2 million 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. 102 Expiration Period FirstEnergy FES 2018-2022 2023-2027 2028-2032 2033-2037 (In millions) State Local State Local 806 $ 3,472 $ 2 $ 1,954 1,963 2,382 1,896 — — — 32 703 982 — — — 7,047 $ 3,472 $ 1,719 $ 1,954 $ $ FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. A recognition threshold and measurement attribute is utilized for financial statement recognition and measurement of tax positions taken or expected to be taken on a company's tax return. As of December 31, 2017 and 2016, FirstEnergy's total unrecognized income tax benefits were approximately $80 million and $84 million, respectively. If ultimately recognized in future years, approximately $24 million of unrecognized income tax benefits would impact the effective tax rate. On October 18, 2017, the Supreme Court of Pennsylvania affirmed the Commonwealth Court’s holding that the state’s net loss carryover provision violated the Pennsylvania Uniformity Clause and was unconstitutional. However, the supreme court also opined that the portion of the net loss carryover provision that created the violation may be severed from the statute, enabling the statute to operate as the legislature intended, and on October 30, 2017, the Pennsylvania Governor signed House Bill 542 into law which, among other things, amended Pennsylvania’s limitation on net loss deductions to remove the flat-dollar limitation. On January 4, 2018, the supreme court denied to further hear any arguments related to the matter and, as a result, FirstEnergy withdrew its protective refund claims from the state of Pennsylvania on January 30, 2018. Upon doing so, FirstEnergy will reverse a previously recorded unrecognized tax benefit of approximately $45 million in the first quarter of 2018, none of which will impact FirstEnergy’s effective tax rate. As of December 31, 2017, it is reasonably possible that approximately $2 million of additional unrecognized tax benefits may be resolved during 2018 as a result of the statute of limitations expiring, none of which would affect FirstEnergy's effective tax rate. The following table summarizes the changes in unrecognized tax positions for the years ended 2017, 2016 and 2015: Balance, January 1, 2015 Current year increases Prior years increases Prior years decreases Balance, December 31, 2015 Current year increases Prior years increases Prior years decreases Balance, December 31, 2016 Current year increases Decrease for lapse in statute Balance, December 31, 2017 FirstEnergy FES (In millions) 34 $ 3 7 (10) 34 $ 2 69 (21) 84 $ 2 (6) 80 $ 3 — 5 — 8 — — (8) — — — — $ $ $ $ FirstEnergy recognizes interest expense or income and penalties related to uncertain tax positions in income taxes. That amount is computed 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 federal income tax return. FirstEnergy's recognition of net interest associated with unrecognized tax benefits in 2017, 2016, and 2015 was not material. For the years ended December 31, 2017 and 2016, the cumulative net interest payable recorded by FirstEnergy was not material. 103 General Taxes General tax expense for 2017, 2016 and 2015, is summarized as follows: FirstEnergy KWH excise State gross receipts Real and personal property Social security and unemployment Other Total general taxes FES State gross receipts Real and personal property Social security and unemployment Other Total general taxes 2017 2016 2015 (In millions) $ $ $ $ $ 188 204 486 131 34 $ 196 212 472 127 35 1,043 $ 1,042 $ 20 27 11 — 58 $ $ $ 28 42 15 3 88 $ 193 224 410 119 32 978 44 36 16 2 98 104 7. LEASES FirstEnergy leases certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases. In 1987, OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years, which expired in 2016 for Perry Unit 1 and in 2017 for Beaver Valley Unit 2. In that same year, CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and entered into similar operating leases for lease terms of approximately 30 years, which expired in 2017. In 2007, FG completed a sale and leaseback transaction for its 93.83% undivided interest in Bruce Mansfield Unit 1 and entered into operating leases for basic lease terms of approximately 33 years, expiring in 2040. FES has unconditionally and irrevocably guaranteed all of FG’s obligations under each of the leases. As of December 31, 2017, FES' leasehold interest was 93.83% of Bruce Mansfield Unit 1. On May 23, 2016, NG completed the purchase of the 3.75% lessor equity interests of the remaining non-affiliated leasehold interest in Perry Unit 1 for $50 million. In addition, the Perry Unit 1 leases expired in accordance with their terms on May 30, 2016, resulting in NG being the sole owner of Perry Unit 1 and entitled to100% of the unit's output. On June 1, 2017, NG completed the purchase of the 2.60% lessor equity interests of the remaining non-affiliated leasehold interests in Beaver Valley Unit 2 for $38 million. In addition, the Beaver Valley Unit 2 leases expired in accordance with their terms on June 1, 2017, resulting in NG being the sole owner of Beaver Valley Unit 2. Operating lease expense for 2017, 2016 and 2015, is summarized as follows: (In millions) FirstEnergy FES 2017 2016 2015 $ $ 158 93 $ $ 168 94 $ $ 174 94 The future minimum capital lease payments as of December 31, 2017 are as follows: Capital Leases 2018 2019 2020 2021 2022 Years thereafter Total minimum lease payments Interest portion Present value of net minimum lease payments Less current portion Noncurrent portion FirstEnergy FES (In millions) $ $ 28 23 18 15 13 20 117 (26) 91 24 67 $ $ 2 — — — — — 2 — 2 2 — The future minimum operating lease payments as of December 31, 2017, are as follows: Operating Leases FirstEnergy FES 2018 2019 2020 2021 2022 Years thereafter Total minimum lease payments (In millions) $ 146 128 102 124 111 1,263 1,874 $ 101 97 68 93 91 1,131 1,581 $ $ 105 8. INTANGIBLE ASSETS As of December 31, 2017, intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheet, include the following: (In millions) NUG contracts(1) OVEC Coal contracts(2) FES customer contracts Intangible Assets Amortization Expense Actual Estimated Gross Accumulated Amortization Net 2017 2018 2019 2020 2021 2022 Thereafter $ 124 $ 36 $ 88 $ 8 102 148 382 $ $ 3 94 144 277 5 8 4 5 1 4 5 $ $ $ 5 — 3 3 5 1 3 1 5 — 2 — 7 $ $ 5 — — — 5 $ $ 5 — — — 5 $ $ 63 4 — — 67 $ 105 $ 15 $ 11 $ 10 $ (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. 9. 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 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. 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 September 2012, the Ohio Companies created separate, wholly-owned limited liability company SPEs which issued 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, 2017 and December 31, 2016, $315 million and $339 million of the phase-in recovery bonds were outstanding, respectively. • JCP&L Securitization - In June 2002, JCP&L Transition Funding sold transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station, which were paid in full at maturity on June 5, 2017. Additionally, 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 and JCP&L’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, 2017 and December 31, 2016, $56 million and $85 million of the transition bonds were outstanding, respectively. • MP and PE Environmental Funding Companies - The entities issued bonds, the proceeds of which were used to construct environmental control facilities. The limited liability company SPEs own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's and PE's West Virginia service territories. 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, 2017 and December 31, 2016, $383 million and $406 million of the environmental control bonds were outstanding, respectively. FES does not have any consolidated VIEs. 106 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 venture's economic performance. FEV's ownership interest is subject to the equity method of accounting. In 2015, FirstEnergy fully impaired the value of its investment in Global Holding. As discussed in Note 16, "Commitments, Guarantees and Contingencies," FE is the guarantor under Global Holding's term loan facility, which has an outstanding principal balance of $275 million. 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, 2017, the carrying value of the equity method investment was $17 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 12 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 $112 million and $108 million, respectively, during the years ended December 31, 2017 and 2016. • Sale and Leaseback Transactions - FES has obligations that are not included on its Consolidated Balance Sheet related to the 2007 Bruce Mansfield Unit 1 sale and leaseback arrangement, which are satisfied through operating lease payments. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the arrangements. FES is exposed to losses under the Bruce Mansfield Unit 1 sale and leaseback agreements upon the occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses FirstEnergy's net exposure to loss based upon the casualty value provisions as of December 31, 2017: Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy(1) $ 1,083 $ 862 $ 221 (1) All amounts are associated with FES. 107 10. FAIR VALUE MEASUREMENTS RECURRING FAIR VALUE MEASUREMENTS 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, which has been reviewed and approved by FirstEnergy's Risk Policy Committee, are used to measure fair value. A more detailed description of FirstEnergy's valuation process for FTRs and NUGs follows: 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. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 11, "Derivative Instruments," for additional information regarding FirstEnergy's FTRs. 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 ICE 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. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. 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, 2017, from those used as of December 31, 2016. 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. 108 Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the years ended December 31, 2017 and 2016. The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: FirstEnergy Recurring Fair Value Measurements December 31, 2017 December 31, 2016 Assets (In millions) Corporate debt securities $ — $ 1,196 $ — $ 1,196 $ — $ 1,247 $ — $ 1,247 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Derivative assets - commodity contracts Derivative assets - FTRs Derivative assets - NUG contracts(1) Equity securities(2) Foreign government debt securities U.S. government debt securities U.S. state debt securities Other(3) Total assets Liabilities — — — 1,104 — — — 589 33 — — — 88 154 276 135 $ 1,693 $ 1,882 $ — 4 — — — — — — 4 33 4 — 10 — — 1,104 925 88 154 276 724 — — — 199 200 — — — 78 161 246 123 $ 3,579 $ 1,134 $ 2,055 $ — 7 1 — — — — — 8 210 7 1 925 78 161 246 322 $ 3,197 Derivative liabilities - commodity contracts Derivative liabilities - FTRs Derivative liabilities - NUG contracts(1) Total liabilities $ $ — $ (27) $ — $ (27) $ (6) $ (118) $ — $ (124) — — — — (1) (79) (1) (79) — — — — (6) (108) — $ (27) $ (80) $ (107) $ (6) $ (118) $ (114) $ (6) (108) (238) Net assets (liabilities)(4) $ 1,693 $ 1,855 $ (76) $ 3,472 $ 1,128 $ 1,937 $ (106) $ 2,959 (1) NUG 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 Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (3) Primarily consists of short-term cash investments. (4) Excludes $(8) million and $(3) million as of December 31, 2017 and December 31, 2016, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. 109 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 periods ended December 31, 2017 and December 31, 2016: NUG Contracts(1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2016 Balance Unrealized gain (loss) Purchases Settlements December 31, 2016 Balance Unrealized gain (loss) Purchases Settlements December 31, 2017 Balance $ $ 1 2 — (2) 1 — — (1) $ (137) $ (136) $ 8 $ (13) $ (17) — 46 (15) — 44 $ (108) $ (107) $ (10) — 39 (10) — 38 (6) 16 (11) 7 1 4 (8) (4) (7) 18 $ (6) $ (2) (1) 8 (5) (10) 9 7 1 (1) 3 — $ — $ (79) $ (79) $ 4 $ (1) $ 3 (1) NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. Level 3 Quantitative Information The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended December 31, 2017: Fair Value, Net (In millions) Valuation Technique Significant Input Range Weighted Average Units FTRs NUG Contracts $ $ 3 (79) Model Model RTO auction clearing prices ($4.60) to $5.40 $0.70 Dollars/MWH Generation Regional electricity prices 400 to 2,099,000 $30.70 to $32.00 426,000 $30.70 MWH Dollars/MWH 110 FES Recurring Fair Value Measurements December 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 720 $ — $ 720 $ — $ $ — $ Derivative assets - commodity contracts Derivative assets - FTRs Equity securities(1) Foreign government debt securities U.S. government debt securities U.S. state debt securities Other(2) Total assets — — 810 — — — 1 33 — — 65 133 29 96 $ 811 $ 1,076 $ — 1 — — — — — 1 33 1 810 65 133 29 97 10 — 634 — — — 2 726 200 — — 58 48 3 81 726 210 4 634 58 48 3 83 — 4 — — — — — 4 $ 1,888 $ 646 $ 1,116 $ $ 1,766 Liabilities Derivative liabilities - commodity contracts Derivative liabilities - FTRs Total liabilities Net assets (liabilities)(3) $ $ $ — $ (23) $ — $ (23) $ (6) $ (118) $ — $ (124) — — (1) (1) — — (5) (5) — $ (23) $ (1) $ (24) $ (6) $ (118) $ (5) $ (129) 811 $ 1,053 $ — $ 1,864 $ 640 $ 998 $ (1) $ 1,637 (1) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (2) Primarily consists of short-term cash investments. (3) Excludes $3 million and $2 million as of December 31, 2017 and December 31, 2016, 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 FTRs held by FES and classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2017 and December 31, 2016: Derivative Asset Derivative Liability (In millions) Net Asset/(Liability) January 1, 2016 Balance Unrealized loss Purchases Settlements December 31, 2016 Balance Unrealized loss Purchases Settlements December 31, 2017 Balance $ $ $ 5 (4) 10 (7) 4 — 1 (4) 1 $ $ $ (11) $ (3) (5) 14 (5) $ (1) (1) 6 (1) $ (6) (7) 5 7 (1) (1) — 2 — Level 3 Quantitative Information The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended December 31, 2017: Fair Value, Net (In millions) Valuation Technique Significant Input Range Weighted Average Units FTRs $ — Model RTO auction clearing prices ($4.60) to $3.30 $0.10 Dollars/MWH 111 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 held-to-maturity securities and AFS securities. At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value. Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES, OE and TE are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of OTTI. The NDTs of JCP&L, ME and PN are subject to regulatory accounting with unrealized gains and losses offset against regulatory assets. During the second quarter of 2017, in connection with NG purchasing the lessor equity interests of the remaining non-affiliated leasehold interests from an owner participant in the Beaver Valley Unit 2 and the expiration of the leases, OE and TE transferred NDT assets of $189 million associated with their leasehold interests to NG. See Note 14, "Asset Retirement Obligations," for additional information. 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. AFS Securities FirstEnergy holds debt and equity securities within its NDT and nuclear fuel disposal trusts. These trust investments are considered AFS securities, recognized at fair market value. FirstEnergy has no securities held for trading purposes. The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT and nuclear fuel disposal trusts as of December 31, 2017 and December 31, 2016: December 31, 2017(1) December 31, 2016(2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,707 $ FES 950 31 20 $ 1,738 $ 1,735 $ 970 847 38 27 $ 1,773 874 Equity securities FirstEnergy $ FES $ 949 695 155 115 $ 1,104 $ 810 822 564 $ 103 $ 70 925 634 (1) Excludes short-term cash investments: FirstEnergy - $87 million; FES - $76 million. (2) Excludes short-term cash investments: FirstEnergy - $61 million; FES - $44 million. 112 Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three years ended December 31, 2017, 2016 and 2015 were as follows: December 31, 2017 Sale Proceeds Realized Gains Realized Losses (In millions) OTTI Interest and Dividend Income FirstEnergy FES $ 2,170 $ 940 $ 330 256 (253) $ (13) $ (195) (13) 98 59 December 31, 2016 Sale Proceeds Realized Gains Realized Losses (In millions) OTTI Interest and Dividend Income FirstEnergy FES $ 1,678 $ 717 $ 170 117 (121) $ (21) $ (69) (19) 100 56 December 31, 2015 Sale Proceeds Realized Gains Realized Losses (In millions) OTTI Interest and Dividend Income FirstEnergy FES $ 1,534 $ 733 $ 209 158 (191) $ (102) $ (134) (90) 101 57 Held-To-Maturity Securities Unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of December 31, 2017 and December 31, 2016 are immaterial to FirstEnergy. Investments in employee benefit trusts and equity method investments totaling $255 million as of December 31, 2017 and $266 million as of December 31, 2016, 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 capital lease obligations and net unamortized debt issuance costs, premiums and discounts: December 31, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy FES $ 22,261 $ 23,038 $ 19,885 $ 2,836 1,487 3,000 19,829 1,555 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, 2017 and December 31, 2016. 11. DERIVATIVE INSTRUMENTS FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, 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 also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. 113 FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted. 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. FirstEnergy has contractual derivative agreements through 2020. Cash Flow Hedges FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating commodity prices and interest rates. Total pre-tax net unamortized losses included in AOCI associated with instruments previously designated as cash flow hedges totaled $10 million and $12 million as of December 31, 2017 and December 31, 2016, respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Net unamortized losses to be amortized to income during the next twelve months are not material. FirstEnergy has used forward starting interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were designated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $25 million (FES $3 million) and $33 million (FES $3 million) as of December 31, 2017 and December 31, 2016, respectively. Unamortized losses expected to be amortized to interest expense during the next twelve months are not material. Refer to Note 3, "Accumulated Other Comprehensive Income," for reclassifications from AOCI during the years ended December 31, 2017 and 2016. As of December 31, 2017 and December 31, 2016, no commodity or interest rate derivatives were designated as cash flow hedges. Fair Value Hedges FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. As of December 31, 2017 and December 31, 2016, no fixed-for-floating interest rate swap agreements were outstanding. Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $3 million and $10 million as of December 31, 2017 and December 31, 2016, respectively. During the next twelve months, approximately $2 million of unamortized gains are expected to be amortized to interest expense. Amortization of unamortized gains included in long-term debt totaled approximately $7 million and $10 million during the years ended December 31, 2017 and 2016, respectively. As of December 31, 2017 and December 31, 2016, no commodity or interest rate derivatives were designated as fair value hedges. Commodity Derivatives FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances where the hedging relationship does not qualify for hedge accounting. Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas primarily for use in FirstEnergy’s combustion turbine units. Derivative instruments are not used in quantities greater than forecasted needs. As of December 31, 2017, FirstEnergy's net asset position under commodity derivative contracts was not material. Under these commodity derivative contracts, FES posted $1 million of collateral. 114 Based on commodity derivative contracts held as of December 31, 2017, an increase in commodity prices of 10% would decrease net income by approximately $6 million (FES $4 million) during the next twelve months. NUGs As of December 31, 2017, FirstEnergy's net liability position under NUG contracts was $79 million representing contracts held at JCP&L and PN. Changes in the market value of NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. FTRs As of December 31, 2017, FirstEnergy's and FES' net position associated with FTRs was not material. FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of PJM that have load serving obligations. The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets and have not been designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price less the obligation due to PJM, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FES and AE Supply are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s Utilities are recorded as regulatory assets or liabilities. Directly allocated FTRs are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance. FirstEnergy records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets: Derivative Assets Derivative Liabilities Fair Value December 31, 2017 December 31, 2016 (In millions) Fair Value December 31, 2017 December 31, 2016 (In millions) Current Assets - Derivatives Current Liabilities - Other Commodity Contracts $ 33 $ 133 Commodity Contracts $ (27) $ FTRs 7 140 (1) (28) (72) (6) (78) FTRs Deferred Charges and Other Assets - Other Commodity Contracts FTRs NUGs(1) 4 37 — — — — Derivative Assets $ 37 $ Noncurrent Liabilities - Adverse Power Contract Liability NUGs(1) Noncurrent Liabilities - Other 77 — Commodity Contracts 1 FTRs 78 218 Derivative Liabilities (79) (108) — — (79) $ (107) $ (52) — (160) (238) (1) NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. 115 FES records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and classification of derivative instruments on FES' Consolidated Balance Sheets: Derivative Assets Derivative Liabilities Fair Value December 31, 2017 December 31, 2016 (In millions) Fair Value December 31, 2017 December 31, 2016 (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 33 $ 133 Commodity Contracts $ (23) $ FTRs Deferred Charges and Other Assets - Derivatives 1 34 FTRs 4 137 Noncurrent Liabilities - Other Commodity Contracts Derivative Assets $ — — 34 $ 77 Commodity Contracts 77 214 Derivative Liabilities (1) (24) — — $ (24) $ (72) (5) (77) (52) (52) (129) FirstEnergy enters into contracts with counterparties that allow for the offsetting of derivative assets and derivative liabilities under netting arrangements with the same counterparty. Certain of these contracts contain margining provisions that require the use of collateral to mitigate credit exposure between FirstEnergy and these counterparties. In situations where collateral is pledged to mitigate exposures related to derivative and non-derivative instruments with the same counterparty, FirstEnergy allocates the collateral based on the percentage of the net fair value of derivative instruments to the total fair value of the combined derivative and non-derivative instruments. The following tables summarize the fair value of derivative assets and derivative liabilities on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: December 31, 2017 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value Amounts Not Offset in Consolidated Balance Sheet Derivative Assets Commodity contracts FTRs Derivative Liabilities Commodity contracts FTRs NUG contracts $ $ $ $ 33 $ 4 37 $ (27) $ (1) (79) (107) $ (In millions) (19) $ (1) (20) $ 19 $ 1 — 20 $ — $ — — $ 3 — — 3 $ $ 14 3 17 (5) — (79) (84) 116 December 31, 2016 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Amounts Not Offset in Consolidated Balance Sheet Derivative Assets Commodity contracts FTRs NUG contracts Derivative Liabilities Commodity contracts FTRs NUG contracts $ $ $ $ 210 $ (117) $ 7 1 (6) — 218 $ (123) $ (124) $ 117 $ (6) (108) 6 — (238) $ 123 $ — $ — — — $ 93 1 1 95 1 — — 1 $ $ (6) — (108) (114) The following tables summarize the fair value of derivative assets and derivative liabilities on FES’ Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: December 31, 2017 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value Amounts Not Offset in Consolidated Balance Sheet Derivative Assets Commodity contracts FTRs Derivative Liabilities Commodity contracts FTRs $ $ $ $ 33 $ 1 34 $ (23) $ (1) (24) $ (In millions) (19) $ (1) (20) $ 19 $ 1 20 $ — $ — — $ — $ — — $ 14 — 14 (4) — (4) December 31, 2016 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value Amounts Not Offset in Consolidated Balance Sheet Derivative Assets Commodity contracts FTRs Derivative Liabilities Commodity contracts FTRs $ $ $ $ (In millions) 210 $ (117) $ 4 (4) 214 $ (121) $ (124) $ 117 $ (5) 4 (129) $ 121 $ 117 — $ — — $ 1 1 2 $ $ 93 — 93 (6) — (6) The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of December 31, 2017: Power Contracts FTRs NUGs Purchases Sales Net 2 9 2 (In millions) 11 — — (9) 9 2 Units MWH MWH MWH The following table summarizes the volumes associated with FES' outstanding derivative transactions as of December 31, 2017: Power Contracts FTRs Purchases Sales Net 2 5 (In millions) 11 — (9) 5 Units MWH MWH The effect of active derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income (Loss) during 2017, 2016 and 2015 are summarized in the following tables: 2017 Unrealized Gain (Loss) Recognized in: Other Operating Expense Realized Gain (Loss) Reclassified to: Revenues Purchased Power Expense Other Operating Expense Fuel Expense 2016 Unrealized Gain (Loss) Recognized in: Other Operating Expense Realized Gain (Loss) Reclassified to: Revenues Purchased Power Expense Other Operating Expense Fuel Expense Year Ended December 31 Commodity Contracts FTRs (In millions) Total $ $ (82) $ 1 $ (81) 54 $ (4) $ (17) — 5 — (14) — 50 (17) (14) 5 Year Ended December 31 Commodity Contracts FTRs (In millions) Total $ $ (14) $ 5 $ (9) 210 $ (131) — (8) $ 8 — (35) — 218 (131) (35) (8) 118 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense Realized Gain (Loss) Reclassified to: Revenues Purchased Power Expense Other Operating Expense Fuel Expense Year Ended December 31 Commodity Contracts FTRs (In millions) Total $ $ 93 $ (20) $ 73 111 $ (130) — (34) $ 50 — (49) — 161 (130) (49) (34) The effect of active derivative instruments not in a hedging relationship on FES' Consolidated Statements of Income (Loss) during 2017, 2016 and 2015 are summarized in the following tables: 2017 Unrealized Gain (Loss) Recognized in: Other Operating Expense Realized Gain (Loss) Reclassified to: Revenues Purchased Power Expense Other Operating Expense 2016 Unrealized Gain (Loss) Recognized in: Other Operating Expense Realized Gain (Loss) Reclassified to: Revenues Purchased Power Expense Other Operating Expense Year Ended December 31 Commodity Contracts FTRs (In millions) Total $ $ (79) $ 1 $ (78) 54 $ (4) $ (17) — — (14) 50 (17) (14) Year Ended December 31 Commodity Contracts FTRs (In millions) Total $ $ (14) $ 5 $ (9) 210 $ (131) — $ 8 — (35) 218 (131) (35) 119 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense Realized Gain (Loss) Reclassified to: Revenues Purchased Power Expense Other Operating Expense Year Ended December 31 Commodity Contracts FTRs (In millions) Total $ $ 93 $ (19) $ 74 111 $ (130) — $ 49 — (49) 160 (130) (49) The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during 2017 and 2016. Changes in the value of these contracts are deferred for future recovery from (or credit to) customers: Derivatives Not in a Hedging Relationship with Regulatory Offset Outstanding net asset (liability) as of January 1, 2017 Unrealized loss Purchases Settlements Outstanding net asset (liability) as of December 31, 2017 Outstanding net asset (liability) as of January 1, 2016 $ $ $ Unrealized loss Purchases Settlements Outstanding net asset (liability) as of December 31, 2016 $ 12. CAPITALIZATION COMMON STOCK Retained Earnings and Dividends NUGs Total Year Ended December 31 Regulated FTRs (In millions) 2 (1) 3 (1) 3 (107) $ (9) — 37 (79) $ $ $ (136) $ (15) — 44 (107) $ 1 (3) 4 — 2 $ $ (105) (10) 3 36 (76) (135) (18) 4 44 (105) As of December 31, 2017, FirstEnergy had an accumulated deficit of $(6.3) billion. Dividends declared in 2017 and 2016 were $1.44 per share, which included dividends of $0.36 per share paid in the first, second, third and fourth quarters. 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. On January 16, 2018, the Board of Directors declared a quarterly dividend of $0.36 per share to be paid from other paid-in-capital in the first quarter of 2018. In addition to paying dividends from retained earnings, OE, CEI, TE, Penn, JCP&L, ME and PN have authorization from the 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, TrAIL and AGC have authorization from FERC to pay cash dividends to their respective parents from paid-in capital accounts, as long as their 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 FirstEnergy as of December 31, 2017. Stock Issuance On January 22, 2018, FirstEnergy entered into agreements for the private placement of its equity securities representing an approximately $2.5 billion investment in the Company. See Note 21, "Subsequent Events," for additional information related to the equity issuances. 120 FE issued approximately 3.0 million shares of common stock in 2017, 2.7 million shares of common stock in 2016 and 2.5 million shares of common stock in 2015 to registered shareholders and its directors and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans. On December 13, 2016, FE contributed 16,097,875 newly issued shares of its common stock to its qualified pension plan in a private placement transaction. These shares were valued at approximately $500 million in the aggregate, and were issued to satisfy a portion of FirstEnergy’s future pension funding obligations. The independent fiduciary representing the pension plan with respect to the equity contribution fully liquidated the FE common stock by January 31, 2017. PREFERRED AND PREFERENCE STOCK FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2017, as follows: 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 FirstEnergy OE OE Penn CEI TE TE JCP&L ME PN MP PE WP As of December 31, 2017 and 2016, there were no preferred or preference shares outstanding. See Note 21, "Subsequent Events," for additional information related to preferred stock outstanding. 121 LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS The following tables present outstanding long-term debt and capital lease obligations for FirstEnergy and FES as of December 31, 2017 and 2016: (Dollar amounts in millions) Maturity Date Interest Rate 2017 2016 As of December 31, 2017 As of December 31 FirstEnergy: FMBs and secured notes - fixed rate 2018 - 2056 1.726% - 9.740% $ 5,446 $ 5,623 Secured notes - variable rate Total FMBs and secured notes Unsecured notes - fixed rate Unsecured notes - variable rate Total unsecured notes Capital lease obligations Unamortized debt discounts Unamortized debt issuance costs Unamortized fair value adjustments Currently payable long-term debt Total long-term debt and other long-term obligations FES: Secured notes - fixed rate Secured notes - variable rate Total secured notes Unsecured notes - fixed rate Capital lease obligations Unamortized debt discounts Unamortized debt issuance costs Currently payable long-term debt 2019 4.500% 2018 - 2047 2.550% - 7.700% 2020 - 2021 3.227% 9 5,455 15,370 1,450 16,820 91 (42) (113) (14) 10 5,633 13,058 1,200 14,258 104 (25) (87) (6) (1,082) (1,685) $ 21,115 $ 18,192 2018 - 2047 4.250% - 5.625% $ 612 $ 2019 4.500% 2019 - 2041 2.550% - 6.800% 9 621 2,215 2 (1) (14) (524) 617 10 627 2,373 8 (1) (15) (179) Total long-term debt and other long-term obligations $ 2,299 $ 2,813 On March 1, 2017, FG retired $28 million of PCRBs at maturity. On March 15, 2017, MP retired $150 million of FMBs at maturity. On April 3, 2017, CEI retired $130 million of 5.70% senior notes at maturity. On May 16, 2017, MP issued $250 million of 3.55% FMBs due 2027. Proceeds received from the issuance of the FMBs were used: (i) to repay short-term borrowings, (ii) to fund capital expenditures and (iii) for working capital needs and other general business purposes. On June 1, 2017, FG repurchased approximately $130 million of PCRBs, which were subject to a mandatory put on such date. FG is currently holding these PCRBs indefinitely. On June 1, 2017, JCP&L retired $250 million of 5.65% senior notes at maturity. On June 21, 2017, FE issued the aggregate principal amount of $3.0 billion of its senior notes in three series: $500 million of 2.85% notes due 2022; $1.5 billion of 3.90% notes due 2027; and $1.0 billion of 4.85% notes due 2047. Proceeds from the issuance of the notes were used: (i) to redeem $650 million of FE's 2.75% notes due in 2018 on July 25, 2017, and (ii) for general corporate purposes, including the repayment of short-term borrowings under the FE Facility. On August 31, 2017, ATSI issued $150 million of 3.66% senior unsecured notes maturing in 2032. Proceeds from the issuance of the notes were used: (i) to repay short-term borrowings, (ii) to fund capital expenditures and (iii) for working capital needs and other general business purposes. 122 On September 8, 2017, PN issued $300 million of 3.25% senior notes maturing in 2028. Proceeds from the issuance of the notes were used to repay short-term borrowings that were used to repay at maturity $300 million of PN's 6.05% senior notes due September 1, 2017. On September 15, 2017, WP issued $100 million of 4.09% FMBs due 2047. Proceeds from the issuance of the FMBs were used: (i) to repay short-term borrowings, (ii) to fund capital expenditures and (iii) for other general business purposes. On October 5, 2017, CEI issued $350 million of 3.50% senior notes maturing in 2028. Proceeds from the issuance of the notes were used: (i) to refinance existing indebtedness, including $300 million of 7.88% FMBs due November 1, 2017, and borrowings outstanding under FirstEnergy's regulated utility money pool and the Facility, (ii) to fund capital expenditures and (iii) for working capital and other general business purposes. On December 15, 2017, WP issued $275 million of 4.14% FMBs maturing in 2047. Proceeds from the issuance of the FMBs were used to repay at maturity $275 million of WP's 5.95% FMBs due December 15, 2017. See Note 7, "Leases," for additional information related to capital leases. 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. As of December 31, 2017 and 2016, $383 million and $406 million of environmental control bonds were outstanding, respectively. Transition Bonds The consolidated financial statements of FirstEnergy and JCP&L include transition bonds issued by JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. The proceeds were used to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station and to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. As of December 31, 2017 and 2016, $56 million and $85 million of the transition bonds were outstanding, respectively. 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. As of December 31, 2017 and 2016, $315 million and $339 million of the phase-in recovery bonds were outstanding, respectively. See Note 9, "Variable Interest Entities," for additional information on securitized bonds. Other Long-term Debt The Ohio Companies, Penn, FG and NG 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, 2017, the sinking fund requirement for all FMBs issued under the various mortgage indentures was zero. 123 The following table presents scheduled debt repayments for outstanding long-term debt, excluding capital leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2017. 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 2018 2019 2020 2021 2022 FirstEnergy FES (In millions) $ 1,051 $ 1,267 1,281 2,032 1,428 515 323 667 674 284 Certain PCRBs allow bondholders to tender their PCRBs for mandatory purchase prior to maturity. The following table classifies these PCRBs by year, excluding unamortized debt discounts and premiums, for the next five years based on the next date on which the debt holders may exercise their right to tender their PCRBs. Year 2018 2019 2020 2021 2022 FirstEnergy FES (In millions) $ $ 375 232 490 342 284 375 232 490 342 284 Debt Covenant Default Provisions FirstEnergy has various debt covenants under certain financing arrangements, including its revolving credit facilities. 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, 2017, FirstEnergy and FES remain in compliance with all debt covenant provisions. 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 FES and AES, default under another financing arrangement in excess of a certain principal amount, typically $100 million. Although such defaults by any of the Utilities, ATSI or TrAIL would generally cross-default FE financing arrangements containing these provisions, defaults by any of AE Supply, FES, FG or NG 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, FG, NG or the Utilities. 13. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT FE and the Utilities and FET and its subsidiaries participate in two separate five-year syndicated revolving credit facilities with aggregate commitments of $5.0 billion (Facilities), which are available through December 6, 2021. FE and the Utilities and FET and its subsidiaries may use borrowings under their Facilities 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 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 Facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FirstEnergy had $300 million and $2,675 million of short-term borrowings as of December 31, 2017 and 2016, respectively. FirstEnergy’s available liquidity from external sources as of January 31, 2018 was as follows: 124 Borrower(s) Type Maturity Commitment Available Liquidity FirstEnergy(1) FET(2) Revolving Revolving December 2021 $ 4,000 $ December 2021 1,000 (In millions) Subtotal $ 5,000 $ Cash — Total $ 5,000 $ 3,740 1,000 4,740 358 5,098 (1) (2) FE and the Utilities. Available liquidity includes impact of $10 million of LOCs issued under various terms. Includes FET, ATSI, MAIT and TrAIL. FES had $105 million and $101 million of short-term borrowings as of December 31, 2017 and December 31, 2016, respectively. Of such amounts, $102 million and $101 million, respectively, represents a currently outstanding promissory note due April 2, 2018, payable to AE Supply with any additional short-term borrowings representing borrowings under an unregulated companies' money pool, which also includes FE, FET, FEV and certain other unregulated subsidiaries of FE, but excludes FENOC, FES and its subsidiaries. In addition to FES' access to a separate unregulated companies' money pool, which includes FE, FES' subsidiaries and FENOC, FES' available liquidity as of January 31, 2018, was as follows: Type Commitment Available Liquidity Two-year secured credit facility with FE $ Cash $ (In millions) 500 $ — 500 $ 500 1 501 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, 2018: Borrower FirstEnergy Revolving Credit Facility Sub- Limits FET Revolving Credit Facility Sub-Limits 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 $ 4,000 $ — $ — 500 500 300 600 300 300 200 500 150 — 50 — — 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. 125 $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, other than the FET facility, which is based on its subsidiaries' credit ratings. 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, 2017, the borrowers were in compliance with the applicable debt-to-total-capitalization covenants, as well as in the case of FE, the minimum interest coverage ratio requirement, in each case as defined under the respective Facilities. Separately, in December 2016, FE and FES entered into a two-year secured credit facility in which FE provides a committed line of credit to FES of up to $500 million and additional credit support of up to $200 million to cover surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR and the Hatfield's Ferry disposal site, respectively. So long as FES remains in an unregulated companies' money pool, which includes FE, FES' subsidiaries and FENOC, the $500 million secured line of credit provides FES the needed liquidity in order for FES to, among other things, satisfy its nuclear support obligation to NG in the event of extraordinary circumstances with respect to its nuclear facilities. The new facility matures on December 31, 2018, and is secured by FMBs issued by FG ($250 million) and NG ($450 million). Additionally, FES maintains access to an unregulated companies' money pool, which includes FE, FES' subsidiaries and FENOC, and continues to conduct its ordinary course of business under that money pool in lieu of borrowing under the new facility. Term Loans As of December 31, 2017, FE had a $1.2 billion variable rate syndicated term loan and two separate $125 million term loans. On January 22, 2018, FE repaid these term loans in full using the proceeds from the $2.5 billion equity investment. FirstEnergy Money Pools FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and the holding company 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 of FE participating in a money pool and FE (as a lender only), FENOC, FES and its subsidiaries participating in a similar money pool. FESC administers these money pools and tracks surplus funds of FirstEnergy 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 2017 was 1.48% per annum for the regulated companies’ money pool and 2.30% per annum for the unregulated companies’ money pools. As discussed above, FES currently maintains access to its unregulated companies' money pool in lieu of borrowing under its $500 million secured line of credit. FE expects to provide ongoing liquidity to FES within such unregulated companies' money pool through March 2018. As of December 31, 2017, FES, its subsidiaries, and FENOC had no borrowings in the aggregate under 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, 2017 and 2016, were as follows: FirstEnergy 3.24% 2.47% 2017 2016 14. ASSET RETIREMENT OBLIGATIONS FirstEnergy has recognized applicable legal obligations for AROs and their associated cost primarily for nuclear power plant decommissioning, reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks, wastewater treatment lagoons and transformers containing PCBs. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation. The ARO liabilities for FES primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities and totaled $1,758 million and $713 million as of December 31, 2017 and 2016, respectively. FES uses an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs. 126 FirstEnergy and FES maintain NDTs that are legally restricted for purposes of settling the nuclear decommissioning ARO. The fair values of the decommissioning trust assets as of December 31, 2017 and 2016 were as follows: 2017 2016 (In millions) FirstEnergy FES $ $ 2,678 1,856 $ $ 2,514 1,552 The following table summarizes the changes to the ARO balances during 2017 and 2016: ARO Reconciliation FirstEnergy FES Balance, January 1, 2016 Liabilities settled Accretion Liabilities Incurred Balance, December 31, 2016 Changes in timing of estimated cash flows (1) Liabilities settled Accretion Liabilities Incurred Balance, December 31, 2017 $ $ $ (In millions) 1,410 $ (27) 95 4 1,482 $ 944 (12) 101 — 2,515 $ 831 (18) 56 32 901 944 (11) 62 49 1,945 (1) See Note 2, "Asset Sales and Impairments" for further discussion. During the second quarter of 2017, in connection with NG purchasing the lessor equity interests of the remaining non-affiliated leasehold interests from an owner participant in the Beaver Valley Unit 2 sale leaseback and the expiration of the leases, OE and TE transferred the ARO (included within the FES liabilities incurred above) and NDT assets associated with their leasehold interests to NG, with the difference of $73 million credited to the common stock of FES. During 2016, in connection with NG purchasing the lessor equity interests of the remaining non-affiliated leasehold interests from an owner participant in Perry Unit 1, OE transferred the ARO (included within the FES liabilities incurred above) and related NDT assets associated with the leasehold interest to NG with the difference of $28 million credited to the common stock of FES. As of June 30, 2016, NG owns 100% of Perry Unit 1. 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. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although not currently expected, changes in timing and closure plan requirements in the future, including changes resulting from the strategic review at CES, could materially and adversely impact FirstEnergy's and FES' AROs. 15. 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 Ohio by the PUCO, in New Jersey by the NJBPU, 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. As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates. In addition, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility. 127 Following the adoption of the Tax Act, various state regulatory proceedings have been initiated to investigate the impact of the Tax Act on the Utilities’ rates and charges. State proceedings which have arisen are discussed below. The Utilities continue to monitor and investigate the impact of state regulatory impacts resulting from the Tax Act. MARYLAND PE 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 Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption and demand and requiring each electric utility to file a plan every three years. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the goal of 0.97% savings achieved under PE's current plan for 2016, and increasing 0.2% per year thereafter to reach 2%. The Maryland legislature in April 2017 adopted a statute requiring the same 0.2% per year increase, 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. The costs of PE's 2015-2017 plan approved by the MDPSC in December 2014 were approximately $60 million. PE filed its 2018-2020 EmPOWER Maryland plan on August 31, 2017. The 2018-2020 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. On December 22, 2017, the MDPSC issued an order approving the 2018-2020 plan with various modifications. 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 February 27, 2013, the MDPSC issued an order requiring the Maryland electric utilities to submit analyses relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations. PE's responsive filings discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 2013 Order, and projected that it would require approximately $2.7 billion in infrastructure investments over 15 years to attempt to achieve the quickest level of response for the largest storm projected in the February 2013 Order. On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting, as well as the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that the Maryland utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not issued a ruling on any of those matters. On September 26, 2016, the MDPSC initiated a new 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. Comments were filed and a hearing was held in late 2016. On January 31, 2017, the MDPSC issued a notice establishing five working groups to address these issues over the following eighteen months, and also directed the retention of an outside consultant to prepare a report on costs and benefits of distributed solar generation in Maryland. 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. If approved, PE will launch an electric vehicle charging infrastructure program on January 1, 2019, offering up to 2,000 rebates for electric vehicle charging equipment to residential customers, and deploying up to 259 chargers at non-residential customer service locations at a projected total cost of $12 million. PE is proposing to recover program costs subject to a five-year amortization. On February 6, 2018, the MDPSC opened a new proceeding to consider the petition and directed that comments be filed by March 16, 2018. On January 12, 2018, the MDPSC instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of Maryland utilities. PE must track and apply regulatory accounting treatment for the impacts beginning January 1, 2018, and submitted a report to the MDPSC on February 15, 2018, estimating that the Tax Act impacts would be approximately $7 million to $8 million annually for PE’s customers and proposed to file a base rate case in the third quarter of 2018 where the benefits from the effects of the Tax Act will be realized by customers through a lower rate increase than would otherwise be necessary. NEW JERSEY JCP&L currently 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. The supply for BGS is comprised of two components, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers. The second BGS component provides a fixed price service and is intended for smaller commercial and residential customers. 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. JCP&L currently operates under rates that were approved by the NJBPU on December 12, 2016, effective as of January 1, 2017. These rates provide an annual increase in operating revenues of approximately $80 million from those previously in place and are 128 intended to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses. In addition, on January 25, 2017, the NJBPU approved the acceleration of the amortization of JCP&L’s 2012 major storm expenses that are recovered through the SRC in order for JCP&L to achieve full recovery by December 31, 2019. Pursuant to the NJBPU's March 26, 2015 final order in JCP&L's 2012 rate case proceeding directing that certain studies be completed, on July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which included operational and financial components. The independent consultant conducting the review issued a final report on July 27, 2016, recognizing that JCP&L is meeting the NJBPU requirements and making various operational and financial recommendations. The NJBPU issued an Order on August 24, 2016, that accepted the independent consultant’s final report and directed JCP&L, the Division of Rate Counsel and other interested parties to address the recommendations. In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases, the NJBPU stated that it would continue to apply its current CTA policy in base rate cases, subject to incorporating the following modifications: (i) calculating savings using a five-year look back from the beginning of the test year; (ii) allocating savings with 75% retained by the company and 25% allocated to rate payers; and (iii) excluding transmission assets of electric distribution companies in the savings calculation. On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the generic CTA proceeding to the Superior Court of New Jersey Appellate Division and JCP&L filed to participate as a respondent in that proceeding supporting the order. On September 18, 2017, the Superior Court of New Jersey Appellate Division reversed the NJBPU's Order on the basis that the NJBPU's modification of its CTA methodology did not comply with the procedures of the NJAPA. JCP&L's existing rates are not expected to be impacted by this order. On December 19, 2017, the NJBPU approved the issuance of proposed rules to modify the CTA methodology consistent with its October 22, 2014 Generic Order. The proposed rule was published in the NJ Register on January 16, 2018, and was republished on February 6, 2018, to correct an error. Interested parties have sixty days to comment on the proposed rulemaking. At the December 19, 2017 NJBPU public meeting, 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. JCP&L expects to make a filing in 2018. 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. JCP&L must track and apply regulatory accounting treatment for the impacts effective January 1, 2018, and file a petition with the NJBPU by March 2, 2018, regarding the expected impacts of the Tax Act on JCP&L’s expenses and revenues and how the effects will be passed through to its customers. OHIO The Ohio Companies currently operate under ESP IV which commenced June 1, 2016 and expires May 31, 2024. The material terms of ESP IV, as approved in the PUCO’s Opinion and Order issued on March 31, 2016 and Fifth Entry on Rehearing on October 12, 2016, include Rider DMR, which provides for the Ohio Companies to collect $132.5 million annually for three years, with the possibility of a two-year extension. Rider DMR will be grossed up for federal income taxes, resulting in an approved amount of approximately $204 million annually. Revenues from Rider DMR will be excluded from the significantly excessive earnings test for the initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension. The PUCO set three conditions for continued recovery under Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO. ESP IV also continues a base distribution rate freeze through May 31, 2024. In addition, ESP IV 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 $30 million per year from June 1, 2016 through May 31, 2019; $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. Other material terms of ESP IV include: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (2) an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016, and remains pending); (3) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; (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; and (5) an agreement to file an application to transition to a straight fixed variable cost recovery mechanism for residential customers' base distribution rates (which filing was made on April 3, 2017, and remains pending). Several parties, including the Ohio Companies, filed applications for rehearing regarding the Ohio Companies’ ESP IV with the PUCO. The Ohio Companies’ application for rehearing challenged, among other things, the PUCO’s failure to adopt the Ohio Companies’ suggested modifications to Rider DMR. The Ohio Companies had previously suggested that a properly designed Rider DMR would be valued at $558 million annually for eight years, and include an additional amount that recognizes the value of the economic impact of FirstEnergy maintaining its headquarters in Ohio. Other parties’ applications for rehearing argued, among other 129 things, that the PUCO’s adoption of Rider DMR is not supported by law or sufficient evidence. On August 16, 2017, the PUCO denied all remaining intervenor applications for rehearing, denied the Ohio Companies’ challenges to the modifications to Rider DMR and added a third-party monitor to ensure that Rider DMR funds are spent appropriately. On September 15, 2017, the Ohio Companies filed an application for rehearing of the PUCO’s August 16, 2017 ruling on the issues of the third-party monitor and the ROE calculation for advanced metering infrastructure. On October 11, 2017, the PUCO denied the Ohio Companies' application for rehearing on both issues. On October 16, 2017, the Sierra Club and the Ohio Manufacturer's Association Energy Group filed notices of appeal with the Supreme Court of Ohio appealing various PUCO entries on their applications for rehearing. On November 16, 2017, the Ohio Companies intervened in the appeal. Additional parties subsequently filed notices of appeal with the Supreme Court of Ohio challenging various PUCO entries on their applications for rehearing. For additional information, see “FERC Matters - Ohio ESP IV PPA,” below. Under ORC 4928.66, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. Starting in 2017, ORC 4928.66 requires the energy savings benchmark to increase by 1% and the peak demand reduction benchmark to increase by 0.75% annually thereafter through 2020 and the energy savings benchmark to increase by 2% annually from 2021 through 2027, with a cumulative benchmark of 22.2% by 2027. On April 15, 2016, the Ohio Companies filed an application for approval of their three-year energy efficiency portfolio plans for the period from January 1, 2017 through December 31, 2019. The plans as proposed comply with benchmarks contemplated by ORC 4928.66 and provisions of the ESP IV, and include a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities. On December 9, 2016, the Ohio Companies filed a Stipulation and Recommendation with several parties that contained changes to the plan and a decrease in the plan costs. The Ohio Companies anticipate the cost of the plans will be approximately $268 million over the life of the portfolio plans 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 filed Stipulation and Recommendation 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 as reported on FERC Form 1. On December 21, 2017, the Ohio Companies filed an application for rehearing challenging the PUCO’s modification of the Stipulation and Recommendation to include the 4% cost cap, which was denied by the PUCO on January 10, 2018. Ohio law requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage amount through 2026, except that in 2014 SB310 froze 2015 and 2016 requirements at the 2014 level (2.5%), pushing back scheduled increases, which resumed in 2017 (3.5%), and increases 1% each year through 2026 (to 12.5%) and shall remain at 12.5% in 2027 and each year thereafter. The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements. In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs. The PUCO issued an Opinion and Order on August 7, 2013, approving the Ohio Companies' acquisition process and their purchases of RECs to meet statutory mandates in all instances except for certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of $43.4 million, plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent. On December 24, 2013, following the denial of their application for rehearing, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted. The OCC and the ELPC also filed appeals of the PUCO's order. On January 24, 2018, the Supreme Court of Ohio reversed the PUCO order finding that the order violated the rule against prohibiting retroactive ratemaking. On February 5, 2018, the OCC and ELPC filed a motion for reconsideration, to which the Ohio Companies responded in opposition on February 15, 2018. On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers. On January 13, 2016, the PUCO granted reconsideration for further consideration of the matters specified in the applications for rehearing. On March 29, 2017, the PUCO issued a Second Entry on Rehearing that granted, in part, the applications for rehearing filed by FES and other parties, finding that the PUCO’s guidelines regarding fixed-price contracts should not apply to large mercantile customers. This finding changes the original order, which applied the guidelines to all customers, including mercantile customers. The PUCO also reaffirmed several provisions of the original order, including that the fixed-price guidelines only apply on a going-forward basis and not to existing contracts and that regulatory-out clauses in contracts are permissible. On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan. The DPM Plan is a portfolio of approximately $450 million in 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. The Ohio Companies have requested that the PUCO issue an order approving the DPM Plan and associated cost recovery no later than May 2, 2018, so that the Ohio Companies can expeditiously commence the DPM Plan and customers can begin to realize the associated benefits. On January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act and determine the appropriate course of action to pass benefits on to customers. The Ohio Companies must establish a regulatory liability, effective January 1, 2018, for 130 the estimated reduction in federal income tax resulting from the Tax Act, and filed comments on February 15, 2018, explaining that customers will save nearly $40 million annually as a result of updating tariff riders for the tax rate changes and that the Ohio Companies’ base distribution rates are not impacted by the Tax Act changes because they are frozen through May 2024. PENNSYLVANIA The Pennsylvania Companies operate under DSPs for the June 1, 2017 through May 31, 2019 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 DSPs, the supply will be provided by wholesale suppliers through a mix of 12 and 24-month energy contracts, as well as one RFP for 2-year SREC contracts for ME, PN and Penn. The DSPs include modifications to the Pennsylvania Companies’ POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges. On December 11, 2017, the Pennsylvania Companies filed DSPs for the June 1, 2019 through May 31, 2023 delivery period. Under the 2019-2023 DSPs, the supply is proposed to 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 as proposed also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program term. The 2019-2023 DSPs also introduce a retail market enhancement rate mechanism designed to stimulate residential customer shopping, and modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW. A hearing has been scheduled for April 10-11, 2018, and the PPUC is expected to issue a final order on these DSPs by mid-September 2018. The Pennsylvania Companies operate under rates that were approved by the PPUC on January 19, 2017, effective as of January 27, 2017. These rates provide annual increases in operating revenues of approximately $96 million at ME, $100 million at PN, $29 million at Penn, and $66 million at WP, and are intended to benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements. Pursuant to Pennsylvania's EE&C legislation in Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at 1.8% for ME, 1.7% for Penn, 1.8% for WP, and 0% for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at 4.0% for ME, 3.9% for PN, 3.3% for Penn, and 2.6% for WP. 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. Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. Pennsylvania EDCs must file LTIIPs outlining infrastructure improvement plans for PPUC review and approval prior to approval of a DSIC. On February 11, 2016, the PPUC approved LTIIPs for each of the Pennsylvania Companies. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. The LTIIPs estimated costs for the remaining period of 2018 to 2020, as modified, are: WP $50.1 million; PN $44.8 million; Penn $33.2 million; and ME $51.3 million. On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery, which were approved by the PPUC on June 9, 2016, and went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. On January 19, 2017, in the PPUC’s order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016, which is pending PPUC approval. The ADIT issue is subject to further litigation and a hearing was held on May 12, 2017. On August 31, 2017, the ALJ issued a decision recommending that the complaint of the Pennsylvania OCA be granted by the PPUC such that the Pennsylvania Companies reflect all federal and state income tax deductions related to DSIC-eligible property in the currently effective DSIC rates. If the decision is approved by the PPUC, the impact is not expected to be material to FirstEnergy. The Pennsylvania Companies filed exceptions to the decision on September 20, 2017, and reply exceptions on October 2, 2017. On February 12, 2018, the PPUC initiated a proceeding to determine the effects of the Tax Act on the tax liability of utilities and the feasibility of reflecting such impacts in rates charged to customers. By March 9, 2018, the Pennsylvania Companies must submit information to the PPUC to calculate the net effect of the Tax Act on income tax expense and rate base, and comments addressing whether rates should be adjusted to reflect the tax rate changes, and if so, how and when such modifications should take effect. 131 WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP's and PE's ENEC rate is updated annually. On September 23, 2016, the WVPSC approved the Phase II energy efficiency program for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, which includes three energy efficiency programs to meet the Phase II requirement of energy efficiency reductions of 0.5% of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, which was approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of Harrison Power Station to MP. The costs for the Phase II program are expected to be $10.4 million and are eligible for recovery through the existing energy efficiency rider which is reviewed in the fuel (ENEC) case each year. On December 15, 2017, the WVPSC approved MP's and PE's proposed annual decrease in their EE&C rates, effective January 1, 2018, which is not material to FirstEnergy. On December 9, 2016, the WVPSC approved the annual ENEC case for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, resulting in an increase in the ENEC rate of $25 million annually beginning January 1, 2017. In addition, ENEC rates will be maintained at the same level for a two year period. On December 30, 2015, MP and PE filed an IRP with the WVPSC identifying a capacity shortfall starting in 2016 and exceeding 700 MWs by 2020 and 850 MWs by 2027. On June 3, 2016, the WVPSC accepted the IRP. On December 16, 2016, MP issued an RFP to address its generation shortfall, along with issuing a second RFP to sell its interest in Bath County. Bids were received by an independent evaluator in February 2017 for both RFPs. AE Supply was the winning bidder of the RFP to address MP’s generation shortfall and on March 6, 2017, MP and AE Supply signed an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station (1,300 MWs) for approximately $195 million, subject to customary and other closing conditions, including regulatory approvals. In addition, on March 7, 2017, MP and PE filed an application with the WVPSC and MP and AE Supply filed an application with FERC requesting authorization for such purchase. Various intervenors filed protests challenging the RFP and requesting FERC deny the application, set it for hearing to allow discovery into the RFP process, or delay an order pending the conclusion of the WVPSC proceeding. On January 12, 2018, FERC issued an order denying authorization for the transaction, holding that MP and AE Supply did not demonstrate that the sale was consistent with the public interest and the transaction did not fall within the safe harbors for meeting FERC’s affiliate cross-subsidization analysis. In the order FERC also revised and clarified certain details of its standards for the review of transactions resulting from competitive solicitations, and concluded that MP’s RFP did not meet the revised and clarified standards. FERC allowed that MP may submit a future application for a transaction resulting from a new RFP. The WVPSC issued its order on January 26, 2018, denying the petition as filed but granting the transfer of Pleasants Power Station under certain conditions, which included MP assuming significant commodity risk. MP, PE and AE Supply have determined not to seek rehearing at FERC in light of the adverse decisions at FERC and the WVPSC. Based on the FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement. With respect to the Bath County RFP, MP does not plan to move forward with that sale of its ownership interest. In the future, MP may re-evaluate its options with respect to its interest in Bath County. On September 1, 2017, MP and PE filed with the WVPSC for a reconciliation of their VMS to confirm that rate recovery matches VMP costs and for a regular review of that program. MP and PE proposed a $15 million annual decrease in VMS rates effective January 1, 2018, and an additional $15 million decrease in rates for 2019. This is an overall decrease in total revenue and average rates of 1%. On December 15, 2017, the WVPSC issued an order adopting a unanimous settlement without modification. On January 3, 2018, the WVPSC initiated a proceeding to investigate the effects of the Tax Act on the revenue requirements of utilities. MP and PE must track the tax savings resulting from the Tax Act on a monthly basis, effective January 1, 2018, and file written testimony explaining the impact of the Tax Act on federal income tax and revenue requirements by May 30, 2018. On January 26, 2018, the WVPSC issued an order clarifying that regulatory accounting should be implemented as of January 1, 2018, including the recording of any regulatory liabilities resulting from the Tax Act. RELIABILITY MATTERS Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES and certain of its subsidiaries, AE Supply, FENOC, ATSI, MAIT and TrAIL. 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 eight regional entities, including RFC. All of FirstEnergy's facilities 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, including FES, believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy, including FES, 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, including FES, 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, 132 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, including FES, part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, and obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations and cash flows. FERC MATTERS Ohio ESP IV PPA On August 4, 2014, the Ohio Companies filed an application with the PUCO seeking approval of their ESP IV. ESP IV included a proposed Rider RRS, which would flow through to customers either charges or credits representing the net result of the price paid to FES through an eight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, against the revenues received from selling such output into the PJM markets. The Ohio Companies entered into stipulations which modified ESP IV, and on March 31, 2016, the PUCO issued an Opinion and Order adopting and approving the Ohio Companies’ stipulated ESP IV with modifications. FES and the Ohio Companies entered into the ESP IV PPA on April 1, 2016, but subsequently agreed to suspend it and advised FERC of this course of action. On March 21, 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in the PJM capacity markets by state-subsidized generation, in particular alleged price suppression that could result from the ESP IV PPA and other similar agreements. The complaint requested that FERC direct PJM to initiate a stakeholder process to develop a long-term MOPR reform for existing resources that receive out-of-market revenue. On January 9, 2017, the generation owners filed to amend their complaint to include challenges to certain legislation and regulatory programs in Illinois. On January 24, 2017, FESC, acting on behalf of its affected affiliates and along with other utility companies, filed a motion to dismiss the amended complaint for various reasons, including that the ESP IV PPA matter is now moot. In addition, on January 30, 2017, FESC along with other utility companies filed a substantive protest to the amended complaint, demonstrating that the question of the proper role for state participation in generation development should be addressed in the PJM stakeholder process. On August 30, 2017, the generation owners requested expedited action by FERC. This proceeding remains pending before FERC. PJM Transmission Rates PJM and its stakeholders have been debating the proper method to allocate costs for certain transmission facilities. While FirstEnergy and other parties advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM. This question has been the subject of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit. On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines. The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole. The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings. On June 15, 2016, various parties, including ATSI and the Utilities, filed a settlement agreement at FERC agreeing to apply a combined usage based/socialization approach to cost allocation for charges to transmission customers in the PJM Region for transmission projects operating at or above 500 kV. Certain other parties in the proceeding did not agree to the settlement and filed protests to the settlement seeking, among other issues, to strike certain of the evidence advanced by FirstEnergy and certain of the other settling parties in support of the settlement, as well as provided further comments in opposition to the settlement. FirstEnergy and certain of the other parties responded to such opposition. On October 20, 2017, the settling and non-opposing parties requested expedited action by FERC. The settlement is pending before FERC. 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. On March 17, 2016, FERC denied FirstEnergy's request for rehearing of FERC's earlier order rejecting the settlement agreement and affirmed its prior ruling that ATSI must submit the cost/benefit analysis. Separately, ATSI resolved a dispute regarding responsibility for certain costs for the “Michigan Thumb” transmission project. Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings before FERC and certain U.S. appellate courts. On October 29, 2015, FERC issued an order finding that ATSI and the ATSI zone do not have to pay MISO MVP charges for the Michigan Thumb transmission project. MISO and the MISO TOs filed a request for rehearing, which FERC denied on May 19, 2016. The MISO TOs subsequently filed an appeal of FERC's orders with the Sixth Circuit. FirstEnergy intervened and 133 participated in the proceedings on behalf of ATSI, the Ohio Companies and Penn. On June 21, 2017, the Sixth Circuit issued its decision denying the MISO TOs' appeal request. MISO and the MISO TOs did not seek review by the U.S. Supreme Court, effectively resolving the dispute over the "Michigan Thumb" transmission project. On a related issue, FirstEnergy joined certain other PJM TOs in a protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region. On July 13, 2016, FERC issued its order finding it appropriate for MISO to assess an MVP usage charge for transmission exports from MISO to PJM. Various parties, including FirstEnergy and the PJM TOs, requested rehearing or clarification of FERC’s order. The requests for rehearing remain pending before FERC. In addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM approved before ATSI joined PJM could be charged to transmission customers in the ATSI zone. The amount to be paid, and the question of derived benefits, is pending before FERC as a result of the Seventh Circuit's June 25, 2014 order described above under "PJM Transmission Rates." The outcome of the proceedings that address the remaining open issues related to MVP costs and "legacy RTEP" transmission projects cannot be predicted at this time. Transfer of Transmission Assets to MAIT Following receipt of necessary regulatory approvals, on January 31, 2017, MAIT issued membership interests to FET, PN and ME in exchange for their respective cash and transmission asset contributions. MAIT, a transmission-only subsidiary of FET, owns and operates all of the FERC-jurisdictional transmission assets previously owned by ME and PN. Subsequently, on March 13, 2017, FERC issued an order authorizing MAIT to issue short- and long-term debt securities, permitting MAIT to participate in the FirstEnergy regulated companies’ money pool for working capital, to fund day-to-day operations, support capital investment and establish an actual capital structure for ratemaking purposes. MAIT Transmission Formula Rate On October 28, 2016, as amended on January 10, 2017, MAIT submitted an application to FERC requesting authorization to implement a forward-looking formula transmission rate to recover and earn a return on transmission assets effective February 1, 2017. Various intervenors submitted protests of the proposed MAIT formula rate. Among other things, the protest asked FERC to suspend the proposed effective date for the formula rate until June 1, 2017. On March 10, 2017, FERC issued an order accepting the MAIT formula transmission rate for filing, suspending the formula transmission rate for five months to become effective July 1, 2017, and establishing hearing and settlement judge procedures. On April 10, 2017, MAIT requested rehearing of FERC’s decision to suspend the effective date of the formula rate. FERC's order on rehearing remains pending. MAIT’s rates went into effect on July 1, 2017, subject to refund pending the outcome of the hearing and settlement procedures. On October 13, 2017, MAIT and certain parties filed a settlement agreement with FERC. The settlement agreement provides for certain changes to MAIT's formula rate, changes MAIT's ROE from 11% to 10.3%, sets the recovery amount for certain regulatory assets, and establishes that MAIT's capital structure will not exceed 60% equity over the period ending December 31, 2021. The settlement agreement further provides that the ROE and the 60% cap on the equity component of MAIT's capital structure will remain in effect unless changed pursuant to section 205 or 206 of the FPA provided the effective date for any change shall be no earlier than January 1, 2022. The settlement agreement currently is pending at FERC. As a result of the settlement agreement, MAIT recognized a pre-tax impairment charge of $13 million in the third quarter of 2017. JCP&L Transmission Formula Rate On October 28, 2016, after withdrawing its request to the NJBPU to transfer its transmission assets to MAIT, JCP&L submitted an application to FERC requesting authorization to implement a forward-looking formula transmission rate to recover and earn a return on transmission assets effective January 1, 2017. A group of intervenors, including the NJBPU and New Jersey Division of Rate Counsel, filed a protest of the proposed JCP&L transmission rate. Among other things, the protest asked FERC to suspend the proposed effective date for the formula rate until June 1, 2017. On March 10, 2017, FERC issued an order accepting the JCP&L formula transmission rate for filing, suspending the transmission rate for five months to become effective June 1, 2017, and establishing hearing and settlement judge procedures. On April 10, 2017, JCP&L requested rehearing of FERC’s decision to suspend the effective date of the formula rate. FERC's order on rehearing remains pending. JCP&L’s rates went into effect on June 1, 2017, subject to refund pending the outcome of the hearing and settlement procedures. On December 21, 2017, JCP&L and certain parties filed a settlement agreement with FERC. The settlement agreement provides for a $135 million stated annual revenue requirement for Network Integration Transmission Service and an average of $20 million stated annual revenue requirement for certain projects listed on the PJM Tariff where the costs are allocated in part beyond the JCP&L transmission zone within the PJM Region. The revenue requirements are subject to a moratorium on additional revenue requirements proceedings through December 31, 2019, other than limited filings to seek recovery for certain additional costs. Also on December 21, 2017, JCP&L filed a motion for authorization to implement the settlement rate on an interim basis. On December 27, 2017, FERC granted the motion authorizing JCP&L to implement the settlement rate effective January 1, 2018, pending a final commission order on the settlement agreement. The settlement agreement is pending at FERC. As a result of the settlement agreement, JCP&L recognized a pre-tax impairment charge of $28 million in the fourth quarter of 2017. 134 DOE NOPR: Grid Reliability and Resilience Pricing On September 28, 2017, the Secretary of Energy released a NOPR requesting FERC to issue rules directing RTOs to incorporate pricing for defined “eligible grid reliability and resiliency resources” into wholesale energy markets. Specifically, as proposed, RTOs would develop and implement tariffs providing a just and reasonable rate for energy purchases from eligible grid reliability and resiliency resources and the recovery of fully allocated costs and a fair ROE. The NOPR followed the August 23, 2017, release of the DOE’s study regarding whether federally controlled wholesale energy markets properly recognize the importance of coal and nuclear plants for the reliability of the high-voltage grid, as well as whether federal policies supporting renewable energy sources have harmed the reliability of the energy grid. The DOE requested for the final rules to be effective in January 2018. On October 2, 2017, FERC established a docket and requested comments on the NOPR. FESC and certain of its affiliates submitted comments and reply comments. On January 8, 2018, FERC issued an order terminating the NOPR proceeding, finding that the NOPR did not satisfy the statutory threshold requirements under the FPA for requiring changes to RTO/ISO tariffs to address resilience concerns. FERC in its order instituted a new administrative proceeding to gather additional information regarding resilience issues, and directed that each RTO/ISO respond to a provided list of questions. There is no deadline or requirement for FERC to act in this new proceeding. At this time, we are uncertain as to the potential impact that final action by FERC, if any, would have on FES and our strategic options, and the timing thereof, with respect to the competitive business. PATH Transmission Project In 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia through Virginia and into Maryland. As a result of PJM canceling the project, approximately $62 million and approximately $59 million in costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery. PATH-Allegheny and PATH-WV requested authorization from FERC to recover the costs with a proposed ROE of 10.9% (10.4% base plus 0.5% for RTO membership) from PJM customers over five years. FERC issued an order denying the 0.5% ROE adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to hearing and settlement procedures. On January 19, 2017, FERC issued an order reducing the PATH formula rate ROE from 10.4% to 8.11% effective January 19, 2017, and allowing recovery of certain related costs. On February 21, 2017, PATH filed a request for rehearing with FERC, seeking recovery of disallowed costs and requesting that the ROE be reset to 10.4%. The Edison Electric Institute submitted an amicus curiae request for reconsideration in support of PATH. On March 20, 2017, PATH also submitted a compliance filing implementing the January 19, 2017 order. Certain affected ratepayers commented on the compliance filing, alleging inaccuracies in and lack of transparency of data and information in the compliance filing, and requested that PATH be directed to recalculate the refund provided in the filing. PATH responded to these comments in a filing that was submitted on May 22, 2017. On July 27, 2017, FERC Staff issued a letter to PATH requesting additional information on, and edits to, the compliance filing, as directed by the January 19, 2017 order. PATH filed its response on September 27, 2017. FERC orders on PATH's requests for rehearing and compliance filing remain pending. Market-Based Rate Authority, Triennial Update The Utilities, AE Supply, FES and certain of its subsidiaries, Buchanan Generation and Green Valley each hold authority from FERC to sell electricity at market-based rates. One condition for retaining this authority is that every three years each entity must file an update with FERC that demonstrates that each entity continues to meet FERC’s requirements for holding market-based rate authority. On December 23, 2016, FESC, on behalf of its affiliates with market-based rate authority, submitted to FERC the most recent triennial market power analysis filing for each market-based rate holder for the current cycle of this filing requirement. On July 27, 2017, FERC accepted the triennial filing as submitted. 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES NUCLEAR INSURANCE The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $13.4 billion (assuming 102 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $450 million; and (ii) $13.0 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $127 million (but not more than $19 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s and NG's maximum potential assessment under these provisions would be $509 million per incident but not more than $76 million in any one year for each incident. In addition to the public liability insurance provided pursuant to the Price-Anderson Act, NG purchases insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. NG is a Member Insured of NEIL, which provides coverage for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. NG, as the Member Insured and each entity with an insurable interest, purchases policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $1.4 billion for replacement power costs incurred during an outage after an initial 12-week waiting period. 135 NG, as the Member Insured and each entity with an insurable interest, is insured under property damage insurance provided by NEIL. Under these arrangements, up to $2.75 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. Member Insureds of NEIL pay annual premiums and are subject to retrospective premium assessments if losses exceed the accumulated funds available to the insurer. NG purchases insurance through NEIL that will pay its obligation in the event a retrospective premium call is made by NEIL, subject to the terms of the policy. FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of NG'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 FirstEnergy’s insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs. The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.06 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds. 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, 2017, outstanding guarantees and other assurances aggregated approximately $3.8 billion, consisting of parental guarantees ($1.2 billion), subsidiaries' guarantees ($1.8 billion), other guarantees ($275 million) and other assurances ($459 million). Of the aggregate amount, substantially all relates to guarantees of wholly-owned consolidated entities of FirstEnergy. FES' debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each of FG and NG. Accordingly, present and future holders of indebtedness of FES, FG and NG would have claims against each of FES, FG and NG, regardless of whether their primary obligor is FES, FG or NG. 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 CES' power portfolio exposure as of December 31, 2017, FES has posted collateral of $123 million and AE Supply has posted collateral of $4 million. The Regulated Distribution Segment has posted collateral of $4 million. 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, 2017: 136 Potential Collateral Obligations FES AE Supply Regulated FE Corp Total (In millions) Contractual Obligations for Additional Collateral At Current Credit Rating Upon Further Downgrade Surety Bonds (Collateralized Amount)(1) Total Exposure from Contractual Obligations $ $ 4 $ — 16 20 $ 1 — 1 2 $ $ — $ — $ 41 107 148 $ — 237 237 $ 5 41 361 407 (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 and the Hatfield's Ferry disposal site, respectively. Excluded from the preceding table are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment. As of December 31, 2017, FES has $2 million of collateral posted with its affiliates. OTHER COMMITMENTS AND CONTINGENCIES FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding's outstanding principal balance is $275 million. 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 and other environmental matters. Pursuant to a March 28, 2017 executive order, the EPA and other federal agencies are to review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof, in particular with respect to existing environmental regulations, may impact its business, results of operations, cash flows and financial condition. Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. 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, generating more electricity from lower or non-emitting plants 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. 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 be material and changes to FirstEnergy's and FES' operations may result. The EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015. The EPA stated the vast majority of U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and state rules and programs but the EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017. 137 The EPA missed the October 1, 2017, deadline and has not yet promulgated the attainment designations. States will then have roughly three years to develop implementation plans to attain the new 2015 ozone NAAQS. On December 5, 2017, fourteen states and the District of Columbia filed complaints in the U.S. District Court of Northern California seeking an order that the EPA promulgate the attainment designations for the new 2015 ozone NAAQS. Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be material and changes to FirstEnergy’s and FES’ operations may result. 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 seeks a short-term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. On September 27, 2016, the EPA extended the time frame for acting on the State of Delaware's CAA Section 126 petition by six months to April 7, 2017, but has not taken any further action. On January 2, 2018, the State of Delaware provided the EPA a notice required at least 60 days prior to filing a suit seeking to compel the EPA to either approve or deny the August 2016 CAA Section 126 petition. 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, Mansfield Unit 1 and Pleasants Units 1 and 2, significantly contribute to Maryland's inability to attain the ozone NAAQS. The petition seeks NOx emission rate limits for the 36 EGUs by May 1, 2017. On January 3, 2017, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to July 15, 2017, but has not taken any further action. On September 27, 2017, and October 4, 2017, the State of Maryland and various environmental organizations filed complaints in the U.S. District Court for the District of Maryland seeking an order that the EPA either approve or deny the CAA Section 126 petition of November 16, 2016. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss. MATS imposed emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired EGUs effective in April 2015 with averaging of emissions from multiple units located at a single plant. The majority of FirstEnergy's MATS compliance program and related costs have been completed. On August 3, 2015, FG, a wholly owned subsidiary of FES, submitted to the AAA office in New York, N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure event that excuses FG’s performance under its coal transportation contract with these parties. Specifically, the dispute arose from a contract for the transportation by BNSF and CSX of a minimum of 3.5 million tons of coal annually through 2025 to certain coal-fired power plants owned by FG that are located in Ohio. As a result of and in compliance with MATS, all plants covered by this contract were deactivated by April 16, 2015. Separately, on August 4, 2015, BNSF and CSX submitted to the AAA office in Washington, D.C., a demand for arbitration and statement of claim against FG alleging that FG breached the contract and that FG’s declaration of a force majeure under the contract is not valid and seeking damages under the contract through 2025. On May 31, 2016, the parties agreed to a stipulation that if FG’s force majeure defense is determined to be wholly or partially invalid, liquidated damages are the sole remedy available to BNSF and CSX. The arbitration panel consolidated the claims and held a hearing in November and December 2016. On April 12, 2017, the arbitration panel ruled on liability in favor of BNSF and CSX. In the liability award, the panel found, among other things, that FG’s demand for declaratory judgment that force majeure excused FG’s performance was denied, that FG breached and repudiated the coal transportation contract and that the panel retains jurisdiction of claims for liquidated damages for the years 2015-2025. On May 1, 2017, FE and FG and CSX and BNSF entered into a definitive settlement agreement, which resolved all claims related to this consolidated proceeding on the terms and conditions set forth below. Pursuant to the settlement agreement, FG will pay CSX and BNSF an aggregate amount equal to $109 million, which is payable in three annual installments, the first of which was made on May 1, 2017. FE agreed to unconditionally and continually guarantee the settlement payments due by FG pursuant to the terms of the settlement agreement. The settlement agreement further provides that in the event of the initiation of bankruptcy proceedings or failure to make timely settlement payments, the unpaid settlement amount will immediately accelerate and become due and payable in full. Further, FE and FG, and CSX and BNSF, agreed to release, waive and discharge each other from any further obligations under the claims covered by the settlement agreement upon payment in full of the settlement amount. Until such time, CSX and BNSF will retain the claims covered by the settlement agreement and in the event of a bankruptcy proceeding with respect to FG, to the extent the remaining settlement payments are not paid in full by FG or FE, CSX and BNSF shall be entitled to seek damages for such claims in an amount to be determined by the arbitration panel or otherwise agreed by the parties. On December 22, 2016, FG, a wholly owned subsidiary of FES, received a demand for arbitration and statement of claim from BNSF and NS which are the counterparties to the coal transportation contract covering the delivery of 2.5 million tons annually through 2025, for FG’s coal-fired Bay Shore Units 2-4, deactivated on September 1, 2012, as a result of the EPA’s MATS and for FG’s W.H. Sammis generating station. The demand for arbitration was submitted to the AAA office in Washington, D.C., against FG alleging, among other things, that FG breached the agreement in 2015 and 2016 and repudiated the agreement for 2017-2025. The counterparties are seeking liquidated damages through 2025, and a declaratory judgment that FG's claim of force majeure is invalid. The arbitration hearing is scheduled for June 2018. The parties have exchanged settlement proposals to resolve all claims related to this proceeding, however, discussions have been terminated and settlement is unlikely. FirstEnergy and FES recorded a pre-tax charge of $116 million in 2017 based on an estimated range of losses regarding the ongoing litigation with respect to this agreement. If the case proceeds to arbitration, the amount of damages owed to BNSF and NS could be materially higher and may cause FES to seek protection under U.S. bankruptcy laws. FG intends to vigorously assert its position in this arbitration proceeding, and if it were ultimately determined that the force majeure provisions or other defenses do not excuse the delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. As to a specific coal supply agreement, AE Supply, the party thereto, asserted termination rights effective in 2015 as a result of MATS. In response to notification of the termination, on January 15, 2015, Tunnel Ridge, LLC, the coal supplier, commenced litigation 138 in the Court of Common Pleas of Allegheny County, Pennsylvania, alleging AE Supply did not have sufficient justification to terminate the agreement and seeking damages for the difference between the market and contract price of the coal, or lost profits plus incidental damages. AE Supply filed an answer denying any liability related to the termination. On May 1, 2017, the complaint was amended to add FE, FES and FG, although not parties to the underlying contract, as defendants and to seek additional damages based on new claims of fraud, unjust enrichment, promissory estoppel and alter ego. On June 27, 2017, after oral argument, defendants' preliminary objections to the amended complaint were denied. On February 18, 2018, the parties reached an agreement in principle settling all claims in dispute. The agreement in principle includes, among other matters, a $93 million payment by AE Supply, as well as certain coal supply commitments for Pleasants Power Station during its remaining operation by AE Supply. Certain aspects of the final settlement agreement will be guaranteed by FE, including the $93 million payment. In September 2007, AE received an NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia. The EPA's NOV alleges equipment replacements during maintenance outages triggered the pre-construction permitting requirements under the NSR and PSD programs. On June 29, 2012, January 31, 2013, March 27, 2013 and October 18, 2016, the EPA issued CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. On December 12, 2014, the EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009. FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss. Climate Change FirstEnergy has established a goal to reduce CO2 emissions by 90% below 2005 levels by 2045. 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. The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act,” in December 2009, 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. On June 23, 2014, the U.S. Supreme Court decided that CO2 or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies. The EPA released its final CPP regulations in August 2015 (which have been stayed by the U.S. Supreme Court), to reduce CO2 emissions from existing fossil fuel-fired EGUs. The EPA also 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 January 21, 2016, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument. 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. Depending on the outcomes of the review pursuant to the executive order, of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material. 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 and in September 2016, 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 was ratified by the requisite number of countries (i.e., at least 55 countries representing at least 55% of global GHG emissions) in October 2016 and its non-binding obligations to limit global warming to well 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. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators. 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 plants. 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 139 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. The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits. On April 13, 2017, the EPA granted a Petition for Reconsideration and administratively stayed (effective upon publication in the Federal Register) all deadlines in the effluent limits rule pending a new rulemaking. Also, on September 18, 2017, the EPA postponed certain compliance deadlines for two years. 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 and FES' operations may result. In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the effluent limits that were effective immediately under the terms of the NPDES permit. MP appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require an initial capital investment ranging from $150 million to $300 million in order to install technology to meet the TDS and sulfate limits, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of the appeal or estimate the possible loss or range of loss. FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the loss or range of loss. 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. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although not currently expected, changes in timing and closure plan requirements in the future, including changes resulting from the strategic review at CES, could materially and adversely impact FirstEnergy's and FES' AROs. Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRs by December 31, 2016, and FG to provide bonding for 45 years of closure and post- closure activities and to complete closure within a 12-year period, but authorizing FG to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCRs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The CCRs from the Bruce Mansfield plant are being beneficially reused with the majority used for reclamation of a site owned by the Marshall County Coal Company in Moundsville, W. Va., and the remainder recycled into drywall by National Gypsum. These beneficial reuse options should be sufficient for ongoing plant operations, however, the Bruce Mansfield plant is pursuing other options. On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR. The Sierra Club's Notices of Appeal before the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility were resolved through a Consent Adjudication between FG, PA DEP and the Sierra Club requiring operational changes that became effective November 3, 2017. 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, 2017, based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $125 million have been accrued through December 31, 2017. Included in the total are accrued liabilities of approximately $80 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered 140 by JCP&L through a non-bypassable SBC. FirstEnergy 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, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of December 31, 2017, FirstEnergy had approximately $2.7 billion (FES $1.9 billion) invested in external trusts to be used for the decommissioning and environmental remediation of its nuclear generating facilities. The values of FirstEnergy's NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, FirstEnergy's obligation 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. As part of routine inspections of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. These inspections revealed that the cracking condition had propagated a small amount in select areas. FENOC's analysis confirms that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions. In a May 28, 2015, Inspection Report regarding the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation for FENOC’s failure to request and obtain a license amendment for its method of evaluating the significance of the shield building cracking. The NRC also concluded that the shield building remained capable of performing its design safety functions despite the identified laminar cracking and that this issue was of very low safety significance. In 2017, FENOC commenced a multi-year effort to implement repairs to the shield building. In addition to these ongoing repairs, FENOC intends to submit a license amendment application to the NRC to reconcile the shield building laminar cracking concern. FES provides a parental support agreement to NG of up to $400 million. The NRC typically relies on such parental support agreements to provide additional assurance that U.S. merchant nuclear plants, including NG's nuclear units, have the necessary financial resources to maintain safe operations, particularly in the event of extraordinary circumstances. So long as FES remains in the unregulated companies' money pool, the $500 million secured line of credit with FE discussed above provides FES the needed liquidity in order for FES to satisfy its nuclear support obligations to NG. Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The loss or range of loss in these matters is not expected to be material to FirstEnergy or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 15, "Regulatory Matters," of the Combined Notes to Consolidated Financial Statements. 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 FirstEnergy 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 FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows. 17. TRANSACTIONS WITH AFFILIATED COMPANIES FES’ operating revenues, operating expenses, investment income and interest expenses include transactions with affiliated companies. These affiliated company transactions include affiliated company power sales agreements between FirstEnergy's competitive and regulated companies, support service billings, including corporate and nuclear facility operational and maintenance support, interest on affiliated company notes including the money pools and other transactions. FirstEnergy's competitive companies at times provide power through affiliated company power sales to meet a portion of the Utilities' POLR and default service requirements and provide power to certain affiliates' facilities. The primary affiliated company transactions for FES during the three years ended December 31, 2017 are as follows: 141 FES Revenues: Electric sales to affiliates Other Expenses: Purchased power from affiliates Fuel Support services Investment Income: Interest income from FE Interest Expense: Interest expense to affiliates Interest expense to FE 2017 2016 (In millions) 2015 $ $ $ 366 11 201 4 775 13 — 19 459 11 622 4 748 2 5 2 666 14 353 1 705 2 4 3 FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are charged to FES and the Utilities from FESC and FENOC. 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 and FENOC. 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. FES purchases the entire output of the generation facilities owned by FG and NG. Prior to June 1, 2017, FES purchased the output relating to leasehold interests of OE and TE in certain of those facilities that were subject to sale and leaseback arrangements, and pursuant to full output, cost-of-service PSAs. Prior to April 1, 2016, FES financially purchased the uncommitted output of AE Supply's generation facilities under a PSA. On December 21, 2015, FES agreed under a PSA to physically purchase all the output of AE Supply's generation facilities effective April 1, 2016. FES and AE Supply terminated the PSA effective on April 1, 2017. Additionally, FES and AE Supply are parties to an affiliated commodity transfer agreement in which AE Supply sells coal to FES in accordance with the terms and conditions set forth under the respective coal purchase agreements that AE Supply has with a third party. During 2017, AE Supply sold 0.4 million tons of coal for $15 million to FES at market prices. During 2016 and 2015, AE Supply sold 1.5 million and 1.2 million tons of coal to FES, respectively, at its cost of $80 million and $63 million, respectively. During 2017 and 2016, FES sold 1.1 million and 0.4 million tons of coal to AE Supply, respectively, for $41 million and $16 million, respectively, at market prices. Also during 2016, FES sold 0.7 million tons of coal to MP for $31 million at market prices. FES had no intercompany sales of coal to AE Supply or MP in 2015. FES and the Utilities are parties to an intercompany income tax allocation agreement with FE and its other subsidiaries 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 6, "Taxes"). 142 18. SUPPLEMENTAL GUARANTOR INFORMATION In 2007, FG, a 100% owned subsidiary of FES, completed a sale and leaseback transaction for a 93.83% undivided interest in Bruce Mansfield Unit 1. FG's parent company, FES has fully and unconditionally and irrevocably guaranteed all of FG's obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FG or its parent company, but the notes are secured by, among other things, each lessor trust's undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES' lease guaranty. This transaction is classified as an operating lease for FES and FirstEnergy and as a financing lease for FG. The Condensed Consolidating Statements of Income (Loss) and Comprehensive Income (Loss) for the years ended December 31, 2017, 2016, and 2015, Condensed Consolidating Balance Sheets as of December 31, 2017 and December 31, 2016, and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2017, 2016, and 2015, for the parent and guarantor and non-guarantor subsidiaries are presented below. These statements are provided as FG's parent company fully and unconditionally guarantees outstanding registered securities of FG as well as FG's obligations under the facility lease for the Bruce Mansfield sale and leaseback that underlie outstanding registered pass-through trust certificates. Investments in wholly owned subsidiaries are accounted for by the parent company using the equity method. Results of operations for FG and NG are, therefore, reflected in their parent company's investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction. 143 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Year Ended December 31, 2017 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES OPERATING EXPENSES: Fuel Purchased power from affiliates Purchased power from non-affiliates Other operating expenses Pension and OPEB mark-to-market adjustment Provision for depreciation General taxes Impairment of assets and related charges Total operating expenses OPERATING INCOME (LOSS) OTHER INCOME (EXPENSE): Investment income (loss), including net income (loss) from equity investees Miscellaneous income Interest expense — affiliates Interest expense — other Capitalized interest Total other income (expense) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) INCOME TAXES (BENEFITS) $ 3,037 $ 1,062 $ 1,362 $ (2,363) $ 3,098 — 2,488 628 322 (12) 12 20 — 3,458 (421) (1,864) 1 (75) (46) — (1,984) (2,405) (14) 390 — — 490 (30) 32 21 — 903 159 39 1 (11) (104) 2 (73) 86 360 209 76 — 653 66 67 17 2,031 3,119 — (2,363) — 49 — (2) — — (2,316) 599 201 628 1,514 24 109 58 2,031 5,164 (1,757) (47) (2,066) 113 5 (1) (44) 24 97 (1,660) (78) 1,806 — 68 56 — 1,930 1,883 27 94 7 (19) (138) 26 (30) (2,096) 295 NET INCOME (LOSS) $ (2,391) $ (274) $ (1,582) $ 1,856 $ (2,391) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (2,391) $ (274) $ (1,582) $ 1,856 $ (2,391) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs Amortized gain on derivative hedges Change in unrealized gain on available-for-sale securities Other comprehensive income (loss) Income taxes (benefits) on other comprehensive income (loss) (14) 2 30 18 6 (13) — — (13) (5) — — 30 30 10 13 — (30) (17) (5) (14) 2 30 18 6 Other comprehensive income (loss), net of tax COMPREHENSIVE INCOME (LOSS) 12 (2,379) $ $ (8) (282) $ 20 (1,562) $ (12) 1,844 $ 12 (2,379) 144 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Year Ended December 31, 2016 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES OPERATING EXPENSES: Fuel Purchased power from affiliates Purchased power from non-affiliates Other operating expenses Pension and OPEB mark-to-market adjustment Provision for depreciation General taxes Impairment of assets and related charges Total operating expenses $ 4,242 $ 1,739 $ 2,004 $ (3,587) $ 4,398 — 4,024 1,020 310 (1) 13 31 39 5,436 582 — — 286 (4) 120 30 3,937 4,951 198 187 — 632 53 206 27 4,729 6,032 — (3,587) — 49 — (3) — (83) (3,624) 780 624 1,020 1,277 48 336 88 8,622 12,795 OPERATING LOSS (1,194) (3,212) (4,028) 37 (8,397) OTHER INCOME (EXPENSE): Investment income (loss), including net income (loss) from equity investees Miscellaneous income Interest expense — affiliates Interest expense — other Capitalized interest Total other income (expense) (4,585) 4 (50) (55) — (4,686) 30 3 (10) (105) 8 (74) 84 — (4) (44) 26 62 4,538 — 57 57 — 4,652 67 7 (7) (147) 34 (46) LOSS BEFORE INCOME TAX BENEFITS (5,880) (3,286) (3,966) 4,689 (8,443) INCOME TAX BENEFITS NET LOSS (425) (1,169) (1,429) 35 (2,988) $ (5,455) $ (2,117) $ (2,537) $ 4,654 $ (5,455) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET LOSS $ (5,455) $ (2,117) $ (2,537) $ 4,654 $ (5,455) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs Amortized gain on derivative hedges Change in unrealized gain on available-for-sale securities Other comprehensive income (loss) Income taxes (benefits) on other comprehensive income (loss) (14) — 52 38 15 (14) — — (14) (5) — — 52 52 20 14 — (52) (38) (15) (14) — 52 38 15 Other comprehensive income (loss), net of tax COMPREHENSIVE LOSS 23 (5,432) $ (9) (2,126) $ 32 (2,505) $ $ (23) 4,631 $ 23 (5,432) 145 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Year Ended December 31, 2015 FES FG NG Eliminations Consolidated (In millions) $ 4,824 $ 1,801 $ 2,138 $ (3,758) $ 5,005 OPERATING INCOME (LOSS) (1,134) 687 STATEMENTS OF INCOME REVENUES OPERATING EXPENSES: Fuel Purchased power from affiliates Purchased power from non-affiliates Other operating expenses Pension and OPEB mark-to-market adjustment Provision for depreciation General taxes Impairment of assets and related charges Total operating expenses OTHER INCOME (EXPENSE): Investment income (loss), including net income (loss) from equity investees Miscellaneous income Interest expense — affiliates Interest expense — other Capitalized interest Total other income (expense) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) INCOME TAXES (BENEFITS) NET INCOME STATEMENTS OF COMPREHENSIVE INCOME NET INCOME OTHER COMPREHENSIVE LOSS: Pension and OPEB prior service costs Amortized gain on derivative hedges Change in unrealized gain on available-for-sale securities Other comprehensive loss Income tax benefits on other comprehensive loss Other comprehensive loss, net of tax COMPREHENSIVE INCOME $ $ $ 871 353 1,684 1,308 57 324 98 33 4,728 277 (14) 3 (7) (147) 35 (130) 147 65 82 82 (6) (3) (9) (18) (7) (11) 71 — 3,826 1,684 378 (8) 12 45 21 5,958 679 — — 273 10 124 26 2 1,114 844 1 (29) (52) — 764 (370) (452) 17 2 (8) (104) 6 (87) 600 224 192 285 — 608 55 191 27 10 1,368 770 (5) — (4) (49) 29 (29) 741 278 — (3,758) — 49 — (3) — — (3,712) (46) (870) — 34 58 — (778) (824) 15 82 $ 376 $ 463 $ (839) $ 82 $ 376 $ 463 $ (839) $ (6) (3) (9) (18) (7) (11) 71 $ (5) — — (5) (2) (3) 373 $ — — (8) (8) (3) (5) 458 $ 5 — 8 13 5 8 (831) $ 146 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2017 FES FG NG (In millions) Eliminations Consolidated ASSETS CURRENT ASSETS: Cash and cash equivalents Receivables- Customers Affiliated companies Other Notes receivable from affiliated companies Materials and supplies Derivatives Collateral Prepaid taxes and other PROPERTY, PLANT AND EQUIPMENT: In service Less — Accumulated provision for depreciation Construction work in progress INVESTMENTS: Nuclear plant decommissioning trusts Investment in affiliated companies Other DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits Property taxes Other LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt Short-term borrowings - affiliated companies Accounts payable- Affiliated companies Other Accrued taxes Derivatives Other CAPITALIZATION: Total equity (deficit) Long-term debt and other long-term obligations NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction Retirement benefits Asset retirement obligations Other 1 181 224 21 — 183 34 130 22 796 2,495 1,823 672 22 694 1,856 — 9 1,865 1,754 25 380 2,159 5,514 524 105 255 105 72 24 169 1,254 (2,070) 2,299 229 723 153 1,945 1,210 4,031 5,514 $ — $ 1 $ — $ — $ — 80 8 1,744 142 — 25 12 2,012 2,646 1,947 699 19 718 — — 9 9 790 9 310 1,109 3,848 438 402 60 83 12 2 73 1,070 547 1,666 2,213 — 125 187 253 565 3,848 $ $ $ — 260 — 1,512 — — — — 1,772 8 — 8 — 8 1,856 — — 1,856 890 16 — 906 4,542 114 — 194 — 21 — 11 340 528 1,007 1,535 — — 1,758 909 2,667 4,542 $ $ $ — (326) — (3,622) — — — — (3,948) (281) (189) (92) — (92) — (1,153) — (1,153) (193) — 25 (168) (5,361) $ (28) $ (3,622) (319) — (13) — 41 (3,941) (1,075) (1,065) (2,140) 723 — — (3) 720 (5,361) $ 181 210 13 366 41 34 105 10 960 122 65 57 3 60 — 1,153 — 1,153 267 — 45 312 2,485 $ — $ 3,325 320 22 52 22 44 3,785 (2,070) 691 (1,379) — 28 — 51 79 2,485 $ 147 $ $ $ FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2016 FES FG NG (In millions) Eliminations Consolidated ASSETS CURRENT ASSETS: Cash and cash equivalents Receivables- Customers Affiliated companies Other Notes receivable from affiliated companies Materials and supplies Derivatives Collateral Prepaid taxes and other PROPERTY, PLANT AND EQUIPMENT: In service Less — Accumulated provision for depreciation Construction work in progress INVESTMENTS: Nuclear plant decommissioning trusts Investment in affiliated companies Other DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits Property taxes Derivatives Other LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt Short-term borrowings - affiliated companies Accounts payable- Affiliated companies Other Accrued taxes Derivatives Other CAPITALIZATION: Total equity Long-term debt and other long-term obligations NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction Retirement benefits Asset retirement obligations Other 2 213 452 27 29 267 137 157 63 1,347 7,057 5,929 1,128 427 1,555 1,552 — 10 1,562 2,279 40 77 381 2,777 7,241 179 101 550 110 143 77 156 1,316 218 2,813 3,031 757 197 901 1,039 2,894 7,241 $ — $ 2 $ — $ — $ — 315 2 1,585 142 — — 24 2,070 2,524 1,920 604 67 671 — — 9 9 1,271 12 — 327 1,610 4,360 200 483 107 93 48 6 54 991 828 2,093 2,921 — 172 188 88 448 4,360 $ $ $ — 417 8 1,294 80 — — 1 1,800 4,703 4,144 559 358 917 1,552 — 1 1,553 883 28 — — 911 5,181 5 — 406 — 61 — 10 482 2,006 1,120 3,126 — — 713 860 1,573 5,181 $ $ $ — (612) — (3,351) — — — — (3,963) (290) (187) (103) — (103) — (2,923) — (2,923) (270) — — 21 (249) (7,238) $ (26) $ (3,351) (706) — (16) — 36 (4,063) (2,834) (1,091) (3,925) 757 — — (7) 750 (7,238) $ 213 332 17 501 45 137 157 38 1,440 120 52 68 2 70 — 2,923 — 2,923 395 — 77 33 505 4,938 $ — $ 2,969 743 17 50 71 56 3,906 218 691 909 — 25 — 98 123 4,938 $ 148 $ $ $ FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2017 FES FG NG Eliminations Consolidated (In millions) $ (485) $ 516 $ 722 $ (26) $ 727 356 (81) — (1) 355 (2) — — — (3) 135 130 — — — (5) — (5) (185) (254) 940 (999) — (219) (717) — — (271) 26 — (245) — — — — — 271 271 — — $ — $ — $ 4 (163) (7) (166) (275) (254) 940 (999) (3) 29 (562) (1) 2 1 (184) (6) (271) (88) — — — — (158) (246) (1) 2 1 NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net Redemptions and Repayments- Long-term debt Other Net cash provided from (used for) financing activities CASH FLOWS FROM INVESTING ACTIVITIES: Property additions Nuclear fuel Sales of investment securities held in trusts Purchases of investment securities held in trusts Cash Investments Loans to affiliated companies, net Net cash provided from (used for) investing activities Net change in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period $ — $ 149 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2016 FES FG NG Eliminations Consolidated (In millions) $ (842) $ 550 $ 1,103 $ (25) $ 786 — 948 — — 948 186 94 (224) (7) 49 (30) (224) — 9 — — 10 (95) — (106) — — — — — — — (376) 1 — 2 2 285 — (308) (2) (25) (292) (232) — 717 (783) — (488) — — — — (941) 25 — (916) — — — — — — 941 — 941 — — (599) (1,078) $ — $ — $ 471 101 (507) (9) 56 (546) (232) 9 717 (783) 10 (18) 1 (842) — 2 2 NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt Short-term borrowings, net Redemptions and Repayments- Long-term debt 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 Cash investments Loans to affiliated companies, net Other Net cash used for investing activities Net change in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period $ — $ 150 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2015 FES FG NG Eliminations Consolidated (In millions) $ (637) $ 552 $ 1,261 $ (24) $ 1,152 — 796 (17) — (70) — 709 (5) — 10 — — (10) (67) — (72) — — 45 67 (70) — — (6) 36 (223) — 3 — — — (372) 4 296 — (348) (28) — (1) (81) (399) (190) — 733 (791) — (533) — (588) (1,180) — 2 2 — — — (863) 24 (98) — — (937) — — — — — — 961 — 961 — — $ — $ — $ 341 — (411) (126) (70) (7) (273) (627) (190) 13 733 (791) (10) (11) 4 (879) — 2 2 NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt Short-term borrowings, net Redemptions and Repayments- Long-term debt Short-term borrowings, net Common stock dividend payment 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 Cash investments Loans to affiliated companies, net Other Net cash used for investing activities Net change in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period $ — $ 151 19. SEGMENT INFORMATION FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission and CES. Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does not have separate reportable operating segments. 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 commodity costs of securing electric generation and the deferral and amortization of certain fuel costs. The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, MAIT (effective January 31, 2017) and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP). The segment's revenues are primarily derived from forward-looking rates at ATSI and TrAIL, as well as stated transmission rates at certain of FirstEnergy's utilities. As discussed in Note 15, "Regulatory Matters - FERC Matters," above, MAIT and JCP&L submitted applications to FERC requesting authorization to implement forward-looking formula transmission rates. In March 2017, FERC approved JCP&L's and MAIT's forward-looking formula rates, subject to refund, with effective dates of June 1, 2017, and July 1, 2017, respectively. Additionally, MAIT and JCP&L filed settlement agreements with FERC on October 13, 2017 and December 21, 2017, respectively, both pending final orders by FERC. Both the forward-looking and stated rates recover costs and provide a return on transmission capital investment. Under forward-looking rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which are 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. The CES segment, through FES and AE Supply, primarily supplies electricity to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. As of January 31, 2018, this business segment controlled 12,303 MWs of electric generating capacity, including, as discussed in Note 2, "Asset Sales and Impairments," 756 MWs of generating capacity which remain subject to an asset purchase agreement with a subsidiary of LS Power that is expected to close in the first half of 2018. The CES segment’s operating results are primarily derived from electric generation sales less the related costs of electricity generation, including fuel, purchased power and net transmission (including congestion) and ancillary costs and capacity costs charged by PJM to deliver energy to the segment’s customers, as well as other operating and maintenance costs, including costs incurred by FENOC. Interest expense on stand-alone holding company debt, corporate income taxes and other businesses that do not constitute an operating segment are categorized as Corporate/Other for reportable business segment purposes. Additionally, reconciling adjustments for the elimination of inter-segment transactions are included in Corporate/Other. As of December 31, 2017, Corporate/ Other had $6.8 billion of stand-alone holding company long-term debt, of which $1.45 billion was subject to variable-interest rates, and $300 million was borrowed by FE under its revolving credit facility. On January 22, 2018, FE repaid its $1.45 billion of outstanding variable-interest rate debt using the proceeds from the $2.5 billion equity investment. 152 Segment Financial Information For the Years Ended December 31 Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Reconciling Adjustments Consolidated (In millions) 2017 External revenues Internal revenues Total revenues Depreciation Amortization of regulatory assets, net Impairment of assets and related charges Investment income Interest expense Income taxes (benefits) Net income (loss) Total assets Total goodwill Property additions 2016 External revenues Internal revenues Total revenues Depreciation Amortization of regulatory assets, net Impairment of assets and related charges Investment income Interest expense Income taxes (benefits) Net income (loss) Total assets Total goodwill Property additions 2015 External revenues Internal revenues Total revenues Depreciation Amortization of regulatory assets, net Impairment of assets and related charges Investment income (loss) Impairment of equity method investment Interest expense Income taxes (benefits) Net income (loss) Total assets Total goodwill Property additions $ 9,734 $ 1,325 $ 3,143 $ — $ — 9,734 724 292 — 54 535 580 916 27,730 5,004 1,191 — 1,325 224 16 41 — 156 205 336 9,525 614 1,030 386 3,529 118 — 2,365 81 179 155 (2,641) 4,339 — 317 — — 72 — — 11 308 (45) (335) 663 — 49 $ 9,629 $ 1,144 $ 4,070 $ — $ — 9,629 676 290 — 49 586 375 651 27,702 5,004 1,063 — 1,144 187 7 — — 158 187 331 8,755 614 1,101 479 4,549 387 — 10,665 66 194 (3,498) (6,919) 5,952 — 619 — — 63 — — 10 219 (119) (240) 739 — 52 $ 9,582 $ 1,046 $ 4,698 $ — $ — 9,582 664 165 8 42 — 600 325 588 27,390 5,092 1,040 — 1,046 164 7 — — — 147 191 328 7,800 526 1,020 686 5,384 394 — 34 (16) — 192 50 89 16,027 800 588 — — 60 — — (9) 362 193 (251) (427) 877 — 56 (185) $ (386) (571) — — — (48) — — — — — — (281) $ (479) (760) — — — (41) — — — — — — (300) $ (686) (986) — — — (39) — — — — — — — 14,017 — 14,017 1,138 308 2,406 98 1,178 895 (1,724) 42,257 5,618 2,587 14,562 — 14,562 1,313 297 10,665 84 1,157 (3,055) (6,177) 43,148 5,618 2,835 15,026 — 15,026 1,282 172 42 (22) 362 1,132 315 578 52,094 6,418 2,704 153 20. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED) The following summarizes certain consolidated operating results by quarter for 2017 and 2016. FirstEnergy CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions, except per share amounts) 2017 2016 Revenues Other operating expense Pension and OPEB mark-to-market adjustment Provision for depreciation Impairment of assets and related charges Operating Income (Loss) Income (loss) before income taxes (benefits) Income taxes (benefits) Net Income (Loss) Earnings (loss) per share of common stock-(1) Basic - Earnings (losses) Available to FirstEnergy Corp. Diluted - Earnings (losses) Available to FirstEnergy Corp. Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 $ 3,442 $ 3,714 $ 3,309 $ 3,552 $ 3,375 $ 3,917 $ 3,401 $ 3,869 1,195 141 293 2,244 (1,830) (2,086) 413 (2,499) 940 — 289 31 884 635 239 396 (5.62) 0.89 (5.62) 0.89 956 — 281 131 544 291 117 174 0.39 0.39 1,141 1,021 — 275 — 574 331 126 205 147 339 9,218 (8,924) (9,185) (3,389) (5,796) 950 — 311 — 861 631 251 380 963 — 334 1,447 (975) (1,219) (130) (1,089) 917 — 329 — 776 541 213 328 0.46 (13.44) 0.89 (2.56) 0.78 0.46 (13.44) 0.89 (2.56) 0.77 (1) The sum of quarterly earnings per share information may not equal annual earnings per share due to the issuance of shares throughout the year. See FirstEnergy's Consolidated Statements of Stockholders' Equity and Note 5, "Stock-Based Compensation Plans," for additional information. FES CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions) 2017 2016 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Revenues Other operating expense Pension and OPEB mark-to-market adjustment Provision for depreciation Impairment of assets and related charges Operating Income (Loss) Income (loss) from continuing operations before income taxes (benefits) Income taxes (benefits) Net Income (Loss) $ $ 700 419 24 29 2,031 (2,112) (2,125) 281 (2,406) 743 291 — 28 — 102 108 32 76 $ $ 741 286 — 27 — 61 42 23 19 914 518 — 25 — (117) (121) (41) (80) $ 997 352 48 86 8,082 (8,153) (8,171) (2,983) (5,188) $ 1,100 $ 1,102 $ 1,199 316 — 83 — 101 96 56 40 369 — 84 540 (571) (581) (143) (438) 240 — 83 — 226 213 82 131 154 21. SUBSEQUENT EVENTS January 2018 Equity Issuance On January 22, 2018, FirstEnergy entered into agreements for the private placement of its equity securities representing an approximately $2.5 billion investment in the Company. The Company entered into a Preferred Stock Purchase Agreement (the Preferred SPA) 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. The Company also entered into a Common Stock Purchase Agreement for the private placement of 30,120,482 shares of the Company’s common stock, par value $0.10 per share, representing an investment of $850 million. The Preferred Stock will participate 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 receive if its shares of Preferred Stock were converted on the dividend record date at the Conversion Price in effect at that time. Such dividends will be paid at the same time that the dividends on Common Stock are paid. Each share of Preferred Stock will be convertible into a number of shares of Common Stock equal to the $1,000 liquidation preference, divided by the Conversion Price then in effect. As of January 22, 2018, the Conversion Price in effect was $27.42 per share. The Conversion Price is 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. The Preferred Stock will generally be convertible at the option of holders beginning on July 22, 2018. The holders of Preferred Stock may also elect to convert their shares if the Company undergoes a fundamental change. Furthermore, the Preferred Stock will automatically convert to Common Stock upon certain events of bankruptcy or liquidation of the Company. The Company may elect to convert the Preferred Stock if, at any time, fewer than 323,200 shares of Preferred Stock are outstanding. In general, any shares of Preferred Stock outstanding on July 22, 2019, will be automatically converted. However, no shares of Preferred Stock will be converted prior to January 22, 2020, if such conversion will cause a converting holder to be deemed to beneficially own, together with its affiliates whose holdings would be aggregated with such holder for purposes of Section 13(d) under the Exchange Act, more than 4.9% of the then-outstanding Common Stock. Furthermore, in no event shall the Company issue more than 58,964,222 shares of Common Stock (the Share Cap) in the aggregate upon conversion of the Convertible Preferred Stock. From and after the time at which the aggregate number of shares of Common Stock issued upon conversion of the Preferred Stock equals the Share Cap, each holder electing to convert Convertible Preferred Stock will be entitled to receive a cash payment equal to the market value of the Common Stock such holder does not receive upon conversion. The holders of Preferred Stock will have limited class voting rights related to the creation of additional securities that are senior or equal with the Preferred Stock, as well as certain reclassifications and amendments that would affect the rights of the holders of Preferred Stock. The holders of Preferred Stock will also have the right to approve issuances of securities convertible or exchangeable for Common Stock, subject to certain exceptions for compensation arrangements and bona fide dividend reinvestment or share purchase plans. Pursuant to the Preferred SPA, FirstEnergy formed a RWG composed of three employees of FirstEnergy and two outside members to advise FirstEnergy management regarding an FES restructuring in the event the FES Board decides to seek bankruptcy protection. Bruce Mansfield Plant On the morning of January 10, 2018, Bruce Mansfield plant personnel were in the process of shutting down Unit 1 for a maintenance outage when an equipment failure resulted in an unplanned outage for Unit 2 that led to the loss of plant power. Later that morning, a fire damaged the scrubber, stack and other plant property and systems associated with Units 1 and 2. Evaluation of the extent of the damage, which may be significant, to the scrubber, stack and other plant property and systems associated with Units 1 and 2 is underway and is expected to take several weeks. Unit 3, which had been off-line for maintenance, was unaffected by the January 10th fire. The affected plant property and systems are insured and management is working with the insurance carriers to complete the assessment. At this time management is unable to estimate the financial effect of the fire on Units 1 and 2. MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 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, the respective management of each registrant conducted an evaluation of the effectiveness of their registrant’s internal control over financial reporting under the supervision of each respective registrant’s chief executive officer and chief financial officer. Based on that evaluation, the respective management of each registrant concluded that their registrant’s internal control over financial reporting was effective as of December 31, 2017. The effectiveness of FirstEnergy’s internal control over financial reporting, as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included herein. The effectiveness of internal control over financial reporting of FES as of December 31, 2017, has not been audited by the registrant's independent registered public accounting firm. 155 Executive Officers as of February 20, 2018 Name G. D. Benz D. M. Chack M. J. Dowling B. L. Gaines C. E. Jones C. D. Lasky J. F. Pearson R. P. Reffner S. E. Strah K. J. Taylor L. L. Vespoli Age 58 67 53 64 62 54 63 67 54 44 58 Positions Held During Past Five Years Senior Vice President, Strategy (B) Vice President, Supply Chain (B) Senior Vice President, Product Development, Marketing and Branding (B) Senior Vice President, Marketing and Branding (B) President, Ohio Operations (B) Vice President (C) Senior Vice President, External Affairs (B) Senior Vice President, Corporate Services and Chief Information Officer (B) President and Chief Executive Officer (A)(B) Chief Executive Officer (F) President (C)(D)(H)(I)(L) Executive Vice President & President, FirstEnergy Utilities (A)(B) Senior Vice President & President, FirstEnergy Utilities (B) Senior Vice President, Human Resources (B) Vice President, Fossil Operations (J) Vice President (G) Vice President, Fossil Operations & Engineering (J) Vice President, Fossil Fleet Operations (J) Executive Vice President and Chief Financial Officer (N) Executive Vice President and Chief Financial Officer (A)(B)(C)(D)(H)(I)(L) Executive Vice President and Chief Financial Officer (F)(G) Executive Vice President and Chief Financial Officer (E)(J) Senior Vice President and Chief Financial Officer (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L) Vice President and General Counsel (N) Vice President and General Counsel (B)(C)(D)(H)(I)(L) Vice President and General Counsel (F)(G) Vice President and General Counsel (E)(J) Vice President, Legal (B) President (G) President (N) Senior Vice President & President, FirstEnergy Utilities (B) President (C)(D)(H)(I)(L) Vice President, Distribution Support (B) Vice President and Controller (N) Vice President, Controller and Chief Accounting Officer (A)(B) Vice President and Controller (C)(D)(H)(I)(L) Vice President and Controller (F)(G) Vice President and Controller (E)(J) Vice President and Assistant Controller (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L) Executive Vice President, Corporate Strategy, Regulatory Affairs & Chief Legal Officer (A)(B)(C)(D)(H)(I)(L)(N) Executive Vice President, Corporate Strategy, Regulatory Affairs & Chief Legal Officer (F)(G) Executive Vice President, Corporate Strategy, Regulatory Affairs & Chief Legal Officer (E)(J) Executive Vice President, Markets & Chief Legal Officer (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L) Executive Vice President and General Counsel (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L) E. L. Yeboah-Amankwah 40 Vice President, Corporate Secretary and Chief Ethics Officer (A)(B) Vice President, State and Federal Regulatory Legal Affairs (B) Vice President and Corporate Secretary (C)(D)(G)(H)(I)(L)(N) Dates 2015-present *-2015 2017-present 2015-2017 *-2015 *-2015 *-present *-present 2015-present 2015-2017 *-2015 2014 *-2013 2015-present 2014-2015 *-2015 2014 *-2013 2016-present 2015-present 2015-2017 2015-2016 *-2015 2016-present 2014-present 2014-2017 2014-2016 *-2013 2017-present 2016-present 2015-present 2015-present *-2015 2016-present 2013-present 2013-present 2013-2017 2013-2016 *-2013 2016-present 2016-2017 2016 2014-2016 *-2013 2017-present 2017 2017-present * Indicates position held at least since January 1, 2013 (A) Denotes executive officer of FE (B) Denotes executive officer of FESC (C) Denotes executive officer of OE, CEI and TE (D) Denotes executive officer of ME, PN and Penn (E) Denotes executive officer of FES (F) Denotes executive officer of FENOC (G) Denotes executive officer of AGC (H) Denotes executive officer of MP, PE and WP (I) Denotes executive officer of TrAIL and FET (J) Denotes executive officer of FG (K) Denotes executive officer of OE (L) Denotes executive officer of ATSI (M) Denotes executive officer of CEI (N) Denotes executive officer of MAIT 156 SHAREHOLDER SERVICES T R A N S F E R A G E N T A N D R E G I S T R A R 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 8:00 a.m. and 8:00 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/invest/firstenergy. S T O C K I N V E S T M E N T P L A N Registered shareholders and employees of the company can participate in the Stock Investment Plan. To learn more about the company’s Stock Investment Plan, visit AST’s website at https://us.astfinancial.com/invest/firstenergy or contact AST toll-free at 1-800-736-3402. D I R E C T D I V I D E N D D E P O S I T 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. S T O C K L I S T I N G A N D T R A D I N G The common stock of FirstEnergy is listed on the New York Stock Exchange under the symbol FE. F O R M 1 0 - K A N N U A L R E P O R T 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, 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/financialreports. 76 South Main Street, Akron, Ohio 44308-1890 

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