FirstEnergy
Annual Report 2015

Plain-text annual report

A N N U A L R E P O R T 2015 FINANCIAL HIGHLIGHTS K E Y A C C O M P L I S H M E N T S • Generated $3.4 billion in cash from operations • Secured a 20-year license extension from • Invested nearly $1 billion to modernize our transmission system as part of our Energizing the Future initiative • Launched our Cash Flow Improvement Project with the goal of capturing meaningful and sustainable savings across our company the Nuclear Regulatory Commission for the Davis-Besse Nuclear Power Station • Enhanced transmission and distribution system reliability F I N A N C I A L S A T A G L A N C E (dollars in millions, except per share amounts) TOTAL REVENUES NET INCOME BASIC AND DILUTED EARNINGS per common share DIVIDENDS PAID per common share BOOK VALUE per common share 2015 $15,026 $578 $1.37 $1.44 2014 $15,049 $299 $0.71 $1.44 $29.33 $29.49 2013 $14,892 $392 $0.94 $2.20 $30.32 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) 2015 2014 2013 $3,447 $2,713 $2,662 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 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 * 2015 2014 2013 2.80 2.56 2.47 0 0.5 1 1.5 2 2.5 3 N E T I N C O M E (in millions) 2015 2014 2013 $299 $392 $578 0 100 200 300 400 500 600 * 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 Charles E. Jones President and Chief Executive Officer We maintained a strong focus in 2015 on achieving more regulated, customer-focused growth for your company. Toward that end, we made significant investments to enhance the reliability and efficiency of our electric system. These included $986 million in targeted improvements during the year to our transmission system, and approximately $1.2 billion in capital upgrades that helped our regulated utilities continue to provide reliable service to customers. We also received approval on a forward-looking rate filing for our American Transmission Systems, Inc. (ATSI) transmission company, which will allow more effective and timely recovery of its system investments. Six of our regulated utilities received approval of settlements in distribution rate cases in 2015, and our rate case in New Jersey also was resolved, resulting in an overall revenue increase of $321 million. In Ohio, the Public Utilities Commission of Ohio (PUCO) is reviewing a settlement agreement with 17 key parties supporting our Electric Security Plan IV (ESP) for The Illuminating Company, Ohio Edison and Toledo Edison. The plan is expected to strengthen your company’s financial position in the years ahead and is designed to provide significant benefits to our customers and communities – including more stable rates, a renewed emphasis on energy efficiency and renewable power, and strong support for economic development. The PUCO is expected to rule on the ESP by the end of March. We also expect to achieve $240 million in annual savings by 2017 through our Cash Flow Improvement Project – a comprehensive effort our employees conducted in 2015, and will closely monitor in the years ahead, to reduce expenses and enhance revenue throughout our operations. In addition, we continue to execute a more conservative strategy for our competitive generation business that minimizes risk while taking advantage of market opportunities. 1 GROWING OUR REGULATED OPERATIONS We’re building a stronger energy system through our primary growth platform, Energizing the Future – an initial $4.2 billion investment in the long-term reliability of our transmission system that began in 2014 and runs through 2017. Spanning our entire transmission system, projects funded through the program are designed to meet the future energy needs of customers by adding resiliency to our bulk electric system, enhancing our facilities and equipment, and increasing physical and cyber security. Initial efforts primarily focused on the ATSI transmission system that encompasses the service areas of Ohio Edison, Toledo Edison, The Illuminating Company and Penn Power, with projects shifting eastward over time to include our other service areas. Work performed to date also has helped us identify $15 billion in additional opportunities across our 24,200-mile transmission system that will benefit customers through further reliability enhancements. Among other projects, we’re reinforcing our system to ensure grid reliability following the retirement of coal-fired power plants in our region. For example, since 2014, we’ve invested $500 million in transmission projects to support the deactivation of three of our power plants along Lake Erie. As part of this effort, we built a 119-mile transmission line from Beaver County, Pa., to our new Glenwillow substation in suburban Cleveland, as well as five new substations across portions of our Ohio service area. In addition, we’re nearing completion of a transmission reinforcement project in Harrison County, W.Va., that involves the construction of a new substation and a 6-mile transmission line. The project is expected to enhance service reliability for approximately 14,000 customers in the northern portion of West Virginia. Given that our regulated footprint is aligned with some of the nation’s richest shale fields, we’re making investments through 2020 to support growth in midstream shale gas operations 2 throughout our service area, including planned expansions that are expected to create 600 megawatts (MW) of new industrial load. For example, we recently completed preliminary site work for a new substation near Smithfield, W.Va., that is expected to support new shale gas operations as well as enhanced service reliability for Mon Power customers. Over the past few years, shale gas development has accounted for approximately 500 MW of new load growth in our region. We remain committed to providing safe, reliable service to our utility customers. All of our utilities outperformed state requirements for SAIDI – an industry- wide measure of the average outage duration for each customer served. In the critical area of safety, our companywide OSHA rate reached industry top-quartile performance in 2015. This reflects the great importance we place on safe work practices in every facet of our operations. A crew member welds a stainless steel roof for one of three, 1 million-gallon water tanks for the dewatering facility under construction at our Bruce Mansfield Plant. The facility is needed to dispose of the plant’s coal combustion byproducts following the scheduled closing of the Little Blue Run disposal site at the end of 2016. CREATING A SMARTER GRID As part of our Energizing the Future initiative, we began investing in nearly 900 smart grid projects designed to make our transmission system more robust, secure and resistant to extreme weather events as well as cyber and physical attacks. These smart grid technologies have the potential to significantly improve our response time to outages by enabling more efficient service restoration. In addition, remote monitoring devices can proactively evaluate grid conditions and take corrective actions even before outages occur. We’re also upgrading our transmission equipment with advanced technologies designed to enhance the reliability of our system and meet projected load growth in our region. We continued to move forward with our Pennsylvania smart meter program, installing more than 160,000 smart meters in our Penn Power service area by the end of 2015. Through this state- mandated effort, we plan to deploy more than 2 million smart meters across our Pennsylvania service area by mid-2019. Although smart grid technologies can be costly, we’re receiving full recovery of our investments in Pennsylvania’s smart meter program – and we will explore similar programs in other states that allow recovery of these costs. In fact, as part of our proposed ESP, we filed a plan to evaluate smart meter and smart grid technologies across our Ohio service area, subject to PUCO consideration and approval. NEARLY 32 MILLION MEGAWATT-HOURS OF CARBON-FREE ELECTRICITY GENERATED BY OUR THREE NUCLEAR POWER STATIONS IN 2015 3 ENSURING FAIR AND AFFORDABLE RATES We made significant progress during the year in our efforts to strengthen earnings by ensuring fair, appropriate and timely recovery of our transmission and distribution investments. In October, the Federal Energy Regulatory Commission (FERC) approved a settlement agreement for a forward-looking rate structure for ATSI, which owns and operates nearly 7,800 miles of transmission lines. This agreement provides more timely recovery of transmission investments that are essential to ensuring the future reliability of our service. FERC also approved a plan to transfer the transmission assets owned by three of our operating companies – Jersey Central Power & Light (JCP&L), Met-Ed and Penelec – to a new affiliate, Mid- Atlantic Interstate Transmission (MAIT). Similar to our existing ATSI and TrAILCo transmission companies, MAIT will help us more effectively finance and build transmission facilities within our Met-Ed, Penelec and JCP&L service areas while providing stronger support to our Energizing the Future initiative as it expands eastward. Although the New Jersey Board of Public Utilities (BPU) rejected one of the plan’s provisions, it continues to review the remainder of the proposal. We also filed a comprehensive settlement agreement with the Pennsylvania Public Utility Commission (PPUC) for approval of MAIT. Approval of our Ohio ESP by the PUCO would be an important step in our efforts to protect customers from future price volatility. The plan includes a rider that reflects the difference between the cost of an eight-year Purchased Power Agreement (PPA) and our Ohio utilities’ associated wholesale market revenues. The PPA supports the continued operation of two of our critical baseload power plants – the Davis-Besse Nuclear Power Station and the W.H. Sammis Plant – which would preserve more than $41 million in annual tax revenues and an estimated 3,000 direct and indirect jobs related to those facilities. Although the PPA has been challenged at FERC, we will continue to advocate for the plan’s many benefits in that proceeding. In February of 2016, the PPUC approved long-term infrastructure improvement plans for our four Pennsylvania utilities, supporting a projected increase in capital investment of nearly $245 million over the next five years to strengthen, upgrade and modernize our distribution systems in the state. The four utilities also filed rate riders that, with PPUC approval, would facilitate recovery of these investments. Our competitive subsidiary, FirstEnergy Solutions, contracts for renewable energy from the 35-MW Casselman Wind Power Project located in Somerset County, Pa. PROVIDE MORE THAN 1 MILLION MEGAWATT-HOURS PER YEAR OF WIND GENERATION 4 LOWERING RISK IN OUR COMPETITIVE BUSINESS We continue to execute a conservative sales and generation strategy that offers less risk to the company. To achieve this goal, our FirstEnergy Solutions subsidiary continued to restructure its sales portfolio to reduce our exposure to weather-sensitive demand and ensure we don’t sell more power than we produce. A larger portion of our generation is kept in reserve to minimize our financial risk when energy prices increase and ensure power is available to sell when market conditions are favorable. We’re maintaining our support of governmental aggregation and other higher-margin sales while pursuing wholesale opportunities that align with our generation portfolio. We also remain committed to economically dispatching our fleet and operating our units with greater flexibility. FirstEnergy Nuclear Operating Company (FENOC) reached a significant milestone in 2015 when the Nuclear Regulatory Commission approved a 20-year license extension for the Davis-Besse Nuclear Power Station, allowing the unit to operate until 2037. In addition, improved reliability and outage execution enabled FENOC to produce approximately 1 million megawatt-hours over its original plan for the year, further improving commodity margin. PJM Interconnection’s new Capacity Performance product had a positive impact in more properly valuing essential and highly reliable baseload generating resources. Capacity auctions held in August and September of 2015 are expected to improve revenues by $1.1 billion from June 2016 through May 2019. However, markets continue to fall short of reflecting the true cost of operating our baseload power plants. MEETING OUR ENVIRONMENTAL COMMITMENTS In 2015, we continued to make progress to improve the environmental performance of our operations. Our proposed Ohio ESP includes a goal to reduce carbon dioxide emissions by at least 90 percent below 2005 levels by 2045 – exceeding President Obama’s goal of achieving economywide reductions of 80 percent or more by 2050. The Clean Power Plan called for individual states to develop plans for meeting the U.S. Environmental Protection Agency’s state-specific emission reduction goals. However, on Feb. 9, 2016, the U.S. Supreme Court granted a petition from 27 states and other stakeholders to halt enforcement of the Clean Power Plan’s final rule until after all legal challenges are resolved. FirstEnergy submitted extensive comments before the rule was finalized, and we’re continuing to engage federal and state policymakers on issues related to our ongoing efforts to ensure the availability of clean, reliable and affordable energy resources for customers. 5 We’ve also made the significant investments needed to comply with the EPA’s Mercury and Air Toxics Standards and other requirements, and we will continue to invest in our fossil fleet to help maintain reliable and affordable supplies of power for customers as we make the transition to a cleaner energy future. $4.2 BILLION IN PLANNED TRANSMISSION INVESTMENTS FROM 2014 THROUGH 2017 SETTING A COURSE FOR THE FUTURE I’m proud of what our employees have accomplished, and I’m confident they will help us succeed in the future by continuing to provide customers with the level of service they expect and deserve. We’re pursuing the right strategy for your company. By achieving solid performance across our three business sectors – distribution, transmission and generation – and remaining focused on meeting our customers’ immediate and long-term energy needs, we can deliver more sustainable growth and greater financial stability for FirstEnergy in the years ahead. Thank you for your support as we work to achieve continued success for your company. Charles E. Jones President and Chief Executive Officer March 16, 2016 6 6 6 PA PA OH NJ MD WV VA C O R P O R A T E P R O F I L E Headquartered in Akron, Ohio, FirstEnergy is a leading regional energy provider dedicated to safety, operational excellence and responsive customer service. Our subsidiaries are involved in the generation, transmission and distribution of electricity. Our 10 utility operating companies form one of the nation’s largest investor-owned electric systems based on 6 million customers served within a nearly 65,000-square-mile area of Ohio, Pennsylvania, New Jersey, West Virginia, Maryland and New York. Our generation subsidiaries control nearly 17,000 megawatts (MW) of capacity from a diversified mix of scrubbed coal, nuclear, natural gas, oil, hydroelectric pumped-storage and contracted wind and solar resources – including 1,900 MW of renewable energy. The company’s transmission subsidiaries operate approximately 24,200 miles of transmission lines connecting the Midwest and Mid-Atlantic regions. FirstEnergy Solutions, our competitive subsidiary, is a retail energy supplier serving approximately 1.6 million residential, commercial and industrial customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois. Ohio Ohio Edison The Illuminating Company Toledo Edison Pennsylvania Met-Ed Penelec Penn Power West Penn Power West Virginia/Maryland Mon Power Potomac Edison New Jersey Jersey Central Power & Light Generating Stations Coal Gas/Oil Hydro Nuclear Wind Solar 7 F I R S T E N E R G Y B O A R D O F D I R E C T O R S D E A R S H A R E H O L D E R S : FirstEnergy’s management team and employees made significant progress in 2015. Your Board of Directors commends their efforts to achieve customer-focused growth in the company’s regulated utility operations, manage risk in its competitive business, and reduce expenses. Your Board provided an annual dividend rate of $1.44 per share in 2015. As FirstEnergy addresses future opportunities and challenges, we will continue to review the dividend on a quarterly basis. Your Board is committed to maintaining the appropriate practices and policies that help ensure good corporate governance. We also support your management team as it focuses on ensuring employee safety, providing outstanding service to customers, enhancing the company’s environmental performance, and delivering consistent and predictable financial results. I welcome Thomas N. Mitchell, who was elected to serve on the company’s Board in January 2016. Tom is a well-respected nuclear industry veteran with 38 years of experience in the field, including leadership positions at the World Association of Nuclear Operators, the Institute of Nuclear Power Operations, the Nuclear Energy Institute and the Electric Power Research Institute. Your Board remains dedicated to representing your interests and enhancing the value of your investment in FirstEnergy. Thank you for your ongoing support. Sincerely, George M. Smart, Chairman of the Board Paul T. Addison Retired, formerly Managing Director in the Utilities Department of Salomon Smith Barney (CitiGroup). 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. Robert B. Heisler, Jr. Retired, formerly Dean of the College of Business Administration and Graduate School of Management of Kent State University. Retired Chairman of the Board of KeyBank N.A. Julia L. Johnson President of NetCommunications, LLC (regulatory and public affairs firm). Charles E. Jones President and Chief Executive Officer of FirstEnergy Corp. Ted J. Kleisner Retired, formerly Chairman of the Board and Chief Executive Officer of Hershey Entertainment & Resorts Company. Donald T. Misheff Retired, formerly Managing Partner of the Northeast Ohio offices of Ernst & Young LLP. Thomas N. Mitchell Retired, formerly President, CEO and Director of Ontario Power Generation Inc. Ernest J. Novak, Jr. Retired, formerly Managing Partner of the Cleveland office of Ernst & Young LLP. Christopher D. Pappas President and Chief Executive Officer of Trinseo S.A., formerly Styron LLC (plastics, latex and rubber producer). 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 CEO of Dream Catcher Educational Consulting (higher education coaching and professional development). Retired President of Cuyahoga Community College. F I R S T E N E R G Y C O R P. E X E C U T I V E O F F I C E R S * Charles E. Jones President and Chief Executive Officer Michael J. Dowling Senior Vice President, External Affairs Leila L. Vespoli Executive Vice President, Markets and Chief Legal Officer Bennett L. Gaines Senior Vice President, Corporate Services and Chief Information Officer James H. Lash Executive Vice President and President, FE Generation James F. Pearson Executive Vice President and Chief Financial Officer Gary D. Benz Senior Vice President, Strategy Lynn M. Cavalier Chief Human Resource Officer Dennis M. Chack Senior Vice President, Marketing and Branding Charles D. Lasky Senior Vice President, Human Resources Donald R. Schneider President, FirstEnergy Solutions Steven E. Strah Senior Vice President and President, FirstEnergy Utilities K. Jon Taylor Vice President, Controller and Chief Accounting Officer * More detailed information on the principal occupation or employment of each of our executive officers and the principal business of any organization by which FirstEnergy Executive Officers are employed may be found on page 145 of this report. 8 2015 ANNUAL.REPORT CONTENTS i............... Glossary.of.Terms 1.............. Selected.Financial.Data 3............. Management’s.Discussion.and.Analysis 61............ Management.Reports 62........... Report.of.Independent.Registered.Public.Accounting.Firm 63........... Consolidated.Statements.of.Income 64........... Consolidated.Statements.of.Comprehensive.Income 65........... Consolidated.Balance.Sheets 66........... Consolidated.Statements.of.Common.Stockholders’.Equity 67........... Consolidated.Statements.of.Cash.Flows 68........... Notes.to.the.Consolidated.Financial.Statements 145.......... Executive.Officers.as.of.February.16,.2016 GLOSSARY  OF  TERMS   The  following  abbreviations  and  acronyms  are  used  in  this  report  to  identify  FirstEnergy  Corp.  and  its  current  and  former  subsidiaries:   The  following  abbreviations and  acronyms are  used  to  identify frequently used  terms in  this report: AE   GLOSSARY OF TERMS Allegheny  Energy,  Inc.,  a  Maryland  utility  holding  company  that  merged  with  a  subsidiary  of  FirstEnergy  on   Unless the   context requires otherwise, references to   “we,” “us,” and   “our” refer to   FirstEnergy Corp. Additionally, the   following   abbreviations and  acronyms are  used  in  this report to  identify FirstEnergy Corp. and  its current and  former subsidiaries: Allegheny  Energy  Service  Corporation,  which  provided  legal,  financial  and  other  corporate  support  services  to  the          former  AE  subsidiaries   February  25,  2011,  which  subsequently  merged  with  and  into  FE  on  January  1,  2014   AESC   AE  Supply   AE AGC   ATSI   AESC Allegheny  Energy  Supply  Company,  LLC,  an  unregulated  generation  subsidiary   Allegheny Energy, Inc., a  Maryland  utility holding  company that merged  with  a  subsidiary of FirstEnergy on   Allegheny  Generating  Company,  a  generation  subsidiary  of  AE  Supply  and  equity  method  investee  of  MP   February 25, 2011, which  subsequently merged  with  and  into  FE on  January 1, 2014 American  Transmission  Systems,  Incorporated,  formerly  a  direct  subsidiary  of  FE  that  became  a  subsidiary  of  FET   Allegheny Energy Service  Corporation, which  provided  legal, financial and  other corporate  support services to  the   in  April  2012,  which  owns  and  operates  transmission  facilities   former AE subsidiaries Buchanan  Energy   AE Supply Buchanan  Energy  Company  of  Virginia,  LLC,  a  subsidiary  of  AE  Supply   Allegheny Energy Supply Company, LLC, an  unregulated  generation  subsidiary Buchanan  Generation   AGC Buchanan  Generation,  LLC,  a  joint  venture  between  AE  Supply  and  CNX  Gas  Corporation   Allegheny Generating  Company, a  generation  subsidiary of AE Supply and  equity method  investee  of MP CEI   ATSI CES   Buchanan  Energy American  Transmission  Systems, Incorporated, formerly a  direct subsidiary of FE that became  a  subsidiary of FET The  Cleveland  Electric  Illuminating  Company,  an  Ohio  electric  utility  operating  subsidiary   in  April 2012, which  owns  and  operates  transmission  facilities Competitive  Energy  Services,  a  reportable  operating  segment  of  FirstEnergy   Buchanan  Energy Company  of Virginia, LLC, a subsidiary of AE Supply FE   Buchanan  Generation FirstEnergy  Corp.,  a  public  utility  holding  company   Buchanan  Generation, LLC, a  joint venture  between  AE Supply and  CNX Gas Corporation FELHC   CEI FENOC   CES FES   FE FESC   FELHC FET   FENOC FES FEV   FESC FG   FET FGMUC   FEV FG FirstEnergy   FGMUC Global  Holding   FirstEnergy Global  Rail   Global Holding GPU   Global  Rail Green  Valley   JCP&L   GPU MAIT   Green  Valley ME   JCP&L MP   MAIT NG   ME OE   MP FELHC,  Inc.   The  Cleveland  Electric Illuminating  Company, an  Ohio  electric utility operating  subsidiary FirstEnergy  Nuclear  Operating  Company,  which  operates  nuclear  generating  facilities   Competitive  Energy  Services, a  reportable  operating  segment of FirstEnergy FirstEnergy  Solutions  Corp.,  which  provides  energy-­related  products  and  services   FirstEnergy Corp., a  public utility holding  company FirstEnergy  Service  Company,  which  provides  legal,  financial  and  other  corporate  support  services   FELHC,  Inc. FirstEnergy  Transmission,  LLC,  formerly  known  as  Allegheny  Energy  Transmission,  LLC,  which  is  the  parent  of   FirstEnergy Nuclear Operating  Company, which  operates nuclear generating  facilities ATSI  and  TrAIL  and  has  a  joint  venture  in  PATH   FirstEnergy Solutions Corp., which  provides energy-­related  products  and  services FirstEnergy  Ventures  Corp.,  which  invests  in  certain  unregulated  enterprises  and  business  ventures   FirstEnergy Service  Company, which  provides legal, financial and  other corporate  support services California  Department of Water Resources Comprehensive  Environmental Response, Compensation, and  Liability Act of 1980 FirstEnergy  Generation,  LLC,  a  wholly-­owned  subsidiary  of  FES,  which  owns  and  operates  non-­nuclear  generating   FirstEnergy Transmission, LLC, formerly known  as Allegheny Energy Transmission, LLC, which  is  the  parent of  facilities   ATSI and  TrAIL and  has a  joint venture  in  PATH FirstEnergy Ventures Corp., which  invests in  certain  unregulated  enterprises and  business ventures FirstEnergy  Generation  Mansfield  Unit  1  Corp.,  a  wholly-­owned  subsidiary  of  FG,  which  owns  various  leasehold        interests  in  Bruce  Mansfield  Unit  1   FirstEnergy Generation, LLC, a  wholly-­owned  subsidiary of FES, which  owns and  operates non-­nuclear generating FirstEnergy  Corp.,  together  with  its  consolidated  subsidiaries   facilities Global  Mining  Holding  Company,  LLC,  a  joint  venture  between  FEV,  WMB  Marketing  Ventures,  LLC  and  Pinesdale   FirstEnergy Generation  Mansfield  Unit 1  Corp., a  wholly-­owned  subsidiary of FG, which  owns various leasehold   interests  in  Bruce  Mansfield  Unit 1 LLC   FirstEnergy  Corp.,  together with  its consolidated  subsidiaries Global  Rail  Group,  LLC,  a  subsidiary  of  Global  Holding  that  owns  coal  transportation  operations  near  Roundup,          Montana   Global Mining  Holding  Company, LLC, a  joint venture  between  FEV, WMB Marketing  Ventures, LLC and  Pinesdale   LLC GPU,  Inc.,  former  parent  of  JCP&L,  ME  and  PN,  that  merged  with  FE  on  November  7,  2001   Global Rail Group, LLC, a  subsidiary of Global Holding  that owns coal transportation  operations near Roundup, Green  Valley  Hydro,  LLC,  which  owned  hydro  generating  stations   Montana Jersey  Central  Power  &  Light  Company,  a  New  Jersey  electric  utility  operating  subsidiary   GPU,  Inc.,  former  parent  of  JCP&L,  ME  and  PN,  that  merged  with  FE  on  November  7,  2001 Mid-­Atlantic  Interstate  Transmission,  LLC,  a  subsidiary  of  FET,  formed  to  own  and  operate  transmission  facilities   Green  Valley Hydro, LLC, which  owned  hydro  generating  stations Metropolitan  Edison  Company,  a  Pennsylvania  electric  utility  operating  subsidiary   Jersey Central Power & Light Company, a  New Jersey electric utility operating  subsidiary Monongahela  Power  Company,  a  West  Virginia  electric  utility  operating  subsidiary   Mid-­Atlantic  Interstate Transmission,  LLC,  a  subsidiary  of  FET,  formed  to  own  and  operate  transmission  facilities FirstEnergy  Nuclear  Generation,  LLC,  a  subsidiary  of  FES,  which  owns  nuclear  generating  facilities   Metropolitan  Edison  Company, a  Pennsylvania  electric  utility  operating  subsidiary Monongahela  Power Company, a  West Virginia  electric  utility  operating  subsidiary Ohio  Edison  Company,  an  Ohio  electric  utility  operating  subsidiary   NG Ohio  Companies   FirstEnergy Nuclear Generation, LLC, a  subsidiary of FES, which  owns nuclear generating  facilities CEI,  OE  and  TE   OE PATH   Ohio  Edison  Company, an  Ohio  electric utility operating  subsidiary Potomac-­Appalachian  Transmission  Highline,  LLC,  a  joint  venture  between  FE  and  a  subsidiary  of  AEP   Ohio  Companies PATH-­Allegheny   CEI, OE and TE PATH  Allegheny  Transmission  Company,  LLC   PATH PATH-­WV   PATH-­Allegheny PE   Potomac-­Appalachian  Transmission  Highline, LLC, a  joint venture  between  FE and  a  subsidiary of AEP PATH  West  Virginia  Transmission  Company,  LLC   PATH Allegheny Transmission  Company, LLC The  Potomac  Edison  Company,  a  Maryland  and  West  Virginia  electric  utility  operating  subsidiary   AAA AEP AFS AFUDC ALJ AMT AOCI Apple® ARO ARR ASLB ASU BGS BNSF BRA CAA CBA CCR CDWR CERCLA CFL CFR CFTC CO2 CONE CPP CSAPR CSX CTA CWA DCPD DCR DOE DR DSIC DSP EDC EDCP EE&C EGS ELPC ENEC EPA EPRI ERO ESOP ESP ESTIP American  Arbitration  Association American  Electric Power Company, Inc. Available-­for-­sale Allowance  for Funds Used  During  Construction Administrative  Law Judge Alternative  Minimum Tax Accumulated  Other Comprehensive  Income Apple®, iPad® and  iPhone® are  registered  trademarks of Apple  Inc. Asset  Retirement  Obligation Auction  Revenue  Right Atomic Safety and  Licensing  Board Accounting  Standards Update Basic Generation  Service BNSF  Railway Company PJM RPM Base  Residual Auction Clean  Air Act Collective  Bargaining  Agreement Coal Combustion  Residuals Compact Fluorescent Light Code  of Federal Regulations Commodity Futures  Trading  Commission Carbon  Dioxide Cost-­of-­New-­Entry EPA's Clean  Power Plan Cross-­State Air  Pollution  Rule CSX Transportation, Inc. Consolidated  Tax  Adjustment Clean  Water Act Delivery  Capital Recovery United  States  Department of Energy Demand  Response Distribution  System Improvement Charge Default Service  Plan Electric  Distribution  Company Executive  Deferred  Compensation  Plan Energy Efficiency and  Conservation Electric Generation  Supplier Environmental Law & Policy Center Deferred  Compensation  Plan  for Outside  Directors EMAAC Eastern  Mid-­Atlantic Area  Council  of  PJM EmPOWER Maryland EmPOWER Maryland  Energy Efficiency Act Expanded  Net Energy Cost United  States Environmental Protection  Agency Electric  Power  Research  Institute Electric  Reliability  Organization Employee  Stock Ownership  Plan Electric  Security  Plan Facebook® FASB Executive  Short-­Term Incentive  Program Facebook is a  registered  trademark  of Facebook, Inc. Financial Accounting  Standards Board Trans-­Allegheny  Interstate  Line  Company,  a  subsidiary  of  FET,  which  owns  and  operates  transmission  facilities   The  Toledo  Edison  Company, an  Ohio  electric utility operating  subsidiary OE,  CEI,  TE,  Penn,  JCP&L,  ME,  PN,  MP,  PE  and  WP   Trans-­Allegheny Interstate  Line  Company, a  subsidiary of FET, which  owns and  operates transmission  facilities West  Penn  Power  Company,  a  Pennsylvania  electric  utility  operating  subsidiary   OE,  CEI,  TE,  Penn,  JCP&L,  ME,  PN,  MP,  PE  and  WP West Penn  Power Company, a  Pennsylvania  electric utility operating  subsidiary i   i   ii PNBV  Capital  Trust,  a  special  purpose  entity  created  by  OE  in  1996   Pennsylvania  Electric Company, a  Pennsylvania  electric utility operating  subsidiary Shippingport  Capital  Trust,  a  special  purpose  entity  created  by  CEI  and  TE  in  1997   PNBV Capital Trust, a  special purpose  entity created  by OE in  1996 PNBV   PN Shippingport   PNBV Signal  Peak   Shippingport Signal Peak TE   TrAIL   TE Utilities   TrAIL WP   Utilities WP Pennsylvania  Power Company, a  Pennsylvania  electric  utility  operating  subsidiary  of  OE   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  Electric  Company,  a  Pennsylvania  electric  utility  operating  subsidiary   Signal  Peak  Energy,  LLC,  an  indirect  subsidiary  of  Global  Holding  that  owns  mining  operations  near  Roundup,   Shippingport Capital Trust, a  special purpose  entity  created  by  CEI and  TE in  1997 Signal Peak Energy, LLC, an  indirect subsidiary of Global Holding  that owns mining  operations near Roundup, The  Toledo  Edison  Company,  an  Ohio  electric  utility  operating  subsidiary   Montana Pennsylvania  Companies   ME,  PN,  Penn  and  WP   Pennsylvania  Companies ME, PN, Penn and WP PATH West Virginia  Transmission  Company, LLC Penn   PE Penn PN   Montana   PATH-­WV GLOSSARY  OF  TERMS   The  following  abbreviations  and  acronyms  are  used  in  this  report  to  identify  FirstEnergy  Corp.  and  its  current  and  former  subsidiaries:   Allegheny  Energy,  Inc.,  a  Maryland  utility  holding  company  that  merged  with  a  subsidiary  of  FirstEnergy  on   February  25,  2011,  which  subsequently  merged  with  and  into  FE  on  January  1,  2014   Allegheny  Energy  Service  Corporation,  which  provided  legal,  financial  and  other  corporate  support  services  to  the              former  AE  subsidiaries   AE  Supply   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   Buchanan  Energy   Buchanan  Energy  Company  of  Virginia,  LLC,  a  subsidiary  of  AE  Supply   Buchanan  Generation   Buchanan  Generation,  LLC,  a  joint  venture  between  AE  Supply  and  CNX  Gas  Corporation   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   FELHC,  Inc.   FirstEnergy  Nuclear  Operating  Company,  which  operates  nuclear  generating  facilities   FirstEnergy  Solutions  Corp.,  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  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   FirstEnergy  Generation  Mansfield  Unit  1  Corp.,  a  wholly-­owned  subsidiary  of  FG,  which  owns  various  leasehold          interests  in  Bruce  Mansfield  Unit  1   FirstEnergy  Corp.,  together  with  its  consolidated  subsidiaries   Global  Mining  Holding  Company,  LLC,  a  joint  venture  between  FEV,  WMB  Marketing  Ventures,  LLC  and  Pinesdale        facilities   LLC          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  hydro  generating  stations   Jersey  Central  Power  &  Light  Company,  a  New  Jersey  electric  utility  operating  subsidiary   Mid-­Atlantic  Interstate  Transmission,  LLC,  a  subsidiary  of  FET,  formed  to  own  and  operate  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   Global  Rail   Global  Rail  Group,  LLC,  a  subsidiary  of  Global  Holding  that  owns  coal  transportation  operations  near  Roundup,     Ohio  Companies   CEI,  OE  and  TE   PATH   Potomac-­Appalachian  Transmission  Highline,  LLC,  a  joint  venture  between  FE  and  a  subsidiary  of  AEP   PATH-­Allegheny   PATH  Allegheny  Transmission  Company,  LLC   PATH-­WV   PATH  West  Virginia  Transmission  Company,  LLC   The  Potomac  Edison  Company,  a  Maryland  and  West  Virginia  electric  utility  operating  subsidiary   Pennsylvania  Power  Company,  a  Pennsylvania  electric  utility  operating  subsidiary  of  OE   Pennsylvania  Companies   ME,  PN,  Penn  and  WP   Pennsylvania  Electric  Company,  a  Pennsylvania  electric  utility  operating  subsidiary   PNBV  Capital  Trust,  a  special  purpose  entity  created  by  OE  in  1996   Shippingport  Capital  Trust,  a  special  purpose  entity  created  by  CEI  and  TE  in  1997   Signal  Peak  Energy,  LLC,  an  indirect  subsidiary  of  Global  Holding  that  owns  mining  operations  near  Roundup,   Montana   The  Toledo  Edison  Company,  an  Ohio  electric  utility  operating  subsidiary   Trans-­Allegheny  Interstate  Line  Company,  a  subsidiary  of  FET,  which  owns  and  operates  transmission  facilities   OE,  CEI,  TE,  Penn,  JCP&L,  ME,  PN,  MP,  PE  and  WP   West  Penn  Power  Company,  a  Pennsylvania  electric  utility  operating  subsidiary   i   AE   AESC   AGC   ATSI   CEI   CES   FE   FELHC   FENOC   FES   FESC   FET   FEV   FG   FGMUC   FirstEnergy   Global  Holding   GPU   Green  Valley   JCP&L   MAIT   ME   MP   NG   OE   PE   Penn   PN   PNBV   TE   TrAIL   Utilities   WP   Shippingport   Signal  Peak   The  following  abbreviations  and  acronyms  are  used  to  identify  frequently  used  terms  in  this  report:   AAA   AEP   AFS   AFUDC   ALJ   AMT   AOCI   Apple®   ARO   ARR   ASLB   ASU   BGS   BNSF   BRA   CAA   CBA   CCR   CDWR   CERCLA   CFL   CFR   CFTC   CO2   CONE   CPP   CSAPR   CSX   CTA   CWA   DCPD   DCR   DOE   DR   DSIC   DSP   EDC   EDCP   EE&C   EGS   ELPC   American  Arbitration  Association   American  Electric  Power  Company,  Inc.   Available-­for-­sale   Allowance  for  Funds  Used  During  Construction   Administrative  Law  Judge   Alternative  Minimum  Tax   Accumulated  Other  Comprehensive  Income   Apple®,  iPad®  and  iPhone®  are  registered  trademarks  of  Apple  Inc.   Asset  Retirement  Obligation   Auction  Revenue  Right   Atomic  Safety  and  Licensing  Board   Accounting  Standards  Update   Basic  Generation  Service   BNSF  Railway  Company   PJM  RPM  Base  Residual  Auction   Clean  Air  Act   Collective  Bargaining  Agreement   Coal  Combustion  Residuals   California  Department  of  Water  Resources   Comprehensive  Environmental  Response,  Compensation,  and  Liability  Act  of  1980   Compact  Fluorescent  Light   Code  of  Federal  Regulations   Commodity  Futures  Trading  Commission   Carbon  Dioxide   Cost-­of-­New-­Entry   EPA's  Clean  Power  Plan   Cross-­State  Air  Pollution  Rule   CSX  Transportation,  Inc.   Consolidated  Tax  Adjustment   Clean  Water  Act   Deferred  Compensation  Plan  for  Outside  Directors   Delivery  Capital  Recovery   United  States  Department  of  Energy   Demand  Response   Distribution  System  Improvement  Charge   Default  Service  Plan   Electric  Distribution  Company   Executive  Deferred  Compensation  Plan   Energy  Efficiency  and  Conservation   Electric  Generation  Supplier   Environmental  Law  &  Policy  Center   EMAAC   Eastern  Mid-­Atlantic  Area  Council  of  PJM   EmPOWER  Maryland   EmPOWER  Maryland  Energy  Efficiency  Act   ENEC   EPA   EPRI   ERO   ESOP   ESP   ESTIP   Facebook®   FASB   Expanded  Net  Energy  Cost   United  States  Environmental  Protection  Agency   Electric  Power  Research  Institute   Electric  Reliability  Organization   Employee  Stock  Ownership  Plan   Electric  Security  Plan   Executive  Short-­Term  Incentive  Program   Facebook  is  a  registered  trademark  of  Facebook,  Inc.   Financial  Accounting  Standards  Board   ii       FERC   Fitch   FMB   FPA   FTR   GAAP   GHG   GWH   HCl   IBEW   ICE   ICP  2007   ICP  2015   IRS   ISO   kV   KWH   KPI   LBR   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   Office  and  Professional  Employees  International  Union   Greenhouse  Gases   Gigawatt-­hour   HydroChloric  Acid   International  Brotherhood  of  Electrical  Workers   IntercontinentalExchange,  Inc.   FirstEnergy  Corp.  2007  Incentive  Plan   FirstEnergy  Corp.  2015  Incentive  Compensation  Plan   Internal  Revenue  Service   Independent  System  Operator   Kilovolt   Kilowatt-­hour   Key  Performance  Indicator   Little  Blue  Run   LCAPP   Long-­Term  Capacity  Agreement  Pilot  Program   LED   LMP   LOC   LSE   LTIIPs   MAAC   MATS   MDPSC   MISO   MLP   mmBTU   Moody’s   MVP   MW   MWD   MWH   NAAQS   NDT   NEIL   NERC   NGO   Ninth  Circuit   NJBPU   NMB   NOL   NOV   NOx   NPDES   NPNS   NRC   NRG   NSR   NUG   NYISO   Light  Emitting  Diode   Locational  Marginal  Price   Letter  of  Credit   Load  Serving  Entity   Long-­Term  Infrastructure  Improvement  Plans   Mid-­Atlantic  Area  Council  of  PJM   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.   Multi-­Value  Project   Megawatt   Megawatt-­day   Megawatt-­hour   National  Ambient  Air  Quality  Standards   Nuclear  Decommissioning  Trust   Nuclear  Electric  Insurance  Limited   North  American  Electric  Reliability  Corporation   Non-­Governmental  Organization   United  States  Court  of  Appeals  for  the  Ninth  Circuit   New  Jersey  Board  of  Public  Utilities   Non-­Market  Based   Net  Operating  Loss   Notice  of  Violation   Nitrogen  Oxide   National  Pollutant  Discharge  Elimination  System   Normal  Purchases  and  Normal  Sales   Nuclear  Regulatory  Commission   NRG  Energy,  Inc.   New  Source  Review   Non-­Utility  Generation   New  York  Independent  System  Operator   iii   PJM  Region   PJM  Tariff   The  aggregate  of  the  zones  within  PJM   PJM  Open  Access  Transmission  Tariff   NYPSC   OCA   OCC   OEPA   OPEB   OPEIU   OTC   OTTI   OVEC   PA  DEP   PCB   PCRB   PJM   PM   POLR   POR   PPA   PPB   PPUC   PSA   PSD   PTC   PUCO   PURPA   R&D   RCRA   REC   REIT   RFC   RFP   RGGI   RMR   ROE   RPM   RRS   RSS   RTEP   RTO   S&P   SAIDI   SAIFI   SB221   SB310   SBC   SEC   SERTP   SF6   SIP   SO2   SOS   New  York  State  Public  Service  Commission   Office  of  Consumer  Advocate   Ohio  Consumers'  Counsel   Ohio  Environmental  Protection  Agency   Other  Post-­Employment  Benefits   Over  The  Counter   Other-­Than-­Temporary  Impairments   Ohio  Valley  Electric  Corporation   Polychlorinated  Biphenyl   Pollution  Control  Revenue  Bond   PJM  Interconnection,  L.L.C.   Pennsylvania  Department  of  Environmental  Protection   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   Price-­to-­Compare   Public  Utilities  Commission  of  Ohio   Public  Utility  Regulatory  Policies  Act  of  1978   Research  and  Development   Resource  Conservation  and  Recovery  Act   Renewable  Energy  Credit   Real  Estate  Investment  Trust   ReliabilityFirst  Corporation   Request  for  Proposal   Regional  Greenhouse  Gas  Initiative   Reliability  Must-­Run   Return  on  Equity   Reliability  Pricing  Model   Retail  Rate  Stability   Rich  Site  Summary   Regional  Transmission  Expansion  Plan   Regional  Transmission  Organization   Standard  &  Poor’s  Ratings  Service   System  Average  Interruption  Duration  Index   System  Average  Interruption  Frequency  Index   Amended  Substitute  Senate  Bill  No.  221   Substitute  Senate  Bill  No.  310   Societal  Benefits  Charge   United  States  Securities  and  Exchange  Commission   Southeastern  Regional  Transmission  Planning   State  Implementation  Plan(s)  Under  the  Clean  Air  Act   Sulfur  Hexafluoride   Sulfur  Dioxide   Standard  Offer  Service   iv   Regulation  FD   Regulation  Fair  Disclosure  promulgated  by  the  SEC   Seventh  Circuit   United  States  Court  of  Appeals  for  the  Seventh  Circuit       LCAPP   Long-­Term  Capacity  Agreement  Pilot  Program   ICP  2007   ICP  2015   FERC   Fitch   FMB   FPA   FTR   GAAP   GHG   GWH   HCl   IBEW   ICE   IRS   ISO   kV   KWH   KPI   LBR   LED   LMP   LOC   LSE   LTIIPs   MAAC   MATS   MDPSC   MISO   MLP   mmBTU   Moody’s   MVP   MW   MWD   MWH   NAAQS   NDT   NEIL   NERC   NGO   NMB   NOL   NOV   NOx   NPDES   NPNS   NRC   NRG   NSR   NUG   NYISO   Ninth  Circuit   NJBPU   Accounting  Principles  Generally  Accepted  in  the  United  States  of  America   Federal  Energy  Regulatory  Commission   Fitch  Ratings   First  Mortgage  Bond   Federal  Power  Act   Financial  Transmission  Right   Greenhouse  Gases   Gigawatt-­hour   HydroChloric  Acid   International  Brotherhood  of  Electrical  Workers   IntercontinentalExchange,  Inc.   FirstEnergy  Corp.  2007  Incentive  Plan   FirstEnergy  Corp.  2015  Incentive  Compensation  Plan   Internal  Revenue  Service   Independent  System  Operator   Kilovolt   Kilowatt-­hour   Key  Performance  Indicator   Little  Blue  Run   Light  Emitting  Diode   Locational  Marginal  Price   Letter  of  Credit   Load  Serving  Entity   Long-­Term  Infrastructure  Improvement  Plans   Mid-­Atlantic  Area  Council  of  PJM   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.   Multi-­Value  Project   Megawatt   Megawatt-­day   Megawatt-­hour   National  Ambient  Air  Quality  Standards   Nuclear  Decommissioning  Trust   Nuclear  Electric  Insurance  Limited   North  American  Electric  Reliability  Corporation   Non-­Governmental  Organization   United  States  Court  of  Appeals  for  the  Ninth  Circuit   New  Jersey  Board  of  Public  Utilities   Non-­Market  Based   Net  Operating  Loss   Notice  of  Violation   Nitrogen  Oxide   National  Pollutant  Discharge  Elimination  System   Normal  Purchases  and  Normal  Sales   Nuclear  Regulatory  Commission   NRG  Energy,  Inc.   New  Source  Review   Non-­Utility  Generation   New  York  Independent  System  Operator   iii   NYPSC   OCA   OCC   OEPA   OPEB   OPEIU   OTC   OTTI   OVEC   PA  DEP   PCB   PCRB   PJM   New  York  State  Public  Service  Commission   Office  of  Consumer  Advocate   Ohio  Consumers'  Counsel   Ohio  Environmental  Protection  Agency   Other  Post-­Employment  Benefits   Office  and  Professional  Employees  International  Union   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   PTC   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   Price-­to-­Compare   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   RMR   ROE   RPM   RRS   RSS   RTEP   RTO   S&P   SAIDI   SAIFI   SB221   SB310   SBC   SEC   SERTP   Real  Estate  Investment  Trust   ReliabilityFirst  Corporation   Request  for  Proposal   Regional  Greenhouse  Gas  Initiative   Reliability  Must-­Run   Return  on  Equity   Reliability  Pricing  Model   Retail  Rate  Stability   Rich  Site  Summary   Regional  Transmission  Expansion  Plan   Regional  Transmission  Organization   Standard  &  Poor’s  Ratings  Service   System  Average  Interruption  Duration  Index   System  Average  Interruption  Frequency  Index   Amended  Substitute  Senate  Bill  No.  221   Substitute  Senate  Bill  No.  310   Societal  Benefits  Charge   United  States  Securities  and  Exchange  Commission   Southeastern  Regional  Transmission  Planning   Seventh  Circuit   United  States  Court  of  Appeals  for  the  Seventh  Circuit   SF6   SIP   SO2   SOS   Sulfur  Hexafluoride   State  Implementation  Plan(s)  Under  the  Clean  Air  Act   Sulfur  Dioxide   Standard  Offer  Service   iv       SPE   SREC   SSO   TDS   TMI-­2   TO   TTS   Twitter®   Special  Purpose  Entity   Solar  Renewable  Energy  Credit   Standard  Service  Offer   Total  Dissolved  Solid   Three  Mile  Island  Unit  2   Transmission  Owner   Temporary  Transaction  Surcharge   Twitter  is  a  registered  trademark  of  Twitter,  Inc.   U.S.  Court  of  Appeals  for   the  D.C.  Circuit   United  States  Court  of  Appeals  for  the  District  of  Columbia  Circuit   UWUA   VIE   VRR   VSCC   WVDEP   WVPSC   Utility  Workers  Union  of  America   Variable  Interest  Entity   Variable  Resource  Requirement   Virginia  State  Corporation  Commission   West  Virginia  Department  of  Environmental  Protection   Public  Service  Commission  of  West  Virginia   v     Special Purpose  Entity Solar Renewable  Energy  Credit Standard  Service  Offer Total Dissolved  Solid Three  Mile  Island  Unit 2 Transmission  Owner Temporary Transaction  Surcharge Twitter  is a registered trademark of Twitter, Inc. U.S. Court of Appeals  for United  States  Court of Appeals  for the  District of Columbia  Circuit the  D.C.  Circuit Utility  Workers  Union  of America Variable  Interest  Entity Variable  Resource  Requirement Virginia  State  Corporation  Commission West Virginia  Department of Environmental Protection Public  Service  Commission  of  West  Virginia SPE SREC SSO TDS TMI-­2 TO TTS Twitter® UWUA VIE VRR VSCC WVDEP WVPSC SELECTED  FINANCIAL  DATA   For  the  Years  Ended  December  31,   2015   2014   2013   2012   2011   Revenues   Income  From  Continuing  Operations   Earnings  Available  to  FirstEnergy  Corp.   Earnings  per  Share  of  Common  Stock:   Basic  -­  Continuing  Operations   Basic  -­  Discontinued  Operations  (Note  19)   Basic  -­  Earnings  Available  to  FirstEnergy  Corp.   Diluted  -­  Continuing  Operations   Diluted  -­  Discontinued  Operations  (Note  19)   Diluted  -­  Earnings  Available  to  FirstEnergy  Corp.   Weighted  Average  Shares  Outstanding:   Basic   Diluted   Dividends  Declared  per  Share  of  Common  Stock   Total  Assets(1)   Capitalization  as  of  December  31:   Total  Equity   Long-­Term  Debt  and  Other  Long-­Term  Obligations   Total  Capitalization   $   $   $   $   $   $   $   $   $   $   $   (In  millions,  except  per  share  amounts)   15,255   $   755   $   770   $   15,049   $   213   $   299   $   14,892   $   375   $   392   $   15,026   $   578   $   578   $   1.37   $   —   1.37   $   1.37   $   —   1.37   $   0.51   $   0.20   0.71   $   0.51   $   0.20   0.71   $   0.90   $   0.04   0.94   $   0.90   $   0.04   0.94   $   1.81   $   0.04   1.85   $   1.80   $   0.04   1.84   $   422   424   1.44   $   52,187   $   420   421   1.44   $   51,648   $   418   419   1.65   $   50,058   $   418   419   2.20   $   50,175   $   12,422   $   19,192   31,614   $   12,422   $   19,176   31,598   $   12,695   $   15,831   28,526   $   13,093   $   15,179   28,272   $   16,087   856   885   2.19   0.03   2.22   2.18   0.03   2.21   399   401   2.20   47,410   13,299   15,716   29,015   (1)Reflects  the  application  of  ASU  2015-­17,  Balance  Sheet  Classification  of  Deferred  Taxes,  which  requires  all  accumulated  deferred  income  taxes  to be  classified  as  non-­current.  The  retrospective  change  decreased  Total  Assets  as  of  December  31  as  follows:  2014  -­  $518  million,  2013  -­$366  million, 2012  -­  $319  million  as  these  amounts  were  reclassified  from  current  assets  to  non-­current  liabilities. PRICE  RANGE  OF  COMMON  STOCK   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.   First  Quarter   Second  Quarter   Third  Quarter   Fourth  Quarter   Yearly   $   $   $   $   $   2015   2014   High   Low   High   Low   41.68   $   37.05   $   35.09   $   33.00   $   41.68   $   33.82   $   32.46   $   30.31   $   28.89   $   28.89   $   34.28   $   35.59   $   34.95   $   40.84   $   40.84   $   30.10   31.17   29.98   33.04   29.98   Closing  prices  are  from  http://finance.yahoo.com.   v 1 SHAREHOLDER  RETURN   MANAGEMENT’S DISCUSSION  AND  ANALYSIS OF REGISTRANT AND  SUBSIDIARIES The  following  graph  shows  the  total  cumulative  return  from  a  $100  investment  on  December  31,  2010  in  FirstEnergy’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  90,633  and  90,346  holders  of  423,560,397  and  423,650,645  shares  of  FirstEnergy’s  common  stock  as  of  December  31,   2015  and  January  31,  2016,  respectively.  Information  regarding  retained  earnings  available  for  payment  of  cash  dividends  is  given  in   Note  11,  Capitalization  of  the  Combined  Notes  to  Consolidated  Financial  Statements.   CHANGES  IN  AND  DISAGREEMENTS  WITH  ACCOUNTANTS  ON  ACCOUNTING  AND  FINANCIAL  DISCLOSURE   None. 2 3 Forward-­Looking   Statements: This report includes forward-­looking   statements based   on   information   currently available   to   management. Such  statements are  subject to  certain  risks and  uncertainties. 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  speed  and  nature  of increased  competition  in  the  electric utility industry, in  general, and  the  retail sales market in   particular. The  ability to  experience  growth  in  the  Regulated  Distribution  and  Regulated  Transmission  segments and  to  successfully implement our sales strategy for the  CES segment. The  accomplishment of our regulatory and  operational goals in  connection  with  our transmission  investment plan, including   but not limited  to, the  proposed  transmission  asset transfer to  MAIT, and  the  effectiveness of our strategy to  reflect a  more •   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 regulated  business profile. opportunities. The  impact of the  regulatory process on  the  pending  matters  at the federal level and in the  various  states  in which we do business including, but not limited  to, matters related  to  rates and  the  ESP IV in  Ohio. 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, including  FERC Opinion  No. 531’s revised  ROE methodology for FERC-­jurisdictional   wholesale   generation   and   transmission   utility service;; 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. Economic or weather conditions affecting  future  sales and  margins such  as a  polar vortex or other significant weather events, and  all associated  regulatory events or actions. •   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  and asset valuations. •   The  continued  ability  of  our  regulated  utilities  to  recover  their  costs. •   Costs being  higher than  anticipated  and  the  success of our policies to  control costs and  to  mitigate  low energy, capacity and   market prices. •   Other legislative  and  regulatory changes, and  revised  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. •   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). The  uncertainties associated  with  the  deactivation  of certain  older regulated  and  competitive  fossil units, including  the   impact  on  vendor  commitments  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. 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 or as a  result of the  incident at Japan's Fukushima  Daiichi Nuclear Plant). Issues  arising from the indications  of cracking in the shield building at  Davis-­Besse. The  risks and  uncertainties associated  with  litigation, arbitration, mediation  and  like  proceedings, including, but not limited   to, any  such  proceedings  related to  vendor commitments. The  impact of labor disruptions by our unionized  workforce. •   Replacement power costs being  higher than  anticipated  or not fully hedged. The  ability to  comply with  applicable  state  and  federal reliability standards and  energy efficiency and  peak demand  reduction mandates. •   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. •   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 through, among  other actions, our cash  flow improvement plan  and  other proposed  capital •   Our ability to  improve  electric commodity margins and  the  impact of, among  other factors, the  increased  cost of fuel and  fuel raising  initiatives. transportation on such margins. MANAGEMENT’S  DISCUSSION  AND  ANALYSIS  OF  REGISTRANT  AND  SUBSIDIARIES   Forward-­Looking   Statements:   This   report   includes   forward-­looking   statements   based   on   information   currently   available   to   management.  Such  statements  are  subject  to  certain  risks  and  uncertainties.  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  speed  and  nature  of  increased  competition  in  the  electric  utility  industry,  in  general,  and  the  retail  sales  market  in particular. The  ability  to  experience  growth  in  the  Regulated  Distribution  and  Regulated  Transmission  segments  and  to  successfully implement  our  sales  strategy  for  the  CES  segment. The  accomplishment  of  our  regulatory  and  operational  goals  in  connection  with  our  transmission  investment  plan,  including but  not  limited  to,  the  proposed  transmission  asset  transfer  to  MAIT,  and  the  effectiveness  of  our  strategy  to  reflect  a  more regulated  business  profile. 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  impact  of  the  regulatory  process  on  the  pending  matters  at  the  federal  level  and  in  the  various  states  in  which  we  do business  including,  but  not  limited  to,  matters  related  to  rates  and  the  ESP  IV  in  Ohio. 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,  including  FERC  Opinion  No.  531’s  revised  ROE  methodology  for  FERC-­jurisdictional wholesale   generation   and   transmission   utility   service;;   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. Economic  or  weather  conditions  affecting  future  sales  and  margins  such  as  a  polar  vortex  or  other  significant  weather events,  and  all  associated  regulatory  events  or  actions. 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  and  asset  valuations. The  continued  ability  of  our  regulated  utilities  to  recover  their  costs. Costs  being  higher  than  anticipated  and  the  success  of  our  policies  to  control  costs  and  to  mitigate  low  energy,  capacity  and market  prices. Other  legislative  and  regulatory  changes,  and  revised  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. 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). The  uncertainties  associated  with  the  deactivation  of  certain  older  regulated  and  competitive  fossil  units,  including  the impact  on  vendor  commitments  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. 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  or  as  a  result  of  the  incident  at Japan's  Fukushima  Daiichi  Nuclear  Plant). Issues  arising  from  the  indications  of  cracking  in  the  shield  building  at  Davis-­Besse. The  risks  and  uncertainties  associated  with  litigation,  arbitration,  mediation  and  like  proceedings,  including,  but  not  limited to,  any  such  proceedings  related  to  vendor  commitments. The  impact  of  labor  disruptions  by  our  unionized  workforce. Replacement  power  costs  being  higher  than  anticipated  or  not  fully  hedged. The  ability  to  comply  with  applicable  state  and  federal  reliability  standards  and  energy  efficiency  and  peak  demand  reduction mandates. 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. 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  through,  among  other  actions,  our  cash  flow  improvement  plan  and  other  proposed  capital raising  initiatives. 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. 3   •     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  material  accounting  policies.   •     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.   •     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,   and   increase   requirements   to   post   additional   collateral   to   support   outstanding   commodity  positions,  LOCs  and  other  financial  guarantees.   •     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  any  changes  in  tax  laws  or  regulations  or  adverse  tax  audit  results  or  rulings.   •     Issues  concerning  the  stability  of  domestic  and  foreign  financial  institutions  and  counterparties  with  which  we  do   business.     •     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.   •     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  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  of  our  Annual  Report  on  Form  10-­K  filed  with  the  SEC  on  February  16,  2016,  (b)  this  Item  7.  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   FE.  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.  The  registrants  expressly  disclaim  any  current  intention  to  update,  except  as  required  by  law,  any  forward-­looking   statements  contained  herein  as  a  result  of  new  information,  future  events  or  otherwise.   FIRSTENERGY  CORP.   MANAGEMENT’S  DISCUSSION  AND  ANALYSIS  OF   FINANCIAL  CONDITION  AND  RESULTS  OF  OPERATIONS   FIRSTENERGY’S  BUSINESS   FirstEnergy's  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  includes  regulated  electric  generation  facilities  located  primarily  in  West  Virginia,  Virginia  and  New   Jersey  that  MP  and  JCP&L,  respectively,  own  or  contractually  control.  The  segment's  results  reflect  the  commodity  costs  of  securing   electric  generation  and  the  deferral  and  amortization  of  certain  fuel  costs.  This  business  segment  currently  controls  3,790  MWs  of   generation  capacity.   The  service  areas  of,  and  customers  served  by,  FirstEnergy's  regulated  distribution  utilities  are  summarized  below  (in  thousands):   Company   OE   Penn   CEI   TE   JCP&L   ME   PN   WP   MP   PE   Area  Served   Central  and  Northeastern  Ohio   Western  Pennsylvania   Northeastern  Ohio   Northwestern  Ohio   Northern,  Western  and  East  Central  New  Jersey   Eastern  Pennsylvania   Western  Pennsylvania   Southwest,  South  Central  and  Northern  Pennsylvania   Northern,  Central  and  Southeastern  West  Virginia   Western  Maryland  and  Eastern  West  Virginia   (1)  As  of  December  31,  2015 Customers   Served  (1)   1,038   1,109   164   746   308   561   588   723   390   401   6,028   The  Regulated  Transmission  segment  transmits  electricity  through  transmission  facilities  owned  and  operated  by  ATSI,  TrAIL,  and   certain  of  FirstEnergy's  utilities  (JCP&L,  ME,  PN,  MP,  PE  and  WP).  This  segment  also  includes  the  regulatory  asset  associated  with   the  abandoned  PATH  project.  The  segment's  revenues  are  primarily  derived  from  rates  that  recover  costs  and  provide  a  return  on   transmission  capital  investment.  Except  for  the  recovery  of  the  PATH  abandoned  project  regulatory  asset,  these  revenues  are   primarily   from   transmission   services   provided   pursuant   to   its   PJM   Tariff   to   LSEs.   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,  Illinois,  Michigan,  New  Jersey  and   Maryland,  and  the  provision  of  partial  POLR  and  default  service  for  some  utilities  in  Ohio,  Pennsylvania  and  Maryland,  including  the   Utilities.  This  business  segment  currently  controls  13,162  MWs  of  capacity.  The  CES  segment’s  net  income  is  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.   The  CES  segment  expects  to  sell  its  annual  generation  output  of  approximately  75  to  80  million  MWHs,  with  up  to  an  additional  5   million  MWHs  available  from  PPAs  for  wind,  solar  and  its  entitlement  from  OVEC,  through  a  target  portfolio  mix  of  approximately  10  to   15  million  MWHs  in  Governmental  Aggregation  sales,  0  to  10  million  MWHs  of  POLR  sales,  0  to  20  million  MWHs  in  large  commercial   and  industrial  sales  (Direct),  10  to  20  million  MWHs  in  block  wholesale  sales,  including  Structured  Sales,  and  10  to  20  million  MWHs   of  spot  wholesale  sales.   Corporate  support  and  other  businesses  that  do  not  constitute  an  operating  segment,  interest  expense  on  stand-­alone  holding   company   debt   and   corporate   income   taxes   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,  2015,  Corporate/Other  had  $4.2  billion  of  stand-­alone  holding  company  long-­term  debt,  of  which  28%  was  subject  to   variable-­interest  rates,  and  $1.7  billion  was  borrowed  by  FE  under  its  revolving  credit  facility.     4   5                         •   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  material accounting  policies. •   •   •   •   •   •   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. 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, and increase requirements   to post additional collateral to support outstanding commodity positions, LOCs and  other financial guarantees. •   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 any changes in  tax laws or regulations or adverse  tax audit results or rulings. Issues  concerning the stability  of domestic  and foreign financial institutions  and counterparties  with which we do business. 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. •   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 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 of our Annual Report on  Form 10-­K filed  with  the  SEC on  February 16, 2016, (b) this Item 7. 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 FE. 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. The  registrants expressly disclaim any current intention  to  update, except as required  by law, any forward-­looking   statements contained  herein  as a  result of new information, future  events or otherwise. FIRSTENERGY  CORP.   MANAGEMENT’S  DISCUSSION  AND  ANALYSIS  OF   FINANCIAL  CONDITION  AND  RESULTS  OF  OPERATIONS   FIRSTENERGY’S  BUSINESS   FirstEnergy's  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  includes  regulated  electric  generation  facilities  located  primarily  in  West  Virginia,  Virginia  and  New   Jersey  that  MP  and  JCP&L,  respectively,  own  or  contractually  control.  The  segment's  results  reflect  the  commodity  costs  of  securing   electric  generation  and  the  deferral  and  amortization  of  certain  fuel  costs.  This  business  segment  currently  controls  3,790  MWs  of   generation  capacity.   The  service  areas  of,  and  customers  served  by,  FirstEnergy's  regulated  distribution  utilities  are  summarized  below  (in  thousands):   Company   OE   Penn   CEI   TE   JCP&L   ME   PN   WP   MP   PE   Area  Served   Customers   Served  (1)   Central  and  Northeastern  Ohio   Western  Pennsylvania   Northeastern  Ohio   Northwestern  Ohio   Northern,  Western  and  East  Central  New  Jersey   Eastern  Pennsylvania   Western  Pennsylvania   Southwest,  South  Central  and  Northern  Pennsylvania   Northern,  Central  and  Southeastern  West  Virginia   Western  Maryland  and  Eastern  West  Virginia   1,038   164   746   308   1,109   561   588   723   390   401   6,028   (1) As  of  December  31,  2015 The  Regulated  Transmission  segment  transmits  electricity  through  transmission  facilities  owned  and  operated  by  ATSI,  TrAIL,  and   certain  of  FirstEnergy's  utilities  (JCP&L,  ME,  PN,  MP,  PE  and  WP).  This  segment  also  includes  the  regulatory  asset  associated  with   the  abandoned  PATH  project.  The  segment's  revenues  are  primarily  derived  from  rates  that  recover  costs  and  provide  a  return  on   transmission  capital  investment.  Except  for  the  recovery  of  the  PATH  abandoned  project  regulatory  asset,  these  revenues  are   primarily   from   transmission   services   provided   pursuant   to   its   PJM   Tariff   to   LSEs.   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,  Illinois,  Michigan,  New  Jersey  and   Maryland,  and  the  provision  of  partial  POLR  and  default  service  for  some  utilities  in  Ohio,  Pennsylvania  and  Maryland,  including  the   Utilities.  This  business  segment  currently  controls  13,162  MWs  of  capacity.  The  CES  segment’s  net  income  is  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.   The  CES  segment  expects  to  sell  its  annual  generation  output  of  approximately  75  to  80  million  MWHs,  with  up  to  an  additional  5   million  MWHs  available  from  PPAs  for  wind,  solar  and  its  entitlement  from  OVEC,  through  a  target  portfolio  mix  of  approximately  10  to   15  million  MWHs  in  Governmental  Aggregation  sales,  0  to  10  million  MWHs  of  POLR  sales,  0  to  20  million  MWHs  in  large  commercial   and  industrial  sales  (Direct),  10  to  20  million  MWHs  in  block  wholesale  sales,  including  Structured  Sales,  and  10  to  20  million  MWHs   of  spot  wholesale  sales.   Corporate  support  and  other  businesses  that  do  not  constitute  an  operating  segment,  interest  expense  on  stand-­alone  holding   company   debt   and   corporate   income   taxes   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,  2015,  Corporate/Other  had  $4.2  billion  of  stand-­alone  holding  company  long-­term  debt,  of  which  28%  was  subject  to   variable-­interest  rates,  and  $1.7  billion  was  borrowed  by  FE  under  its  revolving  credit  facility.     4 5   EXECUTIVE  SUMMARY   FirstEnergy  continues  to  capitalize  on  investment  opportunities  available  in  its  Regulated  Transmission  and  Regulated  Distribution   businesses  while  implementing  a  conservative  hedging  strategy  at  its  Competitive  business.  FirstEnergy  is  focused  on  improving  its   balance  sheet  and  maintaining  investment  grade  credit  metrics  at  each  business  unit,  while  improving  metrics  at  FirstEnergy  over   time.   April  1,  2017.   Competitive  Energy  Services   Additionally,  during  2015,  the  NJBPU  issued  orders  on  JCP&L’s  base  rate  proceedings  and  its  generic  storm  proceedings  resulting  in   a  reduction  of  approximately  $34  million  in  annual  revenues,  inclusive  of  recovery  of  2011  and  2012  storm  costs,  as  well  as  the   NJBPU’s  recently  modified  CTA  policy.  As  part  of  the  base  rate  order,  JCP&L  is  required  to  file  another  base  rate  case  no  later  than   FirstEnergy’s  regulated  investment  strategy  focuses  on  delivering  enhanced  customer  service  and  reliability,  strengthening  grid  and   cyber-­security,   and   adding   resiliency   and   operating   flexibility   to   its   transmission   and   distribution   infrastructure.     Focusing   on   reinvestment  in  its  regulated  operations  will  also  provide  stability  and  growth  for  FirstEnergy  as  this  plan  is  implemented  over  the   coming  years.   Regulated  Transmission   The  centerpiece  of  FirstEnergy’s  regulated  investment  strategy  is  the  Energizing  the  Future  transmission  expansion  plan.  The  initial   phase  of  this  plan  includes  $4.2  billion  in  investments  from  2014  through  2017  to  modernize  FirstEnergy's  transmission  system.   In  conjunction  with  its  transmission  expansion  plan,  in  2015  ATSI  received  FERC-­approval  of    its  "forward  looking"  rate,  implemented   on  January  1,  2015,  where  transmission  rates  are  based  on  estimated  costs  for  the  current  year  with  an  annual  true  up,  and  an  ROE   of:  (i)  12.38%  from  January  1,  2015  through  June  30,  2015;;  (ii)  11.06%  from  July  1,  2015  through  December  31,  2015;;  and  10.38%   effective  January  1,  2016,  unless  changed  pursuant  to  Section  205  or  206  of  the  FPA,  provided  the  effective  date  for  any  change   cannot  be  earlier  than  January  1,  2018.   Additionally,   in   June   2015,   JCP&L,   PN,   ME,   FET,   and   MAIT   made   filings   with   FERC,   the   NJBPU,   and   the   PPUC   requesting   authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT.  If  approved,  MAIT  will  operate  similar  to  FET’s   two  existing  stand-­alone  transmission  subsidiaries  ATSI  and  TrAIL.    FERC  approval  is  expected  in  March  2016  with  final  decisions   expected  from  the  NJBPU  and  PPUC  by  mid-­2016.  Following  FERC  approval  of  the  transfer,  MAIT  expects  to  file  a  Section  204   application  with  FERC,  and  other  necessary  filings  with  the  PPUC  and  the  NJBPU,  seeking  authorization  to  issue  equity  to  FET,   JCP&L,  PN  and  ME  for  their  respective  contributions,  and  to  issue  debt.  MAIT  will  also  make  a  Section  205  formula  rate  application   with  FERC  to  establish  its  transmission  rate.   Regulated  Distribution   During  2015,  FirstEnergy  continued  to  pursue  key  regulatory  initiatives  across  its  utility  footprint,  focusing  on  providing  significant   benefits  to  customers  while  ensuring  the  timely  and  appropriate  recovery  of  investments.  These  initiatives  included:   Also,  in  2015,  PJM  conducted  the  2015  BRA  for  the  2018/2019  delivery  year  and  Capacity  Performance  transition  auctions  for  the   2016/2017   and   2017/2018   delivery   years.   FirstEnergy’s   net   competitive   capacity   position   as   a   result   of   the   BRA   and   Capacity   •     The  Ohio  Companies'  ESP  IV,  Powering  Ohio’s  Progress:  The  ESP  IV,  including  the  impact  of  filed  stipulations  in  the  case,   contemplates  continuing  a  distribution  rate  freeze  through  May  2024  while  helping  ensure  continued  availability  of  more  than   3,200  MWs  of  FirstEnergy’s  critical  baseload  generating  assets  primarily  located  in  the  state  and  serving  the  long-­term   energy  needs  of  Ohio  customers.  Evidentiary  hearings  commenced  in  August  2015.  On  December  1,  2015,  FirstEnergy's   Ohio  Companies  filed  an  additional  settlement  at  the  PUCO,  which  included  the  PUCO  Staff  as  a  signatory  party,  that  sets   forth  ambitious  steps  to  help  safeguard  customers  against  retail  generation  price  increases  in  future  years,  deploy  new   energy  efficiency  programs,  and  provide  a  clear  path  to  a  cleaner  energy  future  by  establishing  a  goal  to  substantially   reduce   carbon   emissions.  The   settlement   includes   an   eight-­year   rate   provision   (Rider   RRS)   designed   to   help   protect   customers  against  rising  retail  price  increases  and  market  volatility,  while  helping  preserve  vital  baseload  power  plants  that   serve  Ohio  customers  and  provide  thousands  of  family-­sustaining  jobs  in  the  state.  The  plants  involved  include  the  Davis-­ Besse  Nuclear  Power  Station,  the  W.H.  Sammis  Plant,  and  a  portion  of  the  output  of  OVEC  units  in  Gallipolis,  Ohio,  and   Madison,  Indiana.  A  decision  is  anticipated  in  March  2016.  On  January  27,  2016,  certain  parties  filed  a  complaint  at  FERC   against  FES,  OE,  CEI,  and  TE  that  requests  FERC  review  of  the  ESP  IV  PPA  under  Section  205  of  the  FPA.  In  addition  to   such  proceeding,  parties  have  expressed  an  intention  to  challenge,  in  the  courts  and/or  before  FERC,  the  PPA  or  PUCO   approval  of  the  ESP  IV,  if  approved.  Management  intends  to  vigorously  defend  against  such  challenges.   •   •   Implementation  of  New  Rates  in  Pennsylvania  for  ME,  PN,  Penn  and  WP:  The  new  rates  were  approved  in  April  2015  and   went  into  effect  in  May  2015,  providing  for  an  increase  in  annual  revenues  of  approximately  $293  million  and  approximately   $88  million  of  additional  annual  operating  expenses.  Furthermore,  in  October  2015,  the  Pennsylvania  companies  filed   LTIIPs  with  the  PPUC  for  infrastructure  improvements  over  the  2016  to  2020  period  totaling  nearly  $245  million,  which  were   approved  on  February  11,  2016.  The  Pennsylvania  Companies  filed  DSIC  riders  on  February  16,  2016,  for  quarterly  cost   recovery  associated  with  the  projects  approved  in  the  LTIIPs. Implementation   of   New   Rates   in   West   Virginia   for   MP   and   PE:   The   new   rates   were   approved   and   went   into   effect   in   February   2015,   resulting   in   recovery   of   $63   million   annually   for   reliability   investments   and   expenses,   storm   damage   expenses,  and  investments  in  operating  improvements  and  environmental  compliance  at  MP’s  and  PE’s  regulated  coal-­fired   power  plants  in  West  Virginia.  MP  and  PE  also  received  orders  in  December  2015  in  their  ENEC  case  and  their  biennial   vegetation  management  program  surcharge  reconciliation,  resulting  in  revenue  increases,  effective  January  1,  2016,  totaling   $96.9  million  and  $36.7  million,  respectively,  to  recover  deferred  costs. 6   7   FirstEnergy  continues  its  strategy  for  its  competitive  business  to  more  effectively  hedge  its  generation  by  reducing  exposure  to   weather-­sensitive  load  in  certain  sales  channels  and  pursuing  high-­margin  sales,  while  leaving  a  portion  of  its  generation  available  to   capture  future  market  opportunities  or  to  mitigate  risk.  This  strategy  is  designed  to  position  CES  to  benefit  from  opportunities  as   markets   improve   while   limiting   risk   from   continued   challenging   market   conditions.  At   the   same   time,   FirstEnergy   continues   to   advocate  for  reforms  that  can  ensure  competitive  wholesale  markets  adequately  value  baseload  generation,  which  is  essential  to   maintaining  grid  reliability.   The  CES  segment  economically  hedges  exposure  to  price  risk  on  a  ratable  basis,  which  is  intended  to  reduce  the  near-­term  financial   impact  of  market  price  volatility.  On  average,  the  CES  segment  expects  to  produce  approximately  75  -­  80  million  MWHs  of  electricity   annually,  with  up  to  an  additional  5  million  MWHs  available  from  purchased  power  agreements  for  wind,  solar  and  its  entitlement  from   OVEC.    In  2015,  CES  sold  approximately  75  million  MWHs  of  which  68  million  MWHs  were  through  contract  sales  with  another  7   million  MWHs  of  wholesale  sales.  As  of  December  31,  2015,  committed  sales  for  2016  and  2017  were  approximately  61  million   MWHs  and  38  million  MWHs,  respectively.     From   a   generation   perspective,   FirstEnergy   continues   to   focus   on   ensuring   its   competitive   fleet   is   cost-­effective,   efficient   and   environmentally  sound.  FirstEnergy  is  on  track  to  exceed  benchmarks  established  by  MATS  and  other  environmental  regulations.   FirstEnergy’s  total  cost  for  MATS  compliance  is  expected  to  be  approximately  $345  million  ($168  million  at  CES  and  $177  million  at   Regulated  Distribution),  of  which  $202  million  has  been  spent  through  December  31,  2015  ($80  million  at  CES  and  $122  million  at   Regulated  Distribution).   During  2015,  FirstEnergy  completed  scheduled  shutdowns  for  three  of  its  nuclear  units  -­  Beaver  Valley  Unit  1  and  Unit  2  and  the   Perry  Nuclear  Power  plant  -­  for  refueling  and  maintenance.  During  the  outages,  fuel  assemblies  were  exchanged  and  numerous   inspections   and   preventative   maintenance   and   improvement   projects   were   completed   to   ensure   continued   safe   and   reliable   operations.    Additionally,  in  December  2015,  the  NRC  approved  a  20-­year  license  extension  for  the  Davis-­Besse  Nuclear  Power   Station  allowing  the  unit  to  operate  until  2037.   Performance  transition  auctions  is  as  follows:   2016  -­  2017   2017  -­  2018   2018  -­  2019*   Legacy   Obligation   Capacity   Performance   Legacy   Obligation   Capacity   Performance   Base   Generation   Capacity   Performance   (MW)   ($/MWD)   (MW)   ($/MWD)   (MW)   (MW)   ($/MWD)   ($/MWD)   (MW)   ($/MWD)   ($/MWD)   (MW)   2,765   $114.23   4,210   $134.00   375   $120.00   6,245   $151.50   —   $149.98   6,245   $164.77   $59.37   3,675   $134.00   985   $120.00   3,565   $151.50   240   $149.98   3,930   $164.77   $119.13   —   $134.00   150   $120.00   —   $151.50   35   **   20   **   ATSI   RTO   All  Other   Zones   875   135   3,775   7,885   1,510   9,810   275   10,195   *Approximately  885  MWs  remain  uncommitted  for  the  2018/2019  delivery  year.       **Base  Generation:  10  MWs  cleared  at  $200.21/MWD  and  25  MWs  cleared  at  $149.98/MWD.  Capacity  Performance:  5  MWs  cleared  at   $215.00/MWD  and  15  MWs  cleared  at  $164.77/MWD.       Projected  CES  Capacity  Revenue*  ($  Millions)   Capacity  Revenue   2016   $815   2017   $590   2018   $620   (through  5/31)   2019   $260   *Includes  revenues  from  the  results  of  incremental/transitional  capacity  auctions,  bilateral  transactions  and  capacity  transfer  rights.                                               FirstEnergy  continues  to  capitalize  on  investment  opportunities  available  in  its  Regulated  Transmission  and  Regulated  Distribution   businesses  while  implementing  a  conservative  hedging  strategy  at  its  Competitive  business.  FirstEnergy  is  focused  on  improving  its   balance  sheet  and  maintaining  investment  grade  credit  metrics  at  each  business  unit,  while  improving  metrics  at  FirstEnergy  over   FirstEnergy’s  regulated  investment  strategy  focuses  on  delivering  enhanced  customer  service  and  reliability,  strengthening  grid  and   cyber-­security,   and   adding   resiliency   and   operating   flexibility   to   its   transmission   and   distribution   infrastructure.     Focusing   on   reinvestment  in  its  regulated  operations  will  also  provide  stability  and  growth  for  FirstEnergy  as  this  plan  is  implemented  over  the   EXECUTIVE  SUMMARY   time.   coming  years.   Regulated  Transmission   The  centerpiece  of  FirstEnergy’s  regulated  investment  strategy  is  the  Energizing  the  Future  transmission  expansion  plan.  The  initial   phase  of  this  plan  includes  $4.2  billion  in  investments  from  2014  through  2017  to  modernize  FirstEnergy's  transmission  system.   In  conjunction  with  its  transmission  expansion  plan,  in  2015  ATSI  received  FERC-­approval  of    its  "forward  looking"  rate,  implemented   on  January  1,  2015,  where  transmission  rates  are  based  on  estimated  costs  for  the  current  year  with  an  annual  true  up,  and  an  ROE   of:  (i)  12.38%  from  January  1,  2015  through  June  30,  2015;;  (ii)  11.06%  from  July  1,  2015  through  December  31,  2015;;  and  10.38%   effective  January  1,  2016,  unless  changed  pursuant  to  Section  205  or  206  of  the  FPA,  provided  the  effective  date  for  any  change   cannot  be  earlier  than  January  1,  2018.   Additionally,   in   June   2015,   JCP&L,   PN,   ME,   FET,   and   MAIT   made   filings   with   FERC,   the   NJBPU,   and   the   PPUC   requesting   authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT.  If  approved,  MAIT  will  operate  similar  to  FET’s   two  existing  stand-­alone  transmission  subsidiaries  ATSI  and  TrAIL.    FERC  approval  is  expected  in  March  2016  with  final  decisions   expected  from  the  NJBPU  and  PPUC  by  mid-­2016.  Following  FERC  approval  of  the  transfer,  MAIT  expects  to  file  a  Section  204   application  with  FERC,  and  other  necessary  filings  with  the  PPUC  and  the  NJBPU,  seeking  authorization  to  issue  equity  to  FET,   JCP&L,  PN  and  ME  for  their  respective  contributions,  and  to  issue  debt.  MAIT  will  also  make  a  Section  205  formula  rate  application   with  FERC  to  establish  its  transmission  rate.   Regulated  Distribution   During  2015,  FirstEnergy  continued  to  pursue  key  regulatory  initiatives  across  its  utility  footprint,  focusing  on  providing  significant   benefits  to  customers  while  ensuring  the  timely  and  appropriate  recovery  of  investments.  These  initiatives  included:   •     The  Ohio  Companies'  ESP  IV,  Powering  Ohio’s  Progress:  The  ESP  IV,  including  the  impact  of  filed  stipulations  in  the  case,   contemplates  continuing  a  distribution  rate  freeze  through  May  2024  while  helping  ensure  continued  availability  of  more  than   3,200  MWs  of  FirstEnergy’s  critical  baseload  generating  assets  primarily  located  in  the  state  and  serving  the  long-­term   energy  needs  of  Ohio  customers.  Evidentiary  hearings  commenced  in  August  2015.  On  December  1,  2015,  FirstEnergy's   Ohio  Companies  filed  an  additional  settlement  at  the  PUCO,  which  included  the  PUCO  Staff  as  a  signatory  party,  that  sets   forth  ambitious  steps  to  help  safeguard  customers  against  retail  generation  price  increases  in  future  years,  deploy  new   energy  efficiency  programs,  and  provide  a  clear  path  to  a  cleaner  energy  future  by  establishing  a  goal  to  substantially   reduce   carbon   emissions.  The   settlement   includes   an   eight-­year   rate   provision   (Rider   RRS)   designed   to   help   protect   customers  against  rising  retail  price  increases  and  market  volatility,  while  helping  preserve  vital  baseload  power  plants  that   serve  Ohio  customers  and  provide  thousands  of  family-­sustaining  jobs  in  the  state.  The  plants  involved  include  the  Davis-­ Besse  Nuclear  Power  Station,  the  W.H.  Sammis  Plant,  and  a  portion  of  the  output  of  OVEC  units  in  Gallipolis,  Ohio,  and   Madison,  Indiana.  A  decision  is  anticipated  in  March  2016.  On  January  27,  2016,  certain  parties  filed  a  complaint  at  FERC   against  FES,  OE,  CEI,  and  TE  that  requests  FERC  review  of  the  ESP  IV  PPA  under  Section  205  of  the  FPA.  In  addition  to   such  proceeding,  parties  have  expressed  an  intention  to  challenge,  in  the  courts  and/or  before  FERC,  the  PPA  or  PUCO   approval  of  the  ESP  IV,  if  approved.  Management  intends  to  vigorously  defend  against  such  challenges.   •   Implementation  of  New  Rates  in  Pennsylvania  for  ME,  PN,  Penn  and  WP:  The  new  rates  were  approved  in  April  2015  and   went  into  effect  in  May  2015,  providing  for  an  increase  in  annual  revenues  of  approximately  $293  million  and  approximately   $88  million  of  additional  annual  operating  expenses.  Furthermore,  in  October  2015,  the  Pennsylvania  companies  filed   LTIIPs  with  the  PPUC  for  infrastructure  improvements  over  the  2016  to  2020  period  totaling  nearly  $245  million,  which  were   approved  on  February  11,  2016.  The  Pennsylvania  Companies  filed  DSIC  riders  on  February  16,  2016,  for  quarterly  cost   recovery  associated  with  the  projects  approved  in  the  LTIIPs. •   Implementation   of   New   Rates   in   West   Virginia   for   MP   and   PE:   The   new   rates   were   approved   and   went   into   effect   in   February   2015,   resulting   in   recovery   of   $63   million   annually   for   reliability   investments   and   expenses,   storm   damage   expenses,  and  investments  in  operating  improvements  and  environmental  compliance  at  MP’s  and  PE’s  regulated  coal-­fired   power  plants  in  West  Virginia.  MP  and  PE  also  received  orders  in  December  2015  in  their  ENEC  case  and  their  biennial   vegetation  management  program  surcharge  reconciliation,  resulting  in  revenue  increases,  effective  January  1,  2016,  totaling   $96.9  million  and  $36.7  million,  respectively,  to  recover  deferred  costs. Additionally,  during  2015,  the  NJBPU  issued  orders  on  JCP&L’s  base  rate  proceedings  and  its  generic  storm  proceedings  resulting  in   a  reduction  of  approximately  $34  million  in  annual  revenues,  inclusive  of  recovery  of  2011  and  2012  storm  costs,  as  well  as  the   NJBPU’s  recently  modified  CTA  policy.  As  part  of  the  base  rate  order,  JCP&L  is  required  to  file  another  base  rate  case  no  later  than   April  1,  2017.   Competitive  Energy  Services   FirstEnergy  continues  its  strategy  for  its  competitive  business  to  more  effectively  hedge  its  generation  by  reducing  exposure  to   weather-­sensitive  load  in  certain  sales  channels  and  pursuing  high-­margin  sales,  while  leaving  a  portion  of  its  generation  available  to   capture  future  market  opportunities  or  to  mitigate  risk.  This  strategy  is  designed  to  position  CES  to  benefit  from  opportunities  as   markets   improve   while   limiting   risk   from   continued   challenging   market   conditions.  At   the   same   time,   FirstEnergy   continues   to   advocate  for  reforms  that  can  ensure  competitive  wholesale  markets  adequately  value  baseload  generation,  which  is  essential  to   maintaining  grid  reliability.   The  CES  segment  economically  hedges  exposure  to  price  risk  on  a  ratable  basis,  which  is  intended  to  reduce  the  near-­term  financial   impact  of  market  price  volatility.  On  average,  the  CES  segment  expects  to  produce  approximately  75  -­  80  million  MWHs  of  electricity   annually,  with  up  to  an  additional  5  million  MWHs  available  from  purchased  power  agreements  for  wind,  solar  and  its  entitlement  from   OVEC.    In  2015,  CES  sold  approximately  75  million  MWHs  of  which  68  million  MWHs  were  through  contract  sales  with  another  7   million  MWHs  of  wholesale  sales.  As  of  December  31,  2015,  committed  sales  for  2016  and  2017  were  approximately  61  million   MWHs  and  38  million  MWHs,  respectively.     From   a   generation   perspective,   FirstEnergy   continues   to   focus   on   ensuring   its   competitive   fleet   is   cost-­effective,   efficient   and   environmentally  sound.  FirstEnergy  is  on  track  to  exceed  benchmarks  established  by  MATS  and  other  environmental  regulations.   FirstEnergy’s  total  cost  for  MATS  compliance  is  expected  to  be  approximately  $345  million  ($168  million  at  CES  and  $177  million  at   Regulated  Distribution),  of  which  $202  million  has  been  spent  through  December  31,  2015  ($80  million  at  CES  and  $122  million  at   Regulated  Distribution).   During  2015,  FirstEnergy  completed  scheduled  shutdowns  for  three  of  its  nuclear  units  -­  Beaver  Valley  Unit  1  and  Unit  2  and  the   Perry  Nuclear  Power  plant  -­  for  refueling  and  maintenance.  During  the  outages,  fuel  assemblies  were  exchanged  and  numerous   inspections   and   preventative   maintenance   and   improvement   projects   were   completed   to   ensure   continued   safe   and   reliable   operations.    Additionally,  in  December  2015,  the  NRC  approved  a  20-­year  license  extension  for  the  Davis-­Besse  Nuclear  Power   Station  allowing  the  unit  to  operate  until  2037.   Also,  in  2015,  PJM  conducted  the  2015  BRA  for  the  2018/2019  delivery  year  and  Capacity  Performance  transition  auctions  for  the   2016/2017   and   2017/2018   delivery   years.   FirstEnergy’s   net   competitive   capacity   position   as   a   result   of   the   BRA   and   Capacity   Performance  transition  auctions  is  as  follows:   2016  -­  2017   2017  -­  2018   2018  -­  2019*   Legacy   Obligation   Capacity   Performance   Legacy   Obligation   Capacity   Performance   Base   Generation   Capacity   Performance   (MW)   ($/MWD)   (MW)   2,765   $114.23   4,210   $59.37   3,675   875   $119.13   —   135   ($/MWD)   $134.00   $134.00   $134.00   ATSI   RTO   All  Other   Zones   ($/MWD)   ($/MWD)   (MW)   (MW)   (MW)   375   $120.00   6,245   $151.50   —   $149.98   6,245   985   $120.00   3,565   $151.50   240   $149.98   3,930   $151.50   150   $120.00   —   ($/MWD)   20   35   **   (MW)   ($/MWD)   $164.77   $164.77   **   3,775   7,885   1,510   9,810   275   10,195   *Approximately  885  MWs  remain  uncommitted  for  the  2018/2019  delivery  year.       **Base  Generation:  10  MWs  cleared  at  $200.21/MWD  and  25  MWs  cleared  at  $149.98/MWD.  Capacity  Performance:  5  MWs  cleared  at   $215.00/MWD  and  15  MWs  cleared  at  $164.77/MWD.       Projected  CES  Capacity  Revenue*  ($  Millions)   Capacity  Revenue   2016   $815   2017   $590   2018   $620   2019   (through  5/31)   $260   *Includes  revenues  from  the  results  of  incremental/transitional  capacity  auctions,  bilateral  transactions  and  capacity  transfer  rights.   6   7                                               CES   FirstEnergy  continues  to  focus  on  maintaining  the  value  of  its  competitive  business  and  continues  to  advocate  for  reforms  that  ensure   the  competitive  wholesale  markets  adequately  value  baseload  generation,  which  is  essential  for  maintaining  grid  reliability.  While  it   cannot  predict  if  or  when  a  power  price  recovery  may  occur,  FirstEnergy  believes  it  has  taken  appropriate  action  over  the  last  several   years  to  reposition  this  business  for  such  a  recovery.  CES  uses  a  conservative  hedging  strategy,  and  expects  to  sell  its  annual   generation  resources  of  approximately  75-­80  million  MWHs  through  a  combination  of  retail  and  wholesale  sales,  maintaining  10-­20   million   MWHs   to   mitigate   risk   in   the   event   of   unplanned   outages   or   extreme   weather   or   to   take   advantage   of   market   upside   opportunities  through  the  wholesale  spot  market.   STRATEGY  AND  OUTLOOK   FirstEnergy  owns  a  large  and  diverse  mix  of  assets  managed  in  an  integrated  model,  featuring  an  electric  distribution  service  area   and  transmission  footprint  that  are  among  the  largest  in  the  nation,  as  well  as  a  competitive  operations  segment  that  owns  or  controls   over  13,000  MWs  of  generation  with  a  diverse  mix  of  non-­emitting  nuclear,  scrubbed  coal,  natural  gas,  hydroelectric  and  other   renewables.   FirstEnergy   continues   to   focus   on   developing   its   transmission   business,   strengthening   its   regulated   utilities,   and   managing  overall  risk  and  conservatively  operating  its  competitive  business.   FirstEnergy  continues  to  focus  on  investment  opportunities  in  its  Regulated  Transmission  and  Regulated  Distribution  segments.    This   investment  strategy  is  focused  on  delivering  enhanced  customer  service  and  reliability,  strengthening  grid  and  cyber-­security,  and   adding   resiliency   and   operating   flexibility   to   its   transmission   and   distribution   infrastructure.     FirstEnergy   expects   to   fund   these   investments  through  a  combination  of  cash  from  operations,  debt,  and,  depending  on  the  regulated  operating  company,  capital   contributions  from  its  parent.    In  the  future,  FirstEnergy  may  consider  additional  equity  to  fund  capital  requirements  in  its  regulated   operations.   FirstEnergy's  longer  term  strategic  outlook  for  its  regulated  and  competitive  businesses  will  be  determined  following  resolution  of  the   Ohio   Companies'   ESP   IV,   including   the   proposed   PPA   between   FES   and   the   Ohio   Companies.   Once   the   ESP   IV   is   finalized,   FirstEnergy  expects  to  be  in  a  position  to  more  fully  understand  the  longer-­term  outlook  of  its  competitive  businesses  and  the  longer   term  growth  rate  of  its  regulated  businesses,  including  planned  capital  investments  and  any  additional  equity  to  fund  growth  in  its   regulated  businesses.     FirstEnergy  is  focused  on  improving  its  balance  sheet  and  maintaining  investment  grade  credit  metrics  at  each  business  unit,  while   improving  metrics  at  FirstEnergy  Corp.  over  time.  As  part  of  an  ongoing  effort  to  manage  costs,  FirstEnergy  identified  both  immediate   and  long-­term  savings  opportunities  through  its  cash  flow  improvement  plan.  The  cash  flow  improvement  plan  identified  targeted  cash   savings  of  approximately  $58  million  in  2015,  $155  million  in  2016  and  $240  million  annually  by  2017,  with  reductions  in  operating   expenses  representing  approximately  65%  of  the  savings  over  the  three-­year  period.   Regulated  Transmission   As  noted  above,  the  centerpiece  of  FirstEnergy’s  growth  strategy  is  a  $4.2  billion  investment  in  the  Energizing  the  Future  program   from  2014  through  2017.  Through  2015,  FirstEnergy's  capital  expenditures  under  this  plan  were  $2.4  billion  and  in  2016  capital   expenditures  under  this  plan  are  currently  projected  to  be  approximately  $1  billion.  This  program  is  focused  on  a  large  number  of   small  projects  within  the  company’s  24,000  mile  service  territory  that  improve  service  to  customers.  The  projects  within  the  program   are  either  regulatory  required  or  support  reliability  enhancement.  Regulatory  required  projects  include  those  requested  by  PJM  to   support  grid  reliability,  generator  deactivations,  or  shale  gas  expansion  activities.  The  second  category  of  projects,  those  that  support   reliability  enhancement,  focus  on  replacing  aging  equipment;;  increasing  automation,  communication,  and  security  within  the  system;;   and  increasing  load  serving  capability.  In  the  initial  years  of  the  program,  the  majority  of  the  projects  are  located  within  the  ATSI   system,  with  expectations  to  move  east  across  FirstEnergy's  service  territory  over  time.    An  additional  $15  billion  in  transmission   investment   opportunities   have   been   identified   across   the   system   beyond   the   2014-­2017   period,   making   this   a   continuing   and   sustainable  platform  for  investment.   In  2016,  FirstEnergy  expects  to  receive  approval  to  transfer  transmission  assets  of  JCP&L,  Met-­Ed  and  Penelec  to  MAIT,  a  new   stand-­alone  transmission  subsidiary.   Regulated  Distribution   The  five-­state  service  territory  served  by  FirstEnergy’s  Regulated  Distribution  segment  also  offers  substantial  opportunities  for  future   investments  to  improve  service  to  more  than  6  million  customers.    In  2015,  FirstEnergy  completed  major  rate  cases  in  West  Virginia,   Pennsylvania  and  New  Jersey.  In  Pennsylvania,  a  filing  for  an  infrastructure  improvement  plan  that  includes  an  investment  of  $245   million  through  2020  was  approved  by  the  PPUC  on  February  11,  2016,  and  in  Ohio,  a  comprehensive  settlement  in  the  ESP  IV  is   pending  PUCO  approval.    The  ESP  IV  settlement  contains  additional  opportunities  for  investment  in  the  Ohio  Companies,  including   grid  modernization  and  energy  efficiency  as  well  as  continuation  of  Rider  DCR  with  revenue  caps  increasing  $180  million  over  the   term  of  the  ESP  IV.  The  settlement  also  includes  a  FERC-­jurisdictional  PPA  where  the  Ohio  Companies  would  purchase  the  output   from  FES’  Davis-­Besse  nuclear  plant,  Sammis  coal  plant  and  entitlement  to  OVEC  generation  output,  a  total  of  3,244  MW,  for  an   eight-­year  term  beginning  June  1,  2016.   FirstEnergy  also  continues  to  closely  monitor  sales  trends  across  its  utility  footprint.  Within  its  Regulated  Distribution  segment,   FirstEnergy  continues  to  be  impacted  by  lower  customer  usage  as  a  result  of  energy  efficiency  mandates  and  products.  During  2015,   electric   distribution   deliveries   on   a   weather-­adjusted   basis   declined   1.6%   in   the   residential   customer   class   and   0.6%   in   the   commercial  customer  class  as  compared  to  2014.  Furthermore,  in  the  industrial  sector,  increases  in  the  shale  gas  sector  were  more   than  offset  with  lower  usage  in  the  steel  and  mining  sectors,  resulting  in  an  overall  decrease  in  the  industrial  sector  of  2.0%.   8   9                                 CES   FirstEnergy  continues  to  focus  on  maintaining  the  value  of  its  competitive  business  and  continues  to  advocate  for  reforms  that  ensure   the  competitive  wholesale  markets  adequately  value  baseload  generation,  which  is  essential  for  maintaining  grid  reliability.  While  it   cannot  predict  if  or  when  a  power  price  recovery  may  occur,  FirstEnergy  believes  it  has  taken  appropriate  action  over  the  last  several   years  to  reposition  this  business  for  such  a  recovery.  CES  uses  a  conservative  hedging  strategy,  and  expects  to  sell  its  annual   generation  resources  of  approximately  75-­80  million  MWHs  through  a  combination  of  retail  and  wholesale  sales,  maintaining  10-­20   million   MWHs   to   mitigate   risk   in   the   event   of   unplanned   outages   or   extreme   weather   or   to   take   advantage   of   market   upside   opportunities  through  the  wholesale  spot  market.   STRATEGY  AND  OUTLOOK   FirstEnergy  owns  a  large  and  diverse  mix  of  assets  managed  in  an  integrated  model,  featuring  an  electric  distribution  service  area   and  transmission  footprint  that  are  among  the  largest  in  the  nation,  as  well  as  a  competitive  operations  segment  that  owns  or  controls   over  13,000  MWs  of  generation  with  a  diverse  mix  of  non-­emitting  nuclear,  scrubbed  coal,  natural  gas,  hydroelectric  and  other   renewables.   FirstEnergy   continues   to   focus   on   developing   its   transmission   business,   strengthening   its   regulated   utilities,   and   managing  overall  risk  and  conservatively  operating  its  competitive  business.   FirstEnergy  continues  to  focus  on  investment  opportunities  in  its  Regulated  Transmission  and  Regulated  Distribution  segments.    This   investment  strategy  is  focused  on  delivering  enhanced  customer  service  and  reliability,  strengthening  grid  and  cyber-­security,  and   adding   resiliency   and   operating   flexibility   to   its   transmission   and   distribution   infrastructure.     FirstEnergy   expects   to   fund   these   investments  through  a  combination  of  cash  from  operations,  debt,  and,  depending  on  the  regulated  operating  company,  capital   contributions  from  its  parent.    In  the  future,  FirstEnergy  may  consider  additional  equity  to  fund  capital  requirements  in  its  regulated   operations.   FirstEnergy's  longer  term  strategic  outlook  for  its  regulated  and  competitive  businesses  will  be  determined  following  resolution  of  the   Ohio   Companies'   ESP   IV,   including   the   proposed   PPA   between   FES   and   the   Ohio   Companies.   Once   the   ESP   IV   is   finalized,   FirstEnergy  expects  to  be  in  a  position  to  more  fully  understand  the  longer-­term  outlook  of  its  competitive  businesses  and  the  longer   term  growth  rate  of  its  regulated  businesses,  including  planned  capital  investments  and  any  additional  equity  to  fund  growth  in  its   regulated  businesses.     FirstEnergy  is  focused  on  improving  its  balance  sheet  and  maintaining  investment  grade  credit  metrics  at  each  business  unit,  while   improving  metrics  at  FirstEnergy  Corp.  over  time.  As  part  of  an  ongoing  effort  to  manage  costs,  FirstEnergy  identified  both  immediate   and  long-­term  savings  opportunities  through  its  cash  flow  improvement  plan.  The  cash  flow  improvement  plan  identified  targeted  cash   savings  of  approximately  $58  million  in  2015,  $155  million  in  2016  and  $240  million  annually  by  2017,  with  reductions  in  operating   expenses  representing  approximately  65%  of  the  savings  over  the  three-­year  period.   Regulated  Transmission   As  noted  above,  the  centerpiece  of  FirstEnergy’s  growth  strategy  is  a  $4.2  billion  investment  in  the  Energizing  the  Future  program   from  2014  through  2017.  Through  2015,  FirstEnergy's  capital  expenditures  under  this  plan  were  $2.4  billion  and  in  2016  capital   expenditures  under  this  plan  are  currently  projected  to  be  approximately  $1  billion.  This  program  is  focused  on  a  large  number  of   small  projects  within  the  company’s  24,000  mile  service  territory  that  improve  service  to  customers.  The  projects  within  the  program   are  either  regulatory  required  or  support  reliability  enhancement.  Regulatory  required  projects  include  those  requested  by  PJM  to   support  grid  reliability,  generator  deactivations,  or  shale  gas  expansion  activities.  The  second  category  of  projects,  those  that  support   reliability  enhancement,  focus  on  replacing  aging  equipment;;  increasing  automation,  communication,  and  security  within  the  system;;   and  increasing  load  serving  capability.  In  the  initial  years  of  the  program,  the  majority  of  the  projects  are  located  within  the  ATSI   system,  with  expectations  to  move  east  across  FirstEnergy's  service  territory  over  time.    An  additional  $15  billion  in  transmission   investment   opportunities   have   been   identified   across   the   system   beyond   the   2014-­2017   period,   making   this   a   continuing   and   In  2016,  FirstEnergy  expects  to  receive  approval  to  transfer  transmission  assets  of  JCP&L,  Met-­Ed  and  Penelec  to  MAIT,  a  new   sustainable  platform  for  investment.   stand-­alone  transmission  subsidiary.   Regulated  Distribution   The  five-­state  service  territory  served  by  FirstEnergy’s  Regulated  Distribution  segment  also  offers  substantial  opportunities  for  future   investments  to  improve  service  to  more  than  6  million  customers.    In  2015,  FirstEnergy  completed  major  rate  cases  in  West  Virginia,   Pennsylvania  and  New  Jersey.  In  Pennsylvania,  a  filing  for  an  infrastructure  improvement  plan  that  includes  an  investment  of  $245   million  through  2020  was  approved  by  the  PPUC  on  February  11,  2016,  and  in  Ohio,  a  comprehensive  settlement  in  the  ESP  IV  is   pending  PUCO  approval.    The  ESP  IV  settlement  contains  additional  opportunities  for  investment  in  the  Ohio  Companies,  including   grid  modernization  and  energy  efficiency  as  well  as  continuation  of  Rider  DCR  with  revenue  caps  increasing  $180  million  over  the   term  of  the  ESP  IV.  The  settlement  also  includes  a  FERC-­jurisdictional  PPA  where  the  Ohio  Companies  would  purchase  the  output   from  FES’  Davis-­Besse  nuclear  plant,  Sammis  coal  plant  and  entitlement  to  OVEC  generation  output,  a  total  of  3,244  MW,  for  an   eight-­year  term  beginning  June  1,  2016.   FirstEnergy  also  continues  to  closely  monitor  sales  trends  across  its  utility  footprint.  Within  its  Regulated  Distribution  segment,   FirstEnergy  continues  to  be  impacted  by  lower  customer  usage  as  a  result  of  energy  efficiency  mandates  and  products.  During  2015,   electric   distribution   deliveries   on   a   weather-­adjusted   basis   declined   1.6%   in   the   residential   customer   class   and   0.6%   in   the   commercial  customer  class  as  compared  to  2014.  Furthermore,  in  the  industrial  sector,  increases  in  the  shale  gas  sector  were  more   than  offset  with  lower  usage  in  the  steel  and  mining  sectors,  resulting  in  an  overall  decrease  in  the  industrial  sector  of  2.0%.   8   9                                 FINANCIAL  OVERVIEW   (In  millions,  except  per  share  amounts)   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  long-­lived  assets   Total  operating  expenses   OPERATING  INCOME   OTHER  INCOME  (EXPENSE):   Loss  on  debt  redemptions   Investment  income  (loss)   Impairment  of  equity  method  investment   Interest  expense   Capitalized  financing  costs   Total  other  expense   For  the  Years  Ended  December  31,   2014   15,049   $   2015   15,026   $   2013   14,892   $   $   Increase  (Decrease)   2015  vs  2014   (23  )   —   %   $   2014  vs  2013   157   1   %   Operating  expenses  decreased  $1,253  million  in  2015  as  compared  to  2014,  including  a  $593  million  decrease  in  the  Company’s   pension  and  OPEB  mark-­to-­market  adjustment,  reflecting  a  decrease  at  CES  of  $1,747  million,  partially  offset  by  increases  at   Regulated  Distribution  and  Regulated  Transmission  of  $255  million  and  $73  million,  respectively.   •   The  increase  at  Regulated  Transmission  primarily  reflected  a  higher  rate  base  and  recovery  of  incremental  operating   expenses  as  well  as  ATSI’s  transition  to  a  forward-­looking  rate,  effective  January  1,  2015.  These  increases  were  partially   offset  by  a  lower  ROE  at  ATSI  in  the  last  six  months  of  2015  as  part  of  the  FERC-­approved  settlement  discussed  above. INCOME  FROM  CONTINUING  OPERATIONS   BEFORE  INCOME  TAXES  (BENEFITS)   INCOME  TAXES  (BENEFITS)   INCOME  FROM  CONTINUING  OPERATIONS   Discontinued  operations  (net  of  income  taxes  of   $0,  $69  and  $9,  respectively)  (Note  19)   NET  INCOME   EARNINGS  PER  SHARE  OF  COMMON   STOCK:   Basic  -­  Continuing  Operations   Basic  -­  Discontinued  Operations  (Note  19)   Basic  -­  Net  Income   Diluted  -­  Continuing  Operations   Diluted  -­  Discontinued  Operations  (Note  19)   Diluted  -­  Net  Income   $   $   $   $   $   1,855   4,318   3,749   242   1,282   268   978   42   12,734   2,292   —   (22  )   (362  )   (1,132  )   117   (1,399  )   893   315   578   2,280   4,716   3,962   835   1,220   12   962   —   13,987   1,062   (8  )   72   —   (1,073  )   118   (891  )   171   (42  )   213   2,496   3,963   3,593   (256  )   1,202   539   978   795   13,310   1,582   (132  )   33   —   (1,016  )   103   (1,012  )   570   195   375   (425  )   (398  )   (213  )   (593  )   62   256   16   42   (1,253  )   1,230   (19  )%   (8  )%   (5  )%   (71  )%   5   %   2,133   %   2   %   —   %   (9  )%   116   %   8   (94  )   (362  )   (59  )   (1  )   (508  )   722   357   365   (100  )%   (131  )%   —   %   5   %   (1  )%   57   %   422   %   (850  )%   171   %   (216  )   753   369   1,091   18   (527  )   (16  )   (795  )   677   (520  )   124   39   —   (57  )   15   121   (399  )   (237  )   (162  )   (9  )%   19   %   10   %   (426  )%   1   %   (98  )%   (2  )%   (100  )%   5   %   (33  )%   (94  )%   118   %   —   %   6   %   15   %   (12  )%   (70  )%   (122  )%   (43  )%   Changes  in  certain  operating  expenses  include  the  following:   •   Fuel  expense  declined  $425  million,  primarily  at  CES,  resulting  from  lower  fossil  generation  associated  with  low  energy   prices,  lower  unit  costs,  and  lower  settlement  and  termination  charges  on  fuel  and  transportation  contracts.     •   Purchased  power  decreased  $398  million,  primarily  reflecting  lower  volumes  at  CES,  resulting  from  lower  contract  sales,   partially  offset  by  higher  volumes  at  Regulated  Distribution  due  to  lower  customer  shopping  as  discussed  above,  and  higher   capacity  expense  associated  with  higher  capacity  rates.     •   Other  operating  expenses  decreased  $213  million,  primarily  reflecting  a  decrease  at  CES  associated  with  lower  PJM   transmission,  mark-­to-­market  and  retail-­related  costs  partially  offset  by  higher  nuclear  planned  outage  costs,  partially  offset   by  an  increase  at  Regulated  Distribution,  resulting  from  higher  network  transmission  expenses,  which  are  recovered  through   transmission   rates   as   discussed   above,   and   higher   operating   and   maintenance   expenses   associated   with   reliability   improvements.     •   Amortization  of  regulatory  assets,  net  increased  $256  million  primarily  reflecting  the  recovery  of  deferred  costs,  including   storm  costs,  associated  with  the  implementation  of  new  rates  discussed  above.     FirstEnergy's  other  expenses  increased  $508  million,  or  57%,  year-­over-­year,  primarily  resulting  from  a  $362  million  pre-­tax,  non-­cash   impairment  charge  associated  with  FEV’s  investment  in  Global  Holding,  lower  investment  income,  including  a  $65  million  increase  in   OTTI,  and  higher  interest  expense  associated  with  higher  average  debt  levels.       FirstEnergy’s  effective  tax  rate  on  income  from  continuing  operations  was  35.3%  in  2015  compared  to  (24.6)%  in  2014.  The  increase   in  the  effective  tax  rate  was  attributable  to  tax  planning  initiatives  executed  during  2014,  including  tax  benefits  associated  with  a   change  in  accounting  method  with  the  IRS  for  costs  associated  with  the  refurbishment  of  meters  and  transformers  and  the  expiration   of  the  statute  of  limitations  on  uncertain  state  tax  positions.    Additionally,  during  2014,  FirstEnergy  recognized  a  reduction  in  income   —   86   17   (86  )   (100  )%   69   406   %   tax  expense  of  $25  million  that  related  to  prior  periods  resulting  from  adjustments  to  its  tax  basis  balance  sheet.   578   $   299   $   392   $   279   93   %   $   (93  )   (24  )%   2014  compared  with  2013   1.37   $   —   1.37   $   1.37   $   —   1.37   $   0.51   $   0.20   0.71   $   0.51   $   0.20   0.71   $   0.90   $   0.04   0.94   $   0.90   $   0.04   0.94   $   0.86   (0.20  )   0.66   0.86   (0.20  )   0.66   169   %   $   (100  )%   93   %   $   169   %   $   (100  )%   93   %   $   (0.39  )   0.16   (0.23  )   (0.39  )   0.16   (0.23  )   (43  )%   400   %   (24  )%   (43  )%   400   %   (24  )%   FirstEnergy’s  net  income  in  2015  was  $578  million,  or  basic  and  diluted  earnings  of  $1.37  per  share  of  common  stock,  compared  with   $299  million,  or  basic  and  diluted  earnings  of  $0.71  per  share  of  common  stock  in  2014,  and  $392  million,  or  basic  and  diluted   earnings  of  $0.94  per  share  of  common  stock  in  2013.    Highlights  of  the  key  changes  in  year-­over-­year  financial  results  are  included   below:   2015  compared  with  2014   As  further  discussed  below,  FirstEnergy’s  2015  income  from  continuing  operations  increased  $365  million  as  compared  to  2014,   resulting   from   a   year-­over-­year   improvement   of   $506   million   at   CES,   $153   million   at   Regulated   Distribution   and   $75   million   at   Regulated  Transmission,  partially  offset  by  a  $369  million  decrease  at  Corporate/Other.       In  2015,  FirstEnergy’s  revenues  decreased  $23  million  as  compared  to  2014,  primarily  resulting  from  a  $905  million  decrease  at  CES   partially  offset  by  a  $523  million  increase  at  Regulated  Distribution  and  a  $242  million  increase  at  Regulated  Transmission.   •   The  decrease  in  revenue  at  CES  resulted  from  a  31  million  MWHs  decline  in  contract  sales,  in  line  with  CES’  strategy   discussed  above,  partially  offset  by  higher  wholesale  sales,  including  increased  capacity  revenue  associated  with  higher   capacity  auction  prices. •   The   increase   in   revenue   at   Regulated   Distribution   resulted   from   the   implementation   of   new   rates   at   certain   operating   companies  as  well  as  a  year-­over-­year  increase  in  retail  generation  revenue,  resulting  from  a  lower  number  of  customers   shopping   with   an   alternative   generation   supplier   and   higher   retail   transmission   revenue,   which   is   recovering   higher   transmission  related  expenses.  Distribution  deliveries  decreased  0.8%,  or  1.1  million  MWHs,  as  weather  adjusted  sales   declined  as  a  result  of  energy  efficiency  mandates  and  products  and  decreases  in  certain  industrial  sectors,  partially  offset   by  an  increase  in  weather-­related  sales. 10   11   FirstEnergy’s  2014  income  from  continuing  operations  decreased  $162  million  as  compared  to  2013  resulting  from  a  year-­over-­year   decline   of   $182   million   at   CES   and   $36   million   at   Regulated   Distribution,   partially   offset   by   a   year-­over-­year   improvement   at   Regulated  Transmission  of  $9  million  and  $47  million  at  Corporate/Other.   In  2014,  FirstEnergy’s  revenue  increased  $157  million  compared  to  2013.  The  increase  resulted  from  a  $382  million  increase  at   Regulated  Distribution  and  a  $38  million  increase  at  Regulated  Transmission,  partially  offset  by  a  decrease  in  CES  revenues  of  $209   million.   expenses. 2013. •   The  increase  in  revenue  at  Regulated  Distribution  resulted  from  higher  wholesale  generation  sales  associated  with  the   Harrison/Pleasants  asset  transfer  whereby  MP  acquired  1,476  MWs  of  generation  from  AE  Supply. •   The  increase  at  Regulated  Transmission  primarily  reflected  a  higher  rate  base  and  recovery  of  incremental  operating   •   The  decrease  at  CES  resulted  from  lower  contract  sales  as  in  2014,  CES  began  to  reduce  its  exposure  to  weather  sensitive   load  to  more  effectively  hedge  its  generation,  targeting  annual  contract  sales  of  65  to  75  million  MWHs  as  compared  to  the   109  million  MWHs  sold  in  2013.    This  change  in  strategy  resulted  in  a  9%  decrease  in  MWH  sales  in  2014  as  compared  to   Operating  expenses  increased  $677  million  in  2014  compared  to  2013,  including  a  $1,091  million  increase  in  FirstEnergy’s  Pension   and  OPEB  mark-­to-­market  adjustment,  primarily  reflecting  an  increase  at  Regulated  Distribution  of  $428  million,  CES  of  $265  million   and  Regulated  Transmission  of  $40  million.   Changes  in  certain  operating  expenses  include  the  following:   •   Lower  fuel  expense  of  $216  million,  primarily  reflected  the  deactivation  of  power  plants  in  2013  and  increased  outages.    Fuel   expense  at  CES  and  Regulated  Distribution  was  further  impacted  by  the  October  2013  Harrison/Pleasants  asset  transfer. •   Purchased  power  increased  $753  million,  primarily  reflecting  higher  CES  purchases  resulting  from  plant  deactivations,   increased   outages   and   the   asset   transfer   discussed   above   as   well   as   higher   unit   pricing   and   capacity   expense.   The   increase  in  unit  pricing  primarily  resulted  from  market  conditions  associated  with  the  extreme  weather  events  in  the  first   quarter  of  2014,  which  included  the  polar  vortex. •   Other  operating  expenses  increased  $369  million  primarily  resulting  from  higher  costs  at  Regulated  Distribution  associated   with  network  transmission  expenses,  increased  vegetation  management  expenses  in  West  Virginia,  as  well  as  higher   operating  and  maintenance  associated  with  reliability  improvements,  storm  restoration  costs  and  the  Harrison/Pleasants                           (In  millions,  except  per  share  amounts)   2015   2014   2013   2015  vs  2014   2014  vs  2013   For  the  Years  Ended  December  31,   Increase  (Decrease)   $   15,026   $   15,049   $   14,892   $   (23  )   —   %   $   157   1   %   FINANCIAL  OVERVIEW   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  long-­lived  assets   Total  operating  expenses   OPERATING  INCOME   OTHER  INCOME  (EXPENSE):   Loss  on  debt  redemptions   Investment  income  (loss)   Impairment  of  equity  method  investment   Interest  expense   Capitalized  financing  costs   Total  other  expense   INCOME  FROM  CONTINUING  OPERATIONS   BEFORE  INCOME  TAXES  (BENEFITS)   INCOME  TAXES  (BENEFITS)   INCOME  FROM  CONTINUING  OPERATIONS   Discontinued  operations  (net  of  income  taxes  of   $0,  $69  and  $9,  respectively)  (Note  19)   NET  INCOME   EARNINGS  PER  SHARE  OF  COMMON   STOCK:   Basic  -­  Continuing  Operations   Basic  -­  Discontinued  Operations  (Note  19)   Basic  -­  Net  Income   Diluted  -­  Continuing  Operations   Diluted  -­  Discontinued  Operations  (Note  19)   Diluted  -­  Net  Income   $   $   $   $   $   below:   2015  compared  with  2014   1,855   4,318   3,749   242   1,282   268   978   42   12,734   2,292   —   (22  )   (362  )   (1,132  )   117   (1,399  )   893   315   578   2,280   4,716   3,962   835   1,220   12   962   —   13,987   1,062   (8  )   72   —   (1,073  )   118   (891  )   171   (42  )   213   2,496   3,963   3,593   (256  )   1,202   539   978   795   13,310   1,582   (132  )   33   —   (1,016  )   103   (1,012  )   570   195   375   (425  )   (398  )   (213  )   (593  )   62   256   16   42   (1,253  )   1,230   (19  )%   (8  )%   (5  )%   (71  )%   5   %   2,133   %   2   %   —   %   (9  )%   116   %   8   (94  )   (362  )   (59  )   (1  )   (508  )   722   357   365   (100  )%   (131  )%   —   %   5   %   (1  )%   57   %   422   %   (850  )%   171   %   (216  )   753   369   1,091   18   (527  )   (16  )   (795  )   677   (520  )   124   39   —   (57  )   15   121   (399  )   (237  )   (162  )   (9  )%   19   %   10   %   (426  )%   1   %   (98  )%   (2  )%   (100  )%   5   %   (33  )%   (94  )%   118   %   —   %   6   %   15   %   (12  )%   (70  )%   (122  )%   (43  )%   —   86   17   (86  )   (100  )%   69   406   %   1.37   $   —   1.37   $   1.37   $   —   1.37   $   0.51   $   0.20   0.71   $   0.51   $   0.20   0.71   $   0.90   $   0.04   0.94   $   0.90   $   0.04   0.94   $   0.86   (0.20  )   0.66   0.86   (0.20  )   0.66   169   %   $   (100  )%   93   %   $   169   %   $   (100  )%   93   %   $   (0.39  )   0.16   (0.23  )   (0.39  )   0.16   (0.23  )   (43  )%   400   %   (24  )%   (43  )%   400   %   (24  )%   FirstEnergy’s  net  income  in  2015  was  $578  million,  or  basic  and  diluted  earnings  of  $1.37  per  share  of  common  stock,  compared  with   $299  million,  or  basic  and  diluted  earnings  of  $0.71  per  share  of  common  stock  in  2014,  and  $392  million,  or  basic  and  diluted   earnings  of  $0.94  per  share  of  common  stock  in  2013.    Highlights  of  the  key  changes  in  year-­over-­year  financial  results  are  included   As  further  discussed  below,  FirstEnergy’s  2015  income  from  continuing  operations  increased  $365  million  as  compared  to  2014,   resulting   from   a   year-­over-­year   improvement   of   $506   million   at   CES,   $153   million   at   Regulated   Distribution   and   $75   million   at   Regulated  Transmission,  partially  offset  by  a  $369  million  decrease  at  Corporate/Other.       In  2015,  FirstEnergy’s  revenues  decreased  $23  million  as  compared  to  2014,  primarily  resulting  from  a  $905  million  decrease  at  CES   partially  offset  by  a  $523  million  increase  at  Regulated  Distribution  and  a  $242  million  increase  at  Regulated  Transmission.   •   The  decrease  in  revenue  at  CES  resulted  from  a  31  million  MWHs  decline  in  contract  sales,  in  line  with  CES’  strategy   discussed  above,  partially  offset  by  higher  wholesale  sales,  including  increased  capacity  revenue  associated  with  higher   capacity  auction  prices. •   The   increase   in   revenue   at   Regulated   Distribution   resulted   from   the   implementation   of   new   rates   at   certain   operating   companies  as  well  as  a  year-­over-­year  increase  in  retail  generation  revenue,  resulting  from  a  lower  number  of  customers   shopping   with   an   alternative   generation   supplier   and   higher   retail   transmission   revenue,   which   is   recovering   higher   transmission  related  expenses.  Distribution  deliveries  decreased  0.8%,  or  1.1  million  MWHs,  as  weather  adjusted  sales   declined  as  a  result  of  energy  efficiency  mandates  and  products  and  decreases  in  certain  industrial  sectors,  partially  offset   by  an  increase  in  weather-­related  sales. •   The  increase  at  Regulated  Transmission  primarily  reflected  a  higher  rate  base  and  recovery  of  incremental  operating   expenses  as  well  as  ATSI’s  transition  to  a  forward-­looking  rate,  effective  January  1,  2015.  These  increases  were  partially   offset  by  a  lower  ROE  at  ATSI  in  the  last  six  months  of  2015  as  part  of  the  FERC-­approved  settlement  discussed  above. Operating  expenses  decreased  $1,253  million  in  2015  as  compared  to  2014,  including  a  $593  million  decrease  in  the  Company’s   pension  and  OPEB  mark-­to-­market  adjustment,  reflecting  a  decrease  at  CES  of  $1,747  million,  partially  offset  by  increases  at   Regulated  Distribution  and  Regulated  Transmission  of  $255  million  and  $73  million,  respectively.   Changes  in  certain  operating  expenses  include  the  following:   •   Fuel  expense  declined  $425  million,  primarily  at  CES,  resulting  from  lower  fossil  generation  associated  with  low  energy   prices,  lower  unit  costs,  and  lower  settlement  and  termination  charges  on  fuel  and  transportation  contracts.     •   Purchased  power  decreased  $398  million,  primarily  reflecting  lower  volumes  at  CES,  resulting  from  lower  contract  sales,   partially  offset  by  higher  volumes  at  Regulated  Distribution  due  to  lower  customer  shopping  as  discussed  above,  and  higher   capacity  expense  associated  with  higher  capacity  rates.     •   Other  operating  expenses  decreased  $213  million,  primarily  reflecting  a  decrease  at  CES  associated  with  lower  PJM   transmission,  mark-­to-­market  and  retail-­related  costs  partially  offset  by  higher  nuclear  planned  outage  costs,  partially  offset   by  an  increase  at  Regulated  Distribution,  resulting  from  higher  network  transmission  expenses,  which  are  recovered  through   transmission   rates   as   discussed   above,   and   higher   operating   and   maintenance   expenses   associated   with   reliability   improvements.     •   Amortization  of  regulatory  assets,  net  increased  $256  million  primarily  reflecting  the  recovery  of  deferred  costs,  including   storm  costs,  associated  with  the  implementation  of  new  rates  discussed  above.     FirstEnergy's  other  expenses  increased  $508  million,  or  57%,  year-­over-­year,  primarily  resulting  from  a  $362  million  pre-­tax,  non-­cash   impairment  charge  associated  with  FEV’s  investment  in  Global  Holding,  lower  investment  income,  including  a  $65  million  increase  in   OTTI,  and  higher  interest  expense  associated  with  higher  average  debt  levels.       FirstEnergy’s  effective  tax  rate  on  income  from  continuing  operations  was  35.3%  in  2015  compared  to  (24.6)%  in  2014.  The  increase   in  the  effective  tax  rate  was  attributable  to  tax  planning  initiatives  executed  during  2014,  including  tax  benefits  associated  with  a   change  in  accounting  method  with  the  IRS  for  costs  associated  with  the  refurbishment  of  meters  and  transformers  and  the  expiration   of  the  statute  of  limitations  on  uncertain  state  tax  positions.    Additionally,  during  2014,  FirstEnergy  recognized  a  reduction  in  income   tax  expense  of  $25  million  that  related  to  prior  periods  resulting  from  adjustments  to  its  tax  basis  balance  sheet.   578   $   299   $   392   $   279   93   %   $   (93  )   (24  )%   2014  compared  with  2013   FirstEnergy’s  2014  income  from  continuing  operations  decreased  $162  million  as  compared  to  2013  resulting  from  a  year-­over-­year   decline   of   $182   million   at   CES   and   $36   million   at   Regulated   Distribution,   partially   offset   by   a   year-­over-­year   improvement   at   Regulated  Transmission  of  $9  million  and  $47  million  at  Corporate/Other.   In  2014,  FirstEnergy’s  revenue  increased  $157  million  compared  to  2013.  The  increase  resulted  from  a  $382  million  increase  at   Regulated  Distribution  and  a  $38  million  increase  at  Regulated  Transmission,  partially  offset  by  a  decrease  in  CES  revenues  of  $209   million.   •   The  increase  in  revenue  at  Regulated  Distribution  resulted  from  higher  wholesale  generation  sales  associated  with  the   Harrison/Pleasants  asset  transfer  whereby  MP  acquired  1,476  MWs  of  generation  from  AE  Supply. •   The  increase  at  Regulated  Transmission  primarily  reflected  a  higher  rate  base  and  recovery  of  incremental  operating   expenses. •   The  decrease  at  CES  resulted  from  lower  contract  sales  as  in  2014,  CES  began  to  reduce  its  exposure  to  weather  sensitive   load  to  more  effectively  hedge  its  generation,  targeting  annual  contract  sales  of  65  to  75  million  MWHs  as  compared  to  the   109  million  MWHs  sold  in  2013.    This  change  in  strategy  resulted  in  a  9%  decrease  in  MWH  sales  in  2014  as  compared  to   2013. Operating  expenses  increased  $677  million  in  2014  compared  to  2013,  including  a  $1,091  million  increase  in  FirstEnergy’s  Pension   and  OPEB  mark-­to-­market  adjustment,  primarily  reflecting  an  increase  at  Regulated  Distribution  of  $428  million,  CES  of  $265  million   and  Regulated  Transmission  of  $40  million.   Changes  in  certain  operating  expenses  include  the  following:   •   Lower  fuel  expense  of  $216  million,  primarily  reflected  the  deactivation  of  power  plants  in  2013  and  increased  outages.    Fuel   expense  at  CES  and  Regulated  Distribution  was  further  impacted  by  the  October  2013  Harrison/Pleasants  asset  transfer. •   Purchased  power  increased  $753  million,  primarily  reflecting  higher  CES  purchases  resulting  from  plant  deactivations,   increased   outages   and   the   asset   transfer   discussed   above   as   well   as   higher   unit   pricing   and   capacity   expense.   The   increase  in  unit  pricing  primarily  resulted  from  market  conditions  associated  with  the  extreme  weather  events  in  the  first   quarter  of  2014,  which  included  the  polar  vortex. •   Other  operating  expenses  increased  $369  million  primarily  resulting  from  higher  costs  at  Regulated  Distribution  associated   with  network  transmission  expenses,  increased  vegetation  management  expenses  in  West  Virginia,  as  well  as  higher   operating  and  maintenance  associated  with  reliability  improvements,  storm  restoration  costs  and  the  Harrison/Pleasants   10   11                           asset  transfer.  CES'  increase  in  other  operating  expenses  was  primarily  attributable  to  higher  transmission  costs,  which   resulted  from  the  market  conditions  associated  with  the  extreme  weather  events  in  the  first  quarter  of  2014,  and  higher   mark-­to-­market  expenses  on  derivative  contracts,  partially  offset  by  lower  generation  operating  and  maintenance  costs   primarily  resulting  from  the  deactivation  of  generating  plants  and  the  Harrison/Pleasants  asset  transfer. Summary  of  Results  of  Operations  —  2015  Compared  with  2014     Financial  results  for  FirstEnergy’s  business  segments  in  2015  and  2014  were  as  follows:   FirstEnergy’s   other   expenses   decreased   $121   million   year-­over-­year,   primarily   resulting   from   the   absence   of   a   loss   on   debt   redemptions  of  $124  million  recognized  in  2013.  Higher  interest  expense  was  offset  by  higher  investment  income  and  capitalized   financing  costs,  primarily  attributable  to  Regulated  Transmission’s  Energizing  the  Future  investment  plan.   FirstEnergy’s  effective  tax  rate  on  income  from  continuing  operations  was  (24.6)%  compared  to  34.2%  in  2013.  The  decrease  in  the   effective  tax  rate  was  attributable  to  tax  benefits  recognized  in  2014  associated  with  an  IRS-­approved  change  in  accounting  method   for  costs  associated  with  the  refurbishment  of  meters  and  transformers  and  the  expiration  of  the  statute  of  limitations  on  uncertain  tax   positions.  Additionally,  during  2014,  FirstEnergy  recognized  a  reduction  in  income  tax  expense  of  $25  million  that  related  to  prior   periods  resulting  from  adjustments  to  its  tax  basis  balance  sheet.   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  18,  Segment  Information,  of  the  Combined  Notes  to  Consolidated   Financial  Statements.  Certain  prior  year  amounts  have  been  reclassified  to  conform  to  the  current  year  presentation.   During  the  fourth  quarter  of  2015,  management  concluded  that  FEV's  33-­1/3%  equity  investment  in  Global  Holding  was  no  longer  a   strategic  asset  to  CES.  Because  of  this  decision,  the  segment  reporting  was  modified  to  reflect  how  management  now  views  and   makes  investment  decisions  regarding  CES  and  Global  Holding.  The  external  segment  reporting  is  consistent  with  the  internal   financial  reports  used  by  FirstEnergy's  Chief  Executive  Officer  (its  chief  operating  decision  maker)  to  regularly  assess  performance  of   the  business  and  allocate  resources.  Disclosures  for  FirstEnergy's  reportable  operating  segments  for  2014  and  2013  have  been   reclassified  to  conform  to  the  current  presentation  reflecting  the  activity  of  FEV's  investment  in  Global  Holding  in  Corporate/Other.   Net  income  by  business  segment  was  as  follows:   Net  Income  (Loss)  By  Business  Segment:   Regulated  Distribution   Regulated  Transmission   Competitive  Energy  Services   Corporate/Other  (1)   Net  Income   Basic  Earnings  Per  Share:   Continuing  operations   Discontinued  operations  (Note  19)   Earnings  per  basic  share   Diluted  Earnings  Per  Share:   Continuing  operations   Discontinued  operations  (Note  19)   Earnings  per  diluted  share   2015   618   $   298   89   (427  )   578   $   1.37   $   —   1.37   $   1.37   $   —   1.37   $   $   $   $   $   $   $   2014   2015  vs  2014   (In  millions,  except  per  share  amounts)   2013   2014  vs  2013   Increase  (Decrease)   Operating  Income   465   $   223   (331  )   (58  )   299   $   0.51   $   0.20   0.71   $   0.51   $   0.20   0.71   $   501   $   214   (218  )   (105  )   392   $   0.90   $   0.04   0.94   $   0.90   $   0.04   0.94   $   153   $   75   420   (369  )   279   $   0.86   $   (0.20  )   0.66   $   0.86   $   (0.20  )   0.66   $   (36  )   9   (113  )   47   (93  )   (0.39  )   0.16   (0.23  )   (0.39  )   0.16   (0.23  )   (1)  Consists  primarily  of  interest  on  stand-­alone  holding  company  debt,  none-­core  business  related  activity  and  corporate  income  taxes.   12   13   2015  Financial  Results   Revenues:   External   Electric   Other   Internal   Total  Revenues   Operating  Expenses:   Fuel   Purchased  power   Other  operating  expenses   Pension  and  OPEB  mark-­to-­market   Provision  for  depreciation   Amortization  of  regulatory  assets,  net   General  taxes   Impairment  of  long-­lived  assets   Total  Operating  Expenses   Other  Income  (Expense):   Loss  on  debt  redemptions   Investment  income  (loss)   Interest  expense   Capitalized  financing  costs   Total  Other  Expense   Impairment  of  equity  method  investment   Income  From  Continuing  Operations  Before   Income  Taxes   Income  taxes   Income  From  Continuing  Operations   Discontinued  Operations,  net  of  tax   Net  Income   Regulated   Distribution   Regulated   Transmission   Competitive   Energy   Services   Corporate/Other   and  Reconciling   Adjustments   FirstEnergy   Consolidated   (In  millions)   $   9,429   $   196   —   9,625   1,011   $   —   —   1,011   4,493   $   205   686   5,384   (173  )   $   (135  )   (686  )   (994  )   533   3,548   2,242   179   672   261   703   8   8,146   1,479   —   42   —   (586  )   25   (519  )   960   342   618   —   —   —   154   3   156   7   102   —   422   589   —   —   —   (161  )   44   (117  )   472   174   298   —   1,322   1,456   1,670   60   394   —   140   34   5,076   308   —   (16  )   —   (192  )   39   (169  )   139   50   89   —   14,760   266   —   15,026   1,855   4,318   3,749   242   1,282   268   978   42   12,734   2,292   —   (22  )   (362  )   (1,132  )   117   (1,399  )   893   315   578   —   578   —   (686  )   (317  )   —   60   —   33   —   (910  )   (84  )   —   (48  )   (362  )   (193  )   9   (594  )   (678  )   (251  )   (427  )   —   $   618   $   298   $   89   $   (427  )   $                       asset  transfer.  CES'  increase  in  other  operating  expenses  was  primarily  attributable  to  higher  transmission  costs,  which   resulted  from  the  market  conditions  associated  with  the  extreme  weather  events  in  the  first  quarter  of  2014,  and  higher   Summary  of  Results  of  Operations  —  2015  Compared  with  2014     mark-­to-­market  expenses  on  derivative  contracts,  partially  offset  by  lower  generation  operating  and  maintenance  costs   Financial  results  for  FirstEnergy’s  business  segments  in  2015  and  2014  were  as  follows:   primarily  resulting  from  the  deactivation  of  generating  plants  and  the  Harrison/Pleasants  asset  transfer. 2015  Financial  Results   Revenues:   External   Electric   Other   Internal   Total  Revenues   Operating  Expenses:   Fuel   Purchased  power   Other  operating  expenses   Pension  and  OPEB  mark-­to-­market   makes  investment  decisions  regarding  CES  and  Global  Holding.  The  external  segment  reporting  is  consistent  with  the  internal   Provision  for  depreciation   Amortization  of  regulatory  assets,  net   General  taxes   Impairment  of  long-­lived  assets   Total  Operating  Expenses   Increase  (Decrease)   Operating  Income   Other  Income  (Expense):   Loss  on  debt  redemptions   Investment  income  (loss)   Impairment  of  equity  method  investment   Interest  expense   Capitalized  financing  costs   Total  Other  Expense   FirstEnergy’s   other   expenses   decreased   $121   million   year-­over-­year,   primarily   resulting   from   the   absence   of   a   loss   on   debt   redemptions  of  $124  million  recognized  in  2013.  Higher  interest  expense  was  offset  by  higher  investment  income  and  capitalized   financing  costs,  primarily  attributable  to  Regulated  Transmission’s  Energizing  the  Future  investment  plan.   FirstEnergy’s  effective  tax  rate  on  income  from  continuing  operations  was  (24.6)%  compared  to  34.2%  in  2013.  The  decrease  in  the   effective  tax  rate  was  attributable  to  tax  benefits  recognized  in  2014  associated  with  an  IRS-­approved  change  in  accounting  method   for  costs  associated  with  the  refurbishment  of  meters  and  transformers  and  the  expiration  of  the  statute  of  limitations  on  uncertain  tax   positions.  Additionally,  during  2014,  FirstEnergy  recognized  a  reduction  in  income  tax  expense  of  $25  million  that  related  to  prior   periods  resulting  from  adjustments  to  its  tax  basis  balance  sheet.   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  18,  Segment  Information,  of  the  Combined  Notes  to  Consolidated   Financial  Statements.  Certain  prior  year  amounts  have  been  reclassified  to  conform  to  the  current  year  presentation.   During  the  fourth  quarter  of  2015,  management  concluded  that  FEV's  33-­1/3%  equity  investment  in  Global  Holding  was  no  longer  a   strategic  asset  to  CES.  Because  of  this  decision,  the  segment  reporting  was  modified  to  reflect  how  management  now  views  and   financial  reports  used  by  FirstEnergy's  Chief  Executive  Officer  (its  chief  operating  decision  maker)  to  regularly  assess  performance  of   the  business  and  allocate  resources.  Disclosures  for  FirstEnergy's  reportable  operating  segments  for  2014  and  2013  have  been   reclassified  to  conform  to  the  current  presentation  reflecting  the  activity  of  FEV's  investment  in  Global  Holding  in  Corporate/Other.   Net  income  by  business  segment  was  as  follows:   Net  Income  (Loss)  By  Business  Segment:   Regulated  Distribution   Regulated  Transmission   Competitive  Energy  Services   Corporate/Other  (1)   Net  Income   Basic  Earnings  Per  Share:   Continuing  operations   Discontinued  operations  (Note  19)   Earnings  per  basic  share   Diluted  Earnings  Per  Share:   Continuing  operations   Discontinued  operations  (Note  19)   Earnings  per  diluted  share   2015   2014   2013   2015  vs  2014   2014  vs  2013   (In  millions,  except  per  share  amounts)   $   618   $   465   $   501   $   298   89   (427  )   223   (331  )   (58  )   214   (218  )   (105  )   578   $   299   $   392   $   1.37   $   —   1.37   $   1.37   $   —   1.37   $   0.51   $   0.20   0.71   $   0.51   $   0.20   0.71   $   0.90   $   0.04   0.94   $   0.90   $   0.04   0.94   $   $   $   $   $   $   153   $   75   420   (369  )   279   $   0.86   $   (0.20  )   0.66   $   0.86   $   (0.20  )   0.66   $   (36  )   9   (113  )   47   (93  )   (0.39  )   0.16   (0.23  )   (0.39  )   0.16   (0.23  )   (1)  Consists  primarily  of  interest  on  stand-­alone  holding  company  debt,  none-­core  business  related  activity  and  corporate  income  taxes.   Regulated   Distribution   Regulated   Transmission   Competitive   Energy   Services   Corporate/Other   and  Reconciling   Adjustments   FirstEnergy   Consolidated   (In  millions)   $   9,429   $   196   —   9,625   1,011   $   —   —   1,011   4,493   $   205   686   5,384   (173  )   $   (135  )   (686  )   (994  )   533   3,548   2,242   179   672   261   703   8   8,146   1,479   —   42   —   (586  )   25   (519  )   —   —   154   3   156   7   102   —   422   589   —   —   —   (161  )   44   (117  )   1,322   1,456   1,670   60   394   —   140   34   5,076   308   —   (16  )   —   (192  )   39   (169  )   14,760   266   —   15,026   1,855   4,318   3,749   242   1,282   268   978   42   12,734   2,292   —   (22  )   (362  )   (1,132  )   117   (1,399  )   893   315   578   —   578   —   (686  )   (317  )   —   60   —   33   —   (910  )   (84  )   —   (48  )   (362  )   (193  )   9   (594  )   (678  )   (251  )   (427  )   —   (427  )   $   Income  From  Continuing  Operations  Before   Income  Taxes   Income  taxes   Income  From  Continuing  Operations   Discontinued  Operations,  net  of  tax   Net  Income   $   960   342   618   —   618   $   472   174   298   —   298   $   139   50   89   —   89   $   12   13                       2014  Financial  Results   Revenues:   External   Electric   Other   Internal   Total  Revenues   Operating  Expenses:   Fuel   Purchased  power   Other  operating  expenses   Pension  and  OPEB  mark-­to-­market   Provision  for  depreciation   Amortization  of  regulatory  assets,  net   General  taxes   Impairment  of  long-­lived  assets   Total  Operating  Expenses   Operating  Income  (Loss)   Other  Income  (Expense):   Loss  on  debt  redemptions   Investment  income   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)   Changes  Between  2015  and  2014  Financial   Results  Increase  (Decrease)   Regulated   Distribution   Regulated   Transmission   Corporate/Other   and   Reconciling   Adjustments   FirstEnergy   Consolidated   Competitive   Energy   Services   (In  millions)   $   8,898   $   204   —   9,102   769   $   —   —   769   5,281   $   189   819   6,289   (193  )   $   (99  )   (819  )   (1,111  )   567   3,385   2,081   506   658   1   693   —   7,891   1,211   —   56   —   (589  )   14   (519  )   —   —   139   2   127   11   70   —   349   420   —   —   —   (131  )   55   (76  )   1,713   2,150   2,075   327   387   —   171   —   6,823   (534  )   (8  )   54   —   (189  )   37   (106  )   14,755   294   —   15,049   2,280   4,716   3,962   835   1,220   12   962   —   13,987   1,062   (8  )   72   —   (1,073  )   118   (891  )   171   (42  )   213   86   299   Revenues:   External   Electric   Other   Internal   Total  Revenues   Operating  Expenses:   Fuel   Purchased  power   Other  operating  expenses   Pension  and  OPEB  mark-­to-­market   Provision  for  depreciation   Amortization  of  regulatory  assets,  net   General  taxes   Impairment  of  long-­lived  assets   Total  Operating  Expenses   Operating  Income  (Loss)   Other  Income  (Expense):   Loss  on  debt  redemptions   Investment  income   Interest  expense   Capitalized  financing  costs   Total  Other  Expense   Impairment  of  equity  method  investment   Income  (Loss)  From  Continuing  Operations  Before   Income  Taxes  (Benefits)   Income  taxes  (benefits)   Income  (Loss)  From  Continuing  Operations   Discontinued  Operations,  net  of  tax   Net  Income  (Loss)   $   531   $   (8  )   —   523   242   $   —   —   242   (788  )   $   16   (133  )   (905  )   20   $   (36  )   133   117   5   (28  )   —   (23  )   (425  )   (398  )   (213  )   (593  )   62   256   16   42   (1,253  )   1,230   8   (94  )   (362  )   (59  )   (1  )   (508  )   722   357   365   (86  )   279   —   133   16   —   12   —   5   —   166   (49  )   —   (10  )   (362  )   (29  )   (3  )   (404  )   (453  )   (84  )   (369  )   —   (34  )   163   161   (327  )   14   260   10   8   255   268   —   (14  )   —   3   11   —   268   115   153   —   —   —   15   1   29   (4  )   32   —   73   169   —   —   —   (30  )   (11  )   (41  )   128   53   75   —   (391  )   (694  )   (405  )   (267  )   7   —   (31  )   34   (1,747  )   842   8   (70  )   —   (3  )   2   (63  )   779   273   506   (86  )   $   153   $   75   $   420   $   (369  )   $   —   (819  )   (333  )   —   48   —   28   —   (1,076  )   (35  )   —   (38  )   —   (164  )   12   (190  )   (225  )   (167  )   (58  )   —   (58  )   $   Income  (Loss)  From  Continuing  Operations   Before  Income  Taxes  (Benefits)   Income  taxes  (benefits)   Income  (Loss)  From  Continuing  Operations   Discontinued  Operations,  net  of  tax   Net  Income  (Loss)   $   692   227   465   —   465   $   344   121   223   —   223   $   (640  )   (223  )   (417  )   86   (331  )   $   14   15             2014  Financial Results Revenues: External Electric Other Internal Total Revenues Operating  Expenses: Fuel Purchased  power Other operating  expenses Pension  and  OPEB mark-­to-­market Provision  for depreciation Amortization  of regulatory assets, net General taxes Impairment of long-­lived  assets Total Operating  Expenses Operating  Income  (Loss) Other Income  (Expense): Loss on  debt redemptions Investment income Interest expense Capitalized financing  costs Total Other Expense Impairment of equity  method  investment Income  (Loss) From Continuing  Operations   Before  Income  Taxes (Benefits) Income  taxes  (benefits) Income  (Loss) From Continuing  Operations Discontinued  Operations, net of tax $ 8,898 $ 769 $ 5,281 $ (193) $ 14,755 204 — 9,102 567 3,385 2,081 506 658 1 693 — 7,891 1,211 — 56 — 14 (589) (519) 692 227 465 — — — 769 — — 139 2 127 11 70 — 349 420 — — — (131) 55 (76) 344 121 223 — 189 819 6,289 1,713 2,150 2,075 327 387 — 171 — (8) 54 — (189) 37 (106) (640) (223) (417) 86 (99) (819) (1,111) — (819) (333) — 48 — 28 — — (38) — (164) 12 (190) (225) (167) (58) — 294 — 15,049 2,280 4,716 3,962 835 1,220 12 962 — (8) 72 — (1,073) 118 (891) 171 (42) 213 86 299 6,823 (1,076) 13,987 (534) (35) 1,062 Net Income  (Loss) $ 465 $ 223 $ (331) $ (58) $ Regulated   Distribution Regulated   Transmission Competitive Energy   Services Corporate/Other   and  Reconciling   Adjustments FirstEnergy   Consolidated (In millions) Changes  Between  2015  and  2014  Financial   Results  Increase  (Decrease)   Regulated   Distribution   Regulated   Transmission   Corporate/Other   and   Reconciling   Adjustments   FirstEnergy   Consolidated   Competitive   Energy   Services   (In  millions)   Revenues:   External   Electric   Other   Internal   Total  Revenues   Operating  Expenses:   Fuel   Purchased  power   Other  operating  expenses   Pension  and  OPEB  mark-­to-­market   Provision  for  depreciation   Amortization  of  regulatory  assets,  net   General  taxes   Impairment  of  long-­lived  assets   Total  Operating  Expenses   Operating  Income  (Loss)   Other  Income  (Expense):   Loss  on  debt  redemptions   Investment  income   Impairment  of  equity  method  investment   Interest  expense   Capitalized  financing  costs   Total  Other  Expense   $   531   $   (8  )   —   523   242   $   —   —   242   (788  )   $   16   (133  )   (905  )   20   $   (36  )   133   117   (34  )   163   161   (327  )   14   260   10   8   255   268   —   (14  )   —   3   11   —   —   —   15   1   29   (4  )   32   —   73   (391  )   (694  )   (405  )   (267  )   7   —   (31  )   34   (1,747  )   169   842   —   —   —   (30  )   (11  )   (41  )   128   53   75   —   75   $   8   (70  )   —   (3  )   2   (63  )   779   273   506   (86  )   420   $   —   133   16   —   12   —   5   —   166   (49  )   —   (10  )   (362  )   (29  )   (3  )   (404  )   (453  )   (84  )   (369  )   —   (369  )   $   5   (28  )   —   (23  )   (425  )   (398  )   (213  )   (593  )   62   256   16   42   (1,253  )   1,230   8   (94  )   (362  )   (59  )   (1  )   (508  )   722   357   365   (86  )   279   Income  (Loss)  From  Continuing  Operations  Before   Income  Taxes  (Benefits)   Income  taxes  (benefits)   Income  (Loss)  From  Continuing  Operations   Discontinued  Operations,  net  of  tax   Net  Income  (Loss)   $   268   115   153   —   153   $   14 15   Regulated  Distribution  —  2015  Compared  with  2014     The  following  table  summarizes  the  price  and  volume  factors  contributing  to  the  $107  million  increase  in  generation  revenues  in  2015   compared  to  2014:   Regulated  Distribution's  net  income  increased  $153  million  in  2015  compared  to  2014,  including  a  $327  million  decrease  in  its   Pension  and  OPEB  mark-­to-­market  adjustment.  Excluding  the  impact  of  this  adjustment,  year-­over-­year  earnings  were  impacted  by   increased  operating  expenses,  including  higher  reliability  maintenance  expenses,  higher  benefit  costs,  and  higher  depreciation   associated   with   increased   capital   investments,   and   a   higher   effective   tax   rate,   partially   offset   by   a   net   increase   in   new   rates   implemented  in  2015  at  certain  operating  companies.       Revenues  —   The  $523  million  increase  in  total  revenues  resulted  from  the  following  sources:   Revenues  by  Type  of  Service   2015   2014   (Decrease)   For  the  Years  Ended   December  31,   Increase   Distribution  services   Generation  sales:   Retail   Wholesale   Total  generation  sales   Transmission  sales:   Retail   Wholesale   Total  transmission  sales   Other   Total  Revenues   $   3,993   $   3,694   $   299   (In  millions)   4,303   508   4,811   513   112   625   196   9,625   $   4,043   661   4,704   352   148   500   204   9,102   $   260   (153  )   107   161   (36  )   125   (8  )   523   $   Distribution   services   revenues   increased   $299   million   primarily   resulting   from   approved   base   distribution   rate   increases   in   Pennsylvania,  effective  May  3,  2015,  and  for  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   services  revenues  increased  resulting  from  the  Ohio  Companies'  Rider  DCR  and  higher  cost  recovery  for  above  market  NUG  costs   and  certain  energy  efficiency  programs  for  the  Pennsylvania  Companies,  which  was  impacted  by  a  rate  increase  in  2015.  Partially   offsetting  these  items  were  the  impacts  of  lower  residential  and  industrial  customer  usage  as  described  below.  Distribution  deliveries   by  customer  class  are  summarized  in  the  following  table:   conditions  in  2014.   Operating  Expenses  —   For  the  Years  Ended   December  31,   Increase   energy  prices.   Electric  Distribution  MWH  Deliveries   2015   2014   (Decrease)   Residential   Commercial   Industrial   Other   Total  Electric  Distribution  MWH  Deliveries   (In  thousands)   54,466   43,091   50,269   585   148,411   54,766   42,925   51,276   586   149,553   (0.5  )%   0.4   %   (2.0  )%   (0.2  )%   (0.8  )%   Lower  deliveries  to  residential  customers,  reflect  declining  weather-­adjusted  average  customer  usage  due,  in  part,  to  increasing   energy  efficiency  mandates  as  well  as  heating  degree  days  that  were  10.8%  below  the  same  period  in  2014  and  2.8%  below  normal,   partially  offset  by  cooling  degree  days  that  were  32%  above  2014  and  17%  above  normal.  Commercial  sales  increased  year-­over  -­ year  from  the  increase  in  cooling  degree  days,  partially  offset  by  the  lower  heating  degree  days  as  well  as  decreased  weather-­ adjusted  usage  due,  in  part,  to  increasing  energy  efficiency  mandates.  Deliveries  to  industrial  customers  decreased  2%,  as  the   increase  from  shale  and  petroleum  customer  usage  was  more  than  offset  by  a  decrease  from  steel  and  mining  customer  usage.   Source  of  Change  in  Generation  Revenues   Retail:   Change  in  prices   Effect  of  increase  in  sales  volumes   $   Increase   (Decrease)   (In  millions)   Wholesale:   Effect  of  decrease  in  sales  volumes   Change  in  prices   Capacity  revenue   Increase  in  Generation  Revenues   $   146   114   260   (133  )   (75  )   55   (153  )   107   The  increase  in  retail  generation  sales  volume  was  primarily  due  to  lower  customer  shopping  in  Ohio,  Pennsylvania,  and  New  Jersey   and  an  increase  in  weather-­related  usage,  partially  offset  by  the  impacts  of  energy  efficiency  as  described  above.  Total  generation   provided  by  alternative  suppliers  as  a  percentage  of  total  MWH  deliveries  decreased  to  80%  from  81%  for  the  Ohio  Companies,  65%   from  67%  for  the  Pennsylvania  Companies  and  50%  from  52%  for  JCP&L.  The  increase  in  prices  primarily  resulted  from  higher   default  service  auction  results.   Wholesale  generation  revenues  decreased  $153  million  in  2015  compared  to  2014,  primarily  reflecting  decreased  volume  associated   with  the  termination  of  certain  NUG  contracts  at  JCP&L  and  PN  and  lower  economic  dispatch  of  fossil  generating  units  associated   with  low  spot  market  energy  prices.  Partially  offsetting  the  decrease  was  an  increase  in  capacity  revenue  resulting  from  higher   capacity  prices.  The  difference  between  current  wholesale  generation  revenues  and  certain  energy  costs  incurred  are  deferred  for   future  recovery,  with  no  material  impact  on  earnings.   The   increase   in   retail   transmission   revenues   of   $161   million   was   primarily   due   to   an   increase   in   the   Ohio   Companies'   NMB   transmission  rider  revenues.  The  NMB  rider  recovers  network  transmission  integration  service  costs  from  all  distribution  customers  at   the  Ohio  Companies,  with  no  material  impact  to  earnings.  The  decrease  in  wholesale  transmission  revenues  of  $36  million  primarily   relates  to  lower  congestion  revenue  resulting  from  the  impact  of  market  conditions  associated  with  the  extreme  weather  and  market   Total  operating  expenses  increased  $255  million  primarily  due  to  the  following:   •     Fuel  expense  decreased  $34  million  in  2015  primarily  related  to  lower  economic  dispatch  resulting  from  low  spot  market   •     Purchased  power  costs  were  $163  million  higher  in  2015  primarily  due  to  increased  volumes  reflecting  lower  customer   shopping   as   described   above,   higher   unit   costs   related   to   higher   default   service   auction   results,   and   higher   capacity   expense  at  MP,  partially  offset  by  lower  purchases  resulting  from  the  termination  of  certain  NUG  contracts  at  JCP&L  and  PN.     16   17                                     Regulated  Distribution  —  2015  Compared  with  2014     Regulated  Distribution's  net  income  increased  $153  million  in  2015  compared  to  2014,  including  a  $327  million  decrease  in  its   Pension  and  OPEB  mark-­to-­market  adjustment.  Excluding  the  impact  of  this  adjustment,  year-­over-­year  earnings  were  impacted  by   increased  operating  expenses,  including  higher  reliability  maintenance  expenses,  higher  benefit  costs,  and  higher  depreciation   associated   with   increased   capital   investments,   and   a   higher   effective   tax   rate,   partially   offset   by   a   net   increase   in   new   rates   implemented  in  2015  at  certain  operating  companies.       Revenues  —   The  $523  million  increase  in  total  revenues  resulted  from  the  following  sources:   Revenues  by  Type  of  Service   2015   2014   (Decrease)   Distribution  services   Generation  sales:   Retail   Wholesale   Total  generation  sales   Transmission  sales:   Retail   Wholesale   Total  transmission  sales   Other   Total  Revenues   For  the  Years  Ended   December  31,   Increase   $   3,993   $   3,694   $   299   (In  millions)   4,303   508   4,811   513   112   625   196   4,043   661   4,704   352   148   500   204   $   9,625   $   9,102   $   260   (153  )   107   161   (36  )   125   (8  )   523   Distribution   services   revenues   increased   $299   million   primarily   resulting   from   approved   base   distribution   rate   increases   in   Pennsylvania,  effective  May  3,  2015,  and  for  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   services  revenues  increased  resulting  from  the  Ohio  Companies'  Rider  DCR  and  higher  cost  recovery  for  above  market  NUG  costs   and  certain  energy  efficiency  programs  for  the  Pennsylvania  Companies,  which  was  impacted  by  a  rate  increase  in  2015.  Partially   offsetting  these  items  were  the  impacts  of  lower  residential  and  industrial  customer  usage  as  described  below.  Distribution  deliveries   by  customer  class  are  summarized  in  the  following  table:   Electric  Distribution  MWH  Deliveries   2015   2014   (Decrease)   Residential   Commercial   Industrial   Other   Total  Electric  Distribution  MWH  Deliveries   For  the  Years  Ended   December  31,   Increase   (In  thousands)   54,466   43,091   50,269   585   148,411   54,766   42,925   51,276   586   149,553   (0.5  )%   0.4   %   (2.0  )%   (0.2  )%   (0.8  )%   Lower  deliveries  to  residential  customers,  reflect  declining  weather-­adjusted  average  customer  usage  due,  in  part,  to  increasing   energy  efficiency  mandates  as  well  as  heating  degree  days  that  were  10.8%  below  the  same  period  in  2014  and  2.8%  below  normal,   partially  offset  by  cooling  degree  days  that  were  32%  above  2014  and  17%  above  normal.  Commercial  sales  increased  year-­over  -­ year  from  the  increase  in  cooling  degree  days,  partially  offset  by  the  lower  heating  degree  days  as  well  as  decreased  weather-­ adjusted  usage  due,  in  part,  to  increasing  energy  efficiency  mandates.  Deliveries  to  industrial  customers  decreased  2%,  as  the   increase  from  shale  and  petroleum  customer  usage  was  more  than  offset  by  a  decrease  from  steel  and  mining  customer  usage.   The  following  table  summarizes  the  price  and  volume  factors  contributing  to  the  $107  million  increase  in  generation  revenues  in  2015   compared  to  2014:   Source  of  Change  in  Generation  Revenues   Increase   (Decrease)   (In  millions)   Retail:   Effect  of  increase  in  sales  volumes   $   Change  in  prices   Wholesale:   Effect  of  decrease  in  sales  volumes   Change  in  prices   Capacity  revenue   Increase  in  Generation  Revenues   $   146   114   260   (133  )   (75  )   55   (153  )   107   The  increase  in  retail  generation  sales  volume  was  primarily  due  to  lower  customer  shopping  in  Ohio,  Pennsylvania,  and  New  Jersey   and  an  increase  in  weather-­related  usage,  partially  offset  by  the  impacts  of  energy  efficiency  as  described  above.  Total  generation   provided  by  alternative  suppliers  as  a  percentage  of  total  MWH  deliveries  decreased  to  80%  from  81%  for  the  Ohio  Companies,  65%   from  67%  for  the  Pennsylvania  Companies  and  50%  from  52%  for  JCP&L.  The  increase  in  prices  primarily  resulted  from  higher   default  service  auction  results.   Wholesale  generation  revenues  decreased  $153  million  in  2015  compared  to  2014,  primarily  reflecting  decreased  volume  associated   with  the  termination  of  certain  NUG  contracts  at  JCP&L  and  PN  and  lower  economic  dispatch  of  fossil  generating  units  associated   with  low  spot  market  energy  prices.  Partially  offsetting  the  decrease  was  an  increase  in  capacity  revenue  resulting  from  higher   capacity  prices.  The  difference  between  current  wholesale  generation  revenues  and  certain  energy  costs  incurred  are  deferred  for   future  recovery,  with  no  material  impact  on  earnings.   The   increase   in   retail   transmission   revenues   of   $161   million   was   primarily   due   to   an   increase   in   the   Ohio   Companies'   NMB   transmission  rider  revenues.  The  NMB  rider  recovers  network  transmission  integration  service  costs  from  all  distribution  customers  at   the  Ohio  Companies,  with  no  material  impact  to  earnings.  The  decrease  in  wholesale  transmission  revenues  of  $36  million  primarily   relates  to  lower  congestion  revenue  resulting  from  the  impact  of  market  conditions  associated  with  the  extreme  weather  and  market   conditions  in  2014.   Operating  Expenses  —   Total  operating  expenses  increased  $255  million  primarily  due  to  the  following:   •     Fuel  expense  decreased  $34  million  in  2015  primarily  related  to  lower  economic  dispatch  resulting  from  low  spot  market   energy  prices.   •     Purchased  power  costs  were  $163  million  higher  in  2015  primarily  due  to  increased  volumes  reflecting  lower  customer   shopping   as   described   above,   higher   unit   costs   related   to   higher   default   service   auction   results,   and   higher   capacity   expense  at  MP,  partially  offset  by  lower  purchases  resulting  from  the  termination  of  certain  NUG  contracts  at  JCP&L  and  PN.     16   17                                     Source  of  Change  in  Purchased  Power   Increase   (Decrease)   (In  millions)   Purchases  from  non-­affiliates:   Change  due  to  increased  unit  costs   $   Change  due  to  increased  volumes   Purchases  from  affiliates:   Change  due  to  decreased  unit  costs   Change  due  to  decreased  volumes   Capacity  expense   Amortization  of  deferred  costs   Increase  in  Purchased  Power  Costs   $   66   185   251   (21  )   (113  )   (134  )   36   10   163   Other  expense  was  flat  in  2015  as  compared  to  2014,  as  lower  investment  income  was  offset  by  lower  interest  expense  and  higher   Other  Expense  —   capitalized  financing  costs.   Income  Taxes  —   Regulated  Distribution’s  effective  tax  rate  was  35.6%  and  32.8%  for  2015  and  2014,  respectively.  The  increase  in  the  effective  tax   rate  resulted  from  changes  in  state  apportionment  factors  and  realized  tax  benefits  recognized  in  2014.   Regulated  Transmission  —  2015  Compared  with  2014     Net  income  increased  $75  million  in  2015  compared  to  2014.  Higher  Transmission  revenues  associated  with  ATSI's  "forward  looking"   rate  and  higher  rate  base  were  partially  offset  by  higher  interest  expense  and  lower  capitalized  financing  costs.   Revenues  —   Total  revenues  increased  $242  million  principally  at  ATSI  and  TrAIL,  reflecting  recovery  of  incremental  operating  expenses  and  a   higher  rate  base.  Effective  January  1,  2015,  ATSI's  formula  rate  calculation  transitioned  to  a  "forward  looking"  approach,  where   transmission  revenues  are  based  on  actual  costs.     •     Other  operating  expenses  increased  $161  million  primarily  due  to:   Revenues  by  transmission  asset  owner  are  shown  in  the  following  table:   •     Higher  transmission  expenses  of  $73  million  primarily  due  to  an  increase  in  network  transmission  expenses  at  the   Ohio  Companies,  partially  offset  by  lower  congestion  expenses  at  MP.  The  differences  between  current  retail   transmission  revenues  and  transmission  costs  incurred  are  deferred  for  future  recovery,  resulting  in  no  material   impact  on  current  period  earnings.   •     Increased  regulated  generation  operating  and  maintenance  expenses  of  $7  million,  reflecting  higher  planned   outage  expenses  in  2015  compared  to  2014.   •     Higher  retirement  benefit  costs  of  $22  million,  reflecting  higher  net  benefit  costs  before  the  pension  and  OPEB   mark-­to-­market  adjustment  described  below.     •     Higher  distribution  operating  and  maintenance  expenses  of  $54  million,  reflecting  increased  reliability  maintenance   in  New  Jersey  and  the  Pennsylvania  companies  and  other  employee  benefit  costs,  partially  offset  by  lower  storm   restoration  costs.   Revenues  by  Transmission  Asset  Owner   2015   2014   Increase   For  the  Years  Ended   December  31,   (In  millions)   $   446   $   252   13   300   242   $   214   13   300   769   $   204   38   —   —   242   Total  Revenues   $   1,011   $   •     Pension  and  OPEB  mark-­to-­market  adjustment  decreased  $327  million  to  $179  million,  which  was  impacted  by  lower  than   expected  asset  returns,  partially  offset  by  an  increase  in  the  discount  rate  used  to  measure  benefit  obligations.   Total  operating  expenses  increased  $73  million  principally  due  to  higher  operating  and  maintenance  expenses,  depreciation,  and   property  taxes  at  ATSI,  which  are  recovered  through  ATSI's  "forward  looking"  rate.   •     Depreciation  expense  increased  $14  million  due  to  a  higher  asset  base,  partially  offset  by  lower  depreciation  rates  at  JCP&L   effective  with  the  implementation  of  new  rates  from  its  distribution  base  rate  case  as  well  as  lower  depreciation  rates  in   Pennsylvania  based  on  updated  asset  life  studies  approved  by  the  PPUC.   •     Net  regulatory  asset  amortization  increased  $260  million  primarily  due  to:     •     Recovery  of  storm  costs  in  New  Jersey,  Pennsylvania,  and  West  Virginia  effective  with  the  implementation  of  new   rates  as  discussed  above  ($66  million),     •     Higher  energy  efficiency  program  cost  recovery  ($66  million),     Lower  deferral  of  TTS  costs  in  West  Virginia  ($37  million),       •     •     Higher  amortizations  of  above-­market  NUG  costs  in  Pennsylvania  and  New  Jersey  ($36  million),     •     •     Higher  default  generation  service  cost  amortization  ($28  million),  and   •     Recovery  of  Pennsylvania  legacy  meter  costs  ($22  million);;  partially  offset  by   •     Higher  cost  deferral  of  Ohio  network  transmission  expenses  ($33  million).     Lower  deferral  of  West  Virginia  vegetation  management  expenses  ($31  million),   •     General  taxes  increased  $10  million  primarily  due  to  higher  revenue-­related  taxes  in  Pennsylvania,  partially  offset  by  lower   related  to  coal  and  transportation  contracts,  and  the  absence  of  a  $78  million  after-­tax  gain  on  the  sale  of  certain  hydroelectric   property  taxes  in  Ohio.     ATSI   TrAIL   PATH   Utilities   Operating  Expenses  —   Other  Expenses  —   Income  Taxes  —   Other  expenses  increased  $41  million  due  to  increased  interest  expense  resulting  from  debt  issuances  of  $1.0  billion  at  FET  and   $400  million  at  ATSI,  the  proceeds  of  which,  in  part,  paid  off  short  term  borrowings  as  well  as  lower  capitalized  financing  costs.   Regulated  Transmission’s  effective  tax  rate  was  36.9%  and  35.2%  for  2015  and  2014,  respectively.  The  increase  in  the  effective  tax   rate  resulted  from  changes  in  state  apportionment  factors  and  realized  tax  benefits  recognized  in  2014.   CES  —  2015  Compared  with  2014     Operating  results  increased  $420  million  in  2015  compared  to  2014,  primarily  from  higher  capacity  revenues  and  the  absence  of  the   impact  of  the  high  market  prices  associated  with  extreme  weather  events  and  unplanned  outages  in  2014  that  resulted  in  higher   purchased  power  and  transmission  costs,  partially  offset  by  lower  contract  sales  volumes.  Additionally,  changes  in  year-­over-­year   operating  results  were  impacted  by  lower  Pension  and  OPEB  mark-­to-­market  adjustments,  lower  settlement  and  termination  costs   facilities  recognized  in  February  2014.   Revenues  —   Total  revenues  decreased  $905  million  in  2015,  compared  to  2014,  primarily  due  to  decreased  sales  volumes  in  line  with  CES'   strategy  to  more  effectively  hedge  its  generation.  Revenues  were  also  impacted  by  higher  unit  prices  compared  to  2014  as  a  result  of   increased  channel  pricing  as  well  as  higher  capacity  revenues,  as  further  described  below.   18   19                                                                         Source  of  Change  in  Purchased  Power   Purchases  from  non-­affiliates:   Change  due  to  increased  unit  costs   $   Change  due  to  increased  volumes   Increase   (Decrease)   (In  millions)   Purchases  from  affiliates:   Change  due  to  decreased  unit  costs   Change  due  to  decreased  volumes   Capacity  expense   Amortization  of  deferred  costs   Increase  in  Purchased  Power  Costs   $   66   185   251   (21  )   (113  )   (134  )   36   10   163   Other  Expense  —   Other  expense  was  flat  in  2015  as  compared  to  2014,  as  lower  investment  income  was  offset  by  lower  interest  expense  and  higher   capitalized  financing  costs.   Income  Taxes  —   Regulated  Distribution’s  effective  tax  rate  was  35.6%  and  32.8%  for  2015  and  2014,  respectively.  The  increase  in  the  effective  tax   rate  resulted  from  changes  in  state  apportionment  factors  and  realized  tax  benefits  recognized  in  2014.   Regulated  Transmission  —  2015  Compared  with  2014     Net  income  increased  $75  million  in  2015  compared  to  2014.  Higher  Transmission  revenues  associated  with  ATSI's  "forward  looking"   rate  and  higher  rate  base  were  partially  offset  by  higher  interest  expense  and  lower  capitalized  financing  costs.   Revenues  —   Total  revenues  increased  $242  million  principally  at  ATSI  and  TrAIL,  reflecting  recovery  of  incremental  operating  expenses  and  a   higher  rate  base.  Effective  January  1,  2015,  ATSI's  formula  rate  calculation  transitioned  to  a  "forward  looking"  approach,  where   transmission  revenues  are  based  on  actual  costs.     •     Other  operating  expenses  increased  $161  million  primarily  due  to:   Revenues  by  transmission  asset  owner  are  shown  in  the  following  table:   •     Higher  transmission  expenses  of  $73  million  primarily  due  to  an  increase  in  network  transmission  expenses  at  the   Ohio  Companies,  partially  offset  by  lower  congestion  expenses  at  MP.  The  differences  between  current  retail   transmission  revenues  and  transmission  costs  incurred  are  deferred  for  future  recovery,  resulting  in  no  material   impact  on  current  period  earnings.   •     Increased  regulated  generation  operating  and  maintenance  expenses  of  $7  million,  reflecting  higher  planned   outage  expenses  in  2015  compared  to  2014.   •     Higher  retirement  benefit  costs  of  $22  million,  reflecting  higher  net  benefit  costs  before  the  pension  and  OPEB   mark-­to-­market  adjustment  described  below.     •     Higher  distribution  operating  and  maintenance  expenses  of  $54  million,  reflecting  increased  reliability  maintenance   in  New  Jersey  and  the  Pennsylvania  companies  and  other  employee  benefit  costs,  partially  offset  by  lower  storm   restoration  costs.   Revenues  by  Transmission  Asset  Owner   2015   2014   Increase   For  the  Years  Ended   December  31,   ATSI   TrAIL   PATH   Utilities   Total  Revenues   Operating  Expenses  —   (In  millions)   $   $   446   $   252   13   300   1,011   $   242   $   214   13   300   769   $   204   38   —   —   242   •     Pension  and  OPEB  mark-­to-­market  adjustment  decreased  $327  million  to  $179  million,  which  was  impacted  by  lower  than   expected  asset  returns,  partially  offset  by  an  increase  in  the  discount  rate  used  to  measure  benefit  obligations.   Total  operating  expenses  increased  $73  million  principally  due  to  higher  operating  and  maintenance  expenses,  depreciation,  and   property  taxes  at  ATSI,  which  are  recovered  through  ATSI's  "forward  looking"  rate.   •     Depreciation  expense  increased  $14  million  due  to  a  higher  asset  base,  partially  offset  by  lower  depreciation  rates  at  JCP&L   effective  with  the  implementation  of  new  rates  from  its  distribution  base  rate  case  as  well  as  lower  depreciation  rates  in   Other  Expenses  —   Pennsylvania  based  on  updated  asset  life  studies  approved  by  the  PPUC.   •     Net  regulatory  asset  amortization  increased  $260  million  primarily  due  to:     Other  expenses  increased  $41  million  due  to  increased  interest  expense  resulting  from  debt  issuances  of  $1.0  billion  at  FET  and   $400  million  at  ATSI,  the  proceeds  of  which,  in  part,  paid  off  short  term  borrowings  as  well  as  lower  capitalized  financing  costs.   •     Recovery  of  storm  costs  in  New  Jersey,  Pennsylvania,  and  West  Virginia  effective  with  the  implementation  of  new   Income  Taxes  —   Regulated  Transmission’s  effective  tax  rate  was  36.9%  and  35.2%  for  2015  and  2014,  respectively.  The  increase  in  the  effective  tax   rate  resulted  from  changes  in  state  apportionment  factors  and  realized  tax  benefits  recognized  in  2014.   •     Higher  amortizations  of  above-­market  NUG  costs  in  Pennsylvania  and  New  Jersey  ($36  million),     CES  —  2015  Compared  with  2014     Operating  results  increased  $420  million  in  2015  compared  to  2014,  primarily  from  higher  capacity  revenues  and  the  absence  of  the   impact  of  the  high  market  prices  associated  with  extreme  weather  events  and  unplanned  outages  in  2014  that  resulted  in  higher   purchased  power  and  transmission  costs,  partially  offset  by  lower  contract  sales  volumes.  Additionally,  changes  in  year-­over-­year   operating  results  were  impacted  by  lower  Pension  and  OPEB  mark-­to-­market  adjustments,  lower  settlement  and  termination  costs   related  to  coal  and  transportation  contracts,  and  the  absence  of  a  $78  million  after-­tax  gain  on  the  sale  of  certain  hydroelectric   facilities  recognized  in  February  2014.   Revenues  —   Total  revenues  decreased  $905  million  in  2015,  compared  to  2014,  primarily  due  to  decreased  sales  volumes  in  line  with  CES'   strategy  to  more  effectively  hedge  its  generation.  Revenues  were  also  impacted  by  higher  unit  prices  compared  to  2014  as  a  result  of   increased  channel  pricing  as  well  as  higher  capacity  revenues,  as  further  described  below.   18   19   rates  as  discussed  above  ($66  million),     •     Higher  energy  efficiency  program  cost  recovery  ($66  million),     •     Lower  deferral  of  TTS  costs  in  West  Virginia  ($37  million),       •     Lower  deferral  of  West  Virginia  vegetation  management  expenses  ($31  million),   •     Higher  default  generation  service  cost  amortization  ($28  million),  and   •     Recovery  of  Pennsylvania  legacy  meter  costs  ($22  million);;  partially  offset  by   •     Higher  cost  deferral  of  Ohio  network  transmission  expenses  ($33  million).     •     General  taxes  increased  $10  million  primarily  due  to  higher  revenue-­related  taxes  in  Pennsylvania,  partially  offset  by  lower   property  taxes  in  Ohio.                                                                             The  decrease  in  total  revenues  resulted  from  the  following  sources:   from  lower  year-­over-­year  market  prices.  The  Direct,  Governmental  Aggregation  and  Mass  Market  customer  base  was  1.6  million  as   Revenues  by  Type  of  Service   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   For  the  Years  Ended   December  31,   2015   2014   (In  millions)   Increase   (Decrease)   1,269   $   1,012   265   712   558   3,816   1,225   138   205   5,384   $   2,359   $   1,184   452   902   522   5,419   461   220   189   6,289   $   (1,090  )   (172  )   (187  )   (190  )   36   (1,603  )   764   (82  )   16   (905  )   For  the  Years  Ended   December  31,   2015   2014   (In  thousands)   Increase   (Decrease)   23,585   15,443   3,878   11,950   12,902   67,758   7,326   75,084   44,012   19,569   6,773   15,708   12,814   98,876   680   99,556   (46.4  )%   (21.1  )%   (42.7  )%   (23.9  )%   0.7   %   (31.5  )%   977.4   %   (24.6  )%   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   Gain  on   Settled   Contracts   (In  millions)   Capacity   Revenue   Total   of  December  31,  2015,  compared  to  2.1  million  as  of  December  31,  2014.   The  decrease  in  POLR  sales  of  $190  million  was  due  to  lower  volumes,  partially  offset  by  higher  rates  associated  with  recent  POLR   auctions.  Structured  Sales  increased  $36  million  due  to  low  market  prices  that  increased  the  gains  on  various  structured  financial   sales  contracts  and  higher  structured  transaction  volumes.   Wholesale  revenues  increased  $764  million  primarily  due  to  an  increase  in  capacity  revenue  from  higher  capacity  prices,  increase  in   short-­term  (net  hourly  position)  transactions,  and  higher  net  gains  on  financially  settled  contracts,  partially  offset  by  lower  spot  market   energy  prices  which  limited  additional  wholesale  sales.   Transmission   revenue   decreased   $82   million   primarily   due   to   lower   congestion   revenue   resulting   from   the   market   conditions   associated  with  the  extreme  weather  events  in  2014.   Other  revenue  increased  $16  million  primarily  due  to  higher  lease  revenues  from  additional  equity  interests  in  affiliated  sale  and   leasebacks  repurchased  in  November  2014.  CES  earns  lease  revenue  associated  with  the  equity  interests  it  purchased.   Operating  Expenses  —   Total  operating  expenses  decreased  $1,747  million  in  2015  due  to  the  following:   •     Fuel  costs  decreased  $391  million  primarily  due  to  lower  economic  dispatch  of  fossil  units  resulting  from  low  spot  market   energy  prices  and  lower  nuclear  unit  prices,  resulting  from  the  suspension  of  the  DOE  nuclear  disposal  fee,  effective  May   16,  2014.  Additionally,  fuel  costs  were  impacted  by  a  decrease  in  settlement  and  termination  costs  related  to  coal  and   transportation  contracts.  The  impact  of  terminations  and  settlements  of  coal  and  transportation  contracts  resulted  in  a  pre-­ tax  loss  of  $67  million  and  $166  million  in  2015  and  2014,  respectively.     •     Purchased  power  costs  decreased  $694  million  due  to  lower  volumes  ($888  million),  partially  offset  by  higher  unit  prices   ($39   million)   and   higher   capacity   expenses   ($155   million).   Lower   volumes   were   primarily   due   to   decreased   load   requirements  resulting  from  lower  sales  as  discussed  above,  partially  offset  by  lower  fossil  generation  as  discussed  above.   The  higher  unit  prices  are  primarily  due  to  higher  losses  on  financially  settled  contracts,  partially  offset  by  lower  market   prices  in  2015  as  compared  to  2014.  The  increase  in  capacity  expense,  which  is  a  component  of  CES'  retail  price,  was   primarily  the  result  of  higher  capacity  rates  associated  with  CES'  retail  sales  obligations.     •     Nuclear  operating  costs  increased  $84  million  as  a  result  of  higher  planned  outage  costs  and  higher  employee  benefit   expenses.  There  were  three  planned  refueling  outages  in  2015  as  compared  to  two  planned  outages  in  2014.     •     Transmission  expenses  decreased  $273  million  primarily  due  to  lower  operating  reserve  and  market-­based  ancillary  costs   associated  with  market  conditions  resulting  from  the  extreme  weather  events  in  2014.   •     General  taxes  decreased  $31  million  primarily  due  to  lower  gross  receipts  taxes  associated  with  decreased  retail  sales   volumes.   •     Pension  and  OPEB  mark-­to-­market  adjustment  decreased  $267  million  to  $60  million,  which  was  impacted  by  lower  than   expected  asset  returns,  partially  offset  by  an  increase  in  the  discount  rate  used  to  measure  benefit  obligations.   •     Other  operating  expenses  decreased  $212  million  primarily  due  to  a  $141  million  decrease  in  mark-­to-­market  expenses  on   commodity  contract  positions  reflecting  lower  market  prices  and  a  $71  million  decrease  in  retail-­related  costs.   •     Impairments  of  long-­lived  assets  increased  $34  million  due  to  impairment  charges  associated  with  non-­core  assets.     Total  other  expense  increased  $63  million  in  2015  compared  to  2014  primarily  due  to  higher  OTTI  on  NDT  investments,  partially  offset   by  the  absence  of  an  $8  million  loss  on  debt  redemptions  incurred  in  2014.   There  were  no  discontinued  operations  in  2015.  In  2014,  discontinued  operations  primarily  included  a  pre-­tax  gain  of  approximately   $142  million  ($78  million  after-­tax)  associated  with  the  sale  of  certain  hydroelectric  assets  on  February  12,  2014.   Other  Expense  —   Discontinued  Operations  —   Income  Taxes  (Benefits)  —   Direct   $   (1,095  )   $   Governmental  Aggregation   Mass  Market   POLR   Structured  Sales   Wholesale   (249  )   (193  )   (216  )   3   197   5   $   77   6   26   33   (8  )   —   $   —   —   —   —   107   —   $  (1,090  )   —   (172  )   —   —   —   468   (190  )   36   764   (187  )   Lower  sales  volumes  in  the  Direct,  Governmental  Aggregation  and  Mass  Market  sales  channels  primarily  reflect  CES'  efforts  to  more   effectively  hedge  its  generation  by  reducing  exposure  to  weather-­sensitive  load.  Although  unit  pricing  was  higher  year-­over-­year  in   the  Direct,  Governmental  Aggregation,  and  Mass  Market  channels,  the  increase  was  primarily  attributable  to  higher  capacity  expense   as  discussed  below,  which  is  a  component  of  the  retail  price,  partially  offset  by  a  lower  energy  component  of  the  retail  price  resulting   CES'  effective  tax  rate  was  36.0%  and  34.8%  for  2015  and  2014,  respectively.  The  increase  in  the  effective  tax  rate  resulted  from   changes  in  state  apportionment  factors  and  realized  tax  benefits  recognized  in  2014.   20   21                                                 The  decrease  in  total  revenues  resulted  from  the  following  sources:   Revenues  by  Type  of  Service   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   For  the  Years  Ended   December  31,   2015   2014   (In  millions)   Increase   (Decrease)   $   1,269   $   1,012   2,359   $   1,184   265   712   558   3,816   1,225   138   205   452   902   522   5,419   461   220   189   $   5,384   $   6,289   $   (1,090  )   (1,603  )   (172  )   (187  )   (190  )   36   764   (82  )   16   (905  )   For  the  Years  Ended   December  31,   2015   2014   (In  thousands)   Increase   (Decrease)   23,585   15,443   3,878   11,950   12,902   67,758   7,326   75,084   44,012   19,569   6,773   15,708   12,814   98,876   680   99,556   (46.4  )%   (21.1  )%   (42.7  )%   (23.9  )%   0.7   %   (31.5  )%   977.4   %   (24.6  )%   The  following  tables  summarize  the  price  and  volume  factors  contributing  to  changes  in  revenues:   Source  of  Change  in  Revenues   Increase  (Decrease)   Gain  on   Settled   Contracts   (In  millions)   MWH  Sales  Channel:    Sales   Volumes   Prices   Capacity   Revenue   Total   Direct   Governmental  Aggregation   Mass  Market   POLR   Structured  Sales   Wholesale   $   (1,095  )   $   5   $   —   $   —   $  (1,090  )   (249  )   (193  )   (216  )   3   197   77   6   26   33   (8  )   —   —   —   —   107   —   —   —   —   468   (172  )   (187  )   (190  )   36   764   Lower  sales  volumes  in  the  Direct,  Governmental  Aggregation  and  Mass  Market  sales  channels  primarily  reflect  CES'  efforts  to  more   effectively  hedge  its  generation  by  reducing  exposure  to  weather-­sensitive  load.  Although  unit  pricing  was  higher  year-­over-­year  in   the  Direct,  Governmental  Aggregation,  and  Mass  Market  channels,  the  increase  was  primarily  attributable  to  higher  capacity  expense   as  discussed  below,  which  is  a  component  of  the  retail  price,  partially  offset  by  a  lower  energy  component  of  the  retail  price  resulting   from  lower  year-­over-­year  market  prices.  The  Direct,  Governmental  Aggregation  and  Mass  Market  customer  base  was  1.6  million  as   of  December  31,  2015,  compared  to  2.1  million  as  of  December  31,  2014.   The  decrease  in  POLR  sales  of  $190  million  was  due  to  lower  volumes,  partially  offset  by  higher  rates  associated  with  recent  POLR   auctions.  Structured  Sales  increased  $36  million  due  to  low  market  prices  that  increased  the  gains  on  various  structured  financial   sales  contracts  and  higher  structured  transaction  volumes.   Wholesale  revenues  increased  $764  million  primarily  due  to  an  increase  in  capacity  revenue  from  higher  capacity  prices,  increase  in   short-­term  (net  hourly  position)  transactions,  and  higher  net  gains  on  financially  settled  contracts,  partially  offset  by  lower  spot  market   energy  prices  which  limited  additional  wholesale  sales.   Transmission   revenue   decreased   $82   million   primarily   due   to   lower   congestion   revenue   resulting   from   the   market   conditions   associated  with  the  extreme  weather  events  in  2014.   Other  revenue  increased  $16  million  primarily  due  to  higher  lease  revenues  from  additional  equity  interests  in  affiliated  sale  and   leasebacks  repurchased  in  November  2014.  CES  earns  lease  revenue  associated  with  the  equity  interests  it  purchased.   Operating  Expenses  —   Total  operating  expenses  decreased  $1,747  million  in  2015  due  to  the  following:   •     Fuel  costs  decreased  $391  million  primarily  due  to  lower  economic  dispatch  of  fossil  units  resulting  from  low  spot  market   energy  prices  and  lower  nuclear  unit  prices,  resulting  from  the  suspension  of  the  DOE  nuclear  disposal  fee,  effective  May   16,  2014.  Additionally,  fuel  costs  were  impacted  by  a  decrease  in  settlement  and  termination  costs  related  to  coal  and   transportation  contracts.  The  impact  of  terminations  and  settlements  of  coal  and  transportation  contracts  resulted  in  a  pre-­ tax  loss  of  $67  million  and  $166  million  in  2015  and  2014,  respectively.     •     Purchased  power  costs  decreased  $694  million  due  to  lower  volumes  ($888  million),  partially  offset  by  higher  unit  prices   ($39   million)   and   higher   capacity   expenses   ($155   million).   Lower   volumes   were   primarily   due   to   decreased   load   requirements  resulting  from  lower  sales  as  discussed  above,  partially  offset  by  lower  fossil  generation  as  discussed  above.   The  higher  unit  prices  are  primarily  due  to  higher  losses  on  financially  settled  contracts,  partially  offset  by  lower  market   prices  in  2015  as  compared  to  2014.  The  increase  in  capacity  expense,  which  is  a  component  of  CES'  retail  price,  was   primarily  the  result  of  higher  capacity  rates  associated  with  CES'  retail  sales  obligations.     •     Nuclear  operating  costs  increased  $84  million  as  a  result  of  higher  planned  outage  costs  and  higher  employee  benefit   expenses.  There  were  three  planned  refueling  outages  in  2015  as  compared  to  two  planned  outages  in  2014.     •     Transmission  expenses  decreased  $273  million  primarily  due  to  lower  operating  reserve  and  market-­based  ancillary  costs   associated  with  market  conditions  resulting  from  the  extreme  weather  events  in  2014.   •     General  taxes  decreased  $31  million  primarily  due  to  lower  gross  receipts  taxes  associated  with  decreased  retail  sales   volumes.   •     Pension  and  OPEB  mark-­to-­market  adjustment  decreased  $267  million  to  $60  million,  which  was  impacted  by  lower  than   expected  asset  returns,  partially  offset  by  an  increase  in  the  discount  rate  used  to  measure  benefit  obligations.   •     Other  operating  expenses  decreased  $212  million  primarily  due  to  a  $141  million  decrease  in  mark-­to-­market  expenses  on   commodity  contract  positions  reflecting  lower  market  prices  and  a  $71  million  decrease  in  retail-­related  costs.   •     Impairments  of  long-­lived  assets  increased  $34  million  due  to  impairment  charges  associated  with  non-­core  assets.     Other  Expense  —   Total  other  expense  increased  $63  million  in  2015  compared  to  2014  primarily  due  to  higher  OTTI  on  NDT  investments,  partially  offset   by  the  absence  of  an  $8  million  loss  on  debt  redemptions  incurred  in  2014.   Discontinued  Operations  —   There  were  no  discontinued  operations  in  2015.  In  2014,  discontinued  operations  primarily  included  a  pre-­tax  gain  of  approximately   $142  million  ($78  million  after-­tax)  associated  with  the  sale  of  certain  hydroelectric  assets  on  February  12,  2014.   Income  Taxes  (Benefits)  —   CES'  effective  tax  rate  was  36.0%  and  34.8%  for  2015  and  2014,  respectively.  The  increase  in  the  effective  tax  rate  resulted  from   changes  in  state  apportionment  factors  and  realized  tax  benefits  recognized  in  2014.   20   21                                               Corporate/Other  —  2015  Compared  with  2014   Financial  results  from  Corporate/Other  resulted  in  a  $369  million  decrease  in  net  income  in  2015  compared  to  2014  primarily  due  to  a   $362   million   pre-­tax   impairment   of   FirstEnergy's   equity   method   investment   in   Global   Holding,   higher   costs   associated   with   environmental  remediation  at  legacy  plants,  higher  interest  expense  and  a  higher  effective  tax  rate.  During  2015,  based  on  the   significant   decline   in   coal   pricing   and   the   current   outlook   for   the   coal   market,   FirstEnergy   assessed   the   carrying   value   of   its   investment  in  Global  Holding  and  determined  there  was  an  other  than  temporary  decline  in  the  fair  value  below  its  carrying  value,   which  resulted  in  the  impairment  charge.  The  increased  interest  expense  primarily  relates  to  a  $1  billion  term  loan  entered  into  in   March  2014  and  a  gain  on  the  termination  of  interest  rate  swap  arrangements  recognized  in  2014.  The  higher  effective  tax  rate   primarily  resulted  from  the  absence  of  tax  benefits  recognized  in  2014  associated  with  an  IRS-­approved  change  in  accounting   method  that  increased  the  tax  basis  in  certain  assets  resulting  in  higher  future  tax  deductions,  a  reduction  in  state  deferred  tax   liabilities   resulting   from   changes   in   state   apportionment   factors,   the   elimination   of   certain   tax   liabilities   associated   with   basis   differences  as  well  as  certain  tax  benefits  recorded  in  2014  that  related  to  prior  periods.     Summary  of Results  of Operations  — 2014  Compared  with  2013   Financial results for FirstEnergy’s business segments in  2014  and  2013  were as follows: 2014  Financial Results Revenues: External Electric Other Internal Total Revenues Operating  Expenses: Fuel Purchased  power Other operating  expenses Pension  and  OPEB mark-­to-­market Provision  for depreciation Amortization  of regulatory assets, net General taxes Impairment of long-­lived  assets Total Operating  Expenses Operating  Income  (loss) Other Income  (Expense): Loss on  debt redemptions Investment income Interest expense Capitalized interest Total Other Expense Income  (Loss) From Continuing  Operations   Before  Income  Taxes (Benefits) Income  taxes  (benefits) Income  (Loss) From Continuing  Operations Discontinued  Operations, net of tax Regulated   Distribution Regulated   Transmission Competitive Energy   Services Corporate/Other   and  Reconciling   Adjustments FirstEnergy   Consolidated (In millions) $ 8,898 $ 769 $ 5,281 $ (193) $ 14,755 204 — 9,102 567 3,385 2,081 506 658 1 693 — 7,891 1,211 — 56 14 (589) (519) 692 227 465 — — — 769 — — 139 2 127 11 70 — 349 420 — — (131) 55 (76) 344 121 223 — 189 819 6,289 1,713 2,150 2,075 327 387 — 171 — (8) 54 (189) 37 (106) (640) (223) (417) 86 (99) (819) (1,111) — (819) (333) — 48 — 28 — — (38) (164) 12 (190) (225) (167) (58) — 294 — 15,049 2,280 4,716 3,962 835 1,220 12 962 — (8) 72 (1,073) 118 (891) 171 (42) 213 86 299 6,823 (1,076) 13,987 (534) (35) 1,062 Net Income  (Loss) $ 465 $ 223 $ (331) $ (58) $ 22   23 Corporate/Other — 2015  Compared  with  2014   Financial results from Corporate/Other resulted  in  a  $369  million  decrease  in  net income  in  2015  compared  to  2014  primarily due  to  a   $362   million   pre-­tax   impairment of FirstEnergy's   equity   method investment in Global Holding, higher costs   associated with environmental remediation  at legacy plants, higher interest expense  and  a  higher effective  tax rate. During  2015, based  on  the significant decline   in   coal pricing   and   the   current outlook for the   coal market, FirstEnergy assessed   the   carrying   value   of its investment in  Global Holding  and  determined  there  was an  other than  temporary decline  in  the  fair value  below its carrying  value,   which  resulted  in  the  impairment charge. The  increased  interest expense  primarily relates to  a  $1  billion  term loan  entered  into in March  2014  and  a  gain  on  the  termination  of interest rate  swap  arrangements recognized  in  2014. The  higher effective  tax rate primarily resulted  from the  absence  of tax benefits recognized  in  2014  associated  with  an  IRS-­approved  change  in  accounting   method that increased the tax  basis  in certain assets  resulting in higher future tax deductions, a reduction in state deferred tax   liabilities resulting   from changes in   state   apportionment factors, the   elimination   of certain   tax liabilities associated   with basis   differences as well as certain  tax benefits recorded  in  2014  that related  to  prior periods. Summary  of  Results  of  Operations  —  2014  Compared  with  2013     Financial  results  for  FirstEnergy’s  business  segments  in  2014  and  2013  were  as  follows:   2014  Financial  Results   Revenues:   External   Electric   Other   Internal   Total  Revenues   Operating  Expenses:   Fuel   Purchased  power   Other  operating  expenses   Pension  and  OPEB  mark-­to-­market   Provision  for  depreciation   Amortization  of  regulatory  assets,  net   General  taxes   Impairment  of  long-­lived  assets   Total  Operating  Expenses   Operating  Income  (loss)   Other  Income  (Expense):   Loss  on  debt  redemptions   Investment  income   Interest  expense   Capitalized  interest   Total  Other  Expense   Regulated   Distribution   Regulated   Transmission   Competitive   Energy   Services   Corporate/Other   and  Reconciling   Adjustments   FirstEnergy   Consolidated   (In  millions)   $   8,898   $   204   —   9,102   769   $   —   —   769   5,281   $   189   819   6,289   (193  )   $   (99  )   (819  )   (1,111  )   567   3,385   2,081   506   658   1   693   —   7,891   1,211   —   56   (589  )   14   (519  )   —   —   139   2   127   11   70   —   349   420   —   —   (131  )   55   (76  )   344   121   223   —   223   $   1,713   2,150   2,075   327   387   —   171   —   6,823   (534  )   (8  )   54   (189  )   37   (106  )   —   (819  )   (333  )   —   48   —   28   —   (1,076  )   (35  )   —   (38  )   (164  )   12   (190  )   (640  )   (223  )   (417  )   86   (331  )   $   (225  )   (167  )   (58  )   —   (58  )   $   14,755   294   —   15,049   2,280   4,716   3,962   835   1,220   12   962   —   13,987   1,062   (8  )   72   (1,073  )   118   (891  )   171   (42  )   213   86   299   Income  (Loss)  From  Continuing  Operations   Before  Income  Taxes  (Benefits)   Income  taxes  (benefits)   Income  (Loss)  From  Continuing  Operations   Discontinued  Operations,  net  of  tax   Net  Income  (Loss)   $   692   227   465   —   465   $   22 23   2013  Financial  Results   Revenues:   External   Electric   Other   Internal   Total  Revenues   Operating  Expenses:   Fuel   Purchased  power   Other  operating  expenses   Pension  and  OPEB  mark-­to-­market   Provision  for  depreciation   Amortization  of  regulatory  assets,  net   General  taxes   Impairment  of  long-­lived  assets   Total  Operating  Expenses   Operating  Income  (Loss)   Other  Income  (Expense):   Gain  (loss)  on  debt  redemptions   Investment  income   Interest  expense   Capitalized  interest   Total  Other  Expense   Regulated   Distribution   Regulated   Transmission   Competitive   Energy   Services   Corporate/Other     and  Reconciling   Adjustments   FirstEnergy   Consolidated   (In  millions)   $   8,499   $   221   —   8,720   731   $   —   —   731   5,542   $   186   770   6,498   (161  )   $   (126  )   (770  )   (1,057  )   377   3,308   1,773   (149  )   606   529   697   322   7,463   1,257   —   57   (543  )   31   (455  )   —   —   131   —   114   10   54   —   309   422   —   —   (93  )   14   (79  )   2,119   1,425   2,007   (107  )   439   —   202   473   6,558   (60  )   (149  )   14   (222  )   42   (315  )   14,611   281   —   14,892   2,496   3,963   3,593   (256  )   1,202   539   978   795   13,310   1,582   (132  )   33   (1,016  )   103   (1,012  )   570   195   375   17   392   —   (770  )   (318  )   —   43   —   25   —   (1,020  )   (37  )   17   (38  )   (158  )   16   (163  )   (200  )   (95  )   (105  )   —   (105  )   $   Income  (Loss)  From  Continuing  Operations   Before  Income  Taxes  (Benefits)   Income  taxes  (benefits)   Income  From  Continuing  Operations   Discontinued  Operations,  net  of  tax   Net  Income  (Loss)   $   802   301   501   —   501   $   343   129   214   —   214   $   (375  )   (140  )   (235  )   17   (218  )   $   24       2013  Financial  Results   Revenues:   External   Electric   Other   Internal   Total  Revenues   Operating  Expenses:   Fuel   Purchased  power   Other  operating  expenses   Pension  and  OPEB  mark-­to-­market   Provision  for  depreciation   Amortization  of  regulatory  assets,  net   General  taxes   Impairment  of  long-­lived  assets   Total  Operating  Expenses   Operating  Income  (Loss)   Other  Income  (Expense):   Gain  (loss)  on  debt  redemptions   Investment  income   Interest  expense   Capitalized  interest   Total  Other  Expense   Income  (Loss)  From  Continuing  Operations   Before  Income  Taxes  (Benefits)   Income  taxes  (benefits)   Income  From  Continuing  Operations   Discontinued  Operations,  net  of  tax   Net  Income  (Loss)   $   8,499   $   221   —   8,720   731   $   —   —   731   5,542   $   186   770   6,498   (161  )   $   (126  )   (770  )   (1,057  )   377   3,308   1,773   (149  )   606   529   697   322   7,463   1,257   —   57   (543  )   31   (455  )   802   301   501   —   —   —   131   —   114   10   54   —   309   422   —   —   (93  )   14   (79  )   343   129   214   —   2,119   1,425   2,007   (107  )   439   —   202   473   6,558   (60  )   (149  )   14   (222  )   42   (315  )   (375  )   (140  )   (235  )   17   —   (770  )   (318  )   —   43   —   25   —   (1,020  )   (37  )   17   (38  )   (158  )   16   (163  )   (200  )   (95  )   (105  )   —   14,611   281   —   14,892   2,496   3,963   3,593   (256  )   1,202   539   978   795   13,310   1,582   (132  )   33   (1,016  )   103   (1,012  )   570   195   375   17   392   Regulated   Distribution   Regulated   Transmission   Competitive   Energy   Services   Corporate/Other     and  Reconciling   Adjustments   FirstEnergy   Consolidated   Changes  Between  2014  and  2013  Financial  Results   Increase  (Decrease)   Changes  Between  2014  and  2013  Financial  Results   Increase  (Decrease)   Regulated   Distribution   Regulated   Distribution   Regulated   Regulated   Transmission   Transmission   Competitive   Competitive   Energy   Energy   Services   Services   Corporate/Other   Corporate/Other   and  Reconciling   and  Reconciling   Adjustments   Adjustments   FirstEnergy   Consolidated   FirstEnergy   Consolidated   (In  millions)   (In  millions)   (In  millions)   Revenues:   Revenues:   External   External   Electric   Electric   Other   Other   Internal   Internal   Total  Revenues   Total  Revenues   Operating  Expenses:   Operating  Expenses:   Fuel   Fuel   Purchased  power   Purchased  power   Other  operating  expenses   Other  operating  expenses   Pension  and  OPEB  mark-­to-­market   Pension  and  OPEB  mark-­to-­market   Provision  for  depreciation   Provision  for  depreciation   Amortization  of  regulatory  assets,  net   Amortization  of  regulatory  assets,  net   General  taxes   General  taxes   Impairment  of  long-­lived  assets   Impairment  of  long-­lived  assets   Total  Operating  Expenses   Total  Operating  Expenses   $   $   399   $   399   $   (17  )   (17  )   —   —   382   382   38   $   38   $   —   —   —   —   38   38   (261  )   $   (261  )   $   3   3   49   49   (209  )   (209  )   (32  )   $   (32  )   $   27   27   (49  )   (49  )   (54  )   (54  )   190   190   77   77   308   308   655   655   52   52   (528  )   (528  )   (4  )   (4  )   (322  )   (322  )   428   428   —   —   —   —   8   8   2   2   13   13   1   1   16   16   —   —   40   40   (406  )   (406  )   725   725   68   68   434   434   (52  )   (52  )   —   —   (31  )   (31  )   (473  )   (473  )   265   265   144   144   13   13   —   —   157   157   (216  )   (216  )   753   753   369   369   1,091   1,091   18   18   (527  )   (527  )   (16  )   (16  )   (795  )   677   (795  )   677   (520  )   (520  )   124   124   39   39   (57  )   (57  )   15   15   121   121   (399  )   (399  )   (237  )   (237  )   (162  )   (162  )   69   69   (93  )   (93  )   —   —   (49  )   (49  )   (15  )   (15  )   —   —   5   5   —   —   3   3   —   —   (56  )   (56  )   2   2   (17  )   (17  )   —   —   (6  )   (6  )   (4  )   (4  )   (27  )   (27  )   (25  )   (25  )   (72  )   (72  )   47   47   —   —   47   $   47   $   Operating  Income  (Loss)   Operating  Income  (Loss)   (46  )   (46  )   (2  )   (2  )   (474  )   (474  )   Other  Income  (Expense):   Other  Income  (Expense):   Loss  on  debt  redemptions   Loss  on  debt  redemptions   Investment  income   Investment  income   Interest  expense   Interest  expense   Capitalized  interest   Capitalized  interest   Total  Other  Expense   Total  Other  Expense   Income  (Loss)  From  Continuing  Operations  Before   Income  (Loss)  From  Continuing  Operations  Before   Income  Taxes  (Benefits)   Income  Taxes  (Benefits)   $   501   $   214   $   (218  )   $   (105  )   $   Net  Income  (Loss)   Net  Income  (Loss)   $   $   Income  taxes  (benefits)   Income  taxes  (benefits)   Income  (Loss)  From  Continuing  Operations   Income  (Loss)  From  Continuing  Operations   Discontinued  Operations,  net  of  tax   Discontinued  Operations,  net  of  tax   —   —   (1  )   (1  )   (46  )   (46  )   (17  )   (17  )   (64  )   (64  )   (110  )   (110  )   (74  )   (74  )   (36  )   (36  )   —   —   (36  )   $   (36  )   $   —   —   —   —   (38  )   (38  )   41   41   3   3   1   1   (8  )   (8  )   9   9   —   —   9   $   9   $   141   141   40   40   33   33   (5  )   (5  )   209   209   (265  )   (265  )   (83  )   (83  )   (182  )   (182  )   69   69   (113  )   $   (113  )   $   24   25   25               Regulated  Distribution  —  2014  Compared  with  2013     The  following  table  summarizes  the  price  and  volume  factors  contributing  to  the  $415  million  increase  in  generation  revenues  in  2014   compared  to  2013:   Regulated  Distribution's  net  income  decreased  $36  million  in  2014  compared  to  2013.  Regulated  Distribution's  Pension  and  OPEB   mark-­to-­market  adjustment  increased  $655  million  which  was  partially  offset  by  a  reduction  in  regulatory  asset  impairment  charges  of   $305  million  and  an  impairment  of  long-­lived  assets  of  $322  million  incurred  in  2013.  Excluding  the  impact  of  these  charges,  year-­ over-­year  earnings  were  impacted  by  higher  distribution  operating  and  maintenance  costs,  including  the  impact  of  higher  benefit   costs,  higher  depreciation  and  property  taxes,  and  higher  interest  expense  from  debt  issuances.    These  items  were  partially  offset  by   slightly  higher  distribution  deliveries,  higher  earnings  associated  with  the  October  2013  Harrison/Pleasants  asset  transfer,  and  a  lower   effective  tax  rate.   Revenues  —   The  $382  million  increase  in  total  revenues  resulted  from  the  following  sources:   Revenues  by  Type  of  Service   2014   2013   (Decrease)   For  the  Years  Ended   December  31,   Increase   Distribution  services   Generation  sales:   Retail   Wholesale   Total  generation  sales   Transmission  sales:   Retail   Wholesale   Total  transmission  sales   Other   Total  Revenues   $   3,694   $   3,762   $   (68  )   (In  millions)   4,043   661   4,704   352   148   500   204   9,102   $   3,959   330   4,289   347   101   448   221   8,720   $   84   331   415   5   47   52   (17  )   382   $   The  decrease  in  distribution  services  revenue  is  primarily  related  to  a  decrease  in  revenues  from  ME  and  PN  NUG  riders  as  a  result   of  the  expiration  of  certain  NUG  contracts  in  2013  and  a  rider  rate  decrease  associated  with  the  recovery  of  energy  efficiency  and   other  customer  program  costs  for  the  Pennsylvania  Companies.  This  was  partially  offset  by  higher  electric  distribution  MWH  deliveries   of  1.1%  as  described  below,  rate  increases  for  the  Ohio  Companies  associated  with  energy  efficiency  performance  shared  savings   and  the  Rider  DCR,  and  higher  revenues  for  the  Pennsylvania  Companies  associated  with  the  recovery  of  Smart  Meter  program   costs.  Certain  Ohio  energy  efficiency  programs  permit  the  Ohio  Companies  to  bill  and  collect  shared  savings  revenues  if  energy   efficiency  programs  meet  or  exceed  the  state  mandates.  Additionally,  the  Rider  DCR  provides  for  recovery  of  incremental  operating   expenses  and  a  return  on  rate  base  associated  with  incremental  distribution  plant  investments  in  Ohio.  Distribution  deliveries  by   customer  class  are  summarized  in  the  following  table:   For  the  Years  Ended   December  31,   Electric  Distribution  MWH  Deliveries   2014   2013   Increase   •     Fuel  expense  was  $190  million  higher  in  2014  primarily  related  to  increased  generation  as  a  result  of  the  October  2013   Residential   Commercial   Industrial   Other   Total  Electric  Distribution  MWH  Deliveries   (In  thousands)   54,766   42,925   51,276   586   149,553   54,479   42,582   50,243   584   147,888   0.5  %   0.8  %   2.1  %   0.3  %   1.1  %   Higher  deliveries  to  residential  customers  primarily  reflect  increased  weather-­related  usage  resulting  from  heating  degree  days  that   were  7%  above  2013,  and  9%  above  normal,  partially  offset  by  cooling  degree  days  that  were  15%  below  2013,  and  12%  below   normal.  Increased  deliveries  to  commercial  customers  reflect  improving  economic  conditions  across  FirstEnergy's  service  territories.   In  the  industrial  sector,  increased  sales  to  steel,  automotive  and  shale  gas  customers  were  partially  offset  by  lower  sales  to  chemical   and  paper  customers.   26   27   Source  of  Change  in  Generation  Revenues   Increase   (In  millions)   Retail:   Change  in  prices   Effect  of  increase  in  sales  volumes   $   Wholesale:   Effect  of  increase  in  sales  volumes   Change  in  prices   Capacity  revenue   Increase  in  Generation  Revenues   $   14   70   84   166   79   86   331   415   The  increase  in  retail  generation  sales  volume  was  primarily  due  to  weather-­related  usage,  as  described  above,  and  improving   economic  conditions,  partially  offset  by  increased  customer  shopping  in  Pennsylvania.  The  increase  in  retail  generation  prices  reflects   higher  Pennsylvania  PTC  prices,  the  completion  of  marginal  transmission  loss  refunds  to  ME  and  PN  customers  in  the  second   quarter   of   2013   and   a   higher   generation   rate   at   WP,   which   includes   the   recovery   of   transmission   costs   effective   June   2013.   Additionally,  the  impact  on  retail  generation  prices  of  MP's  Temporary  Transaction  Surcharge  (TTS)  associated  with  the  October  2013   Harrison/Pleasants  asset  transfer  was  offset  by  a  rate  reduction  associated  with  the  recovery  of  deferred  energy  costs.  As  part  of  the   TTS,  MP  earns  a  return  on  and  of  the  Harrison  plant  costs.   The  increase  in  wholesale  generation  revenues  of  $331  million  in  2014  resulted  from  increased  volume  and  energy  prices  associated   with  market  conditions  related  to  extreme  weather  events  in  January  2014  and  increased  capacity  revenue  related  to  the  October   2013  Harrison/Pleasants  asset  transfer  whereby  MP  acquired  from  AE  Supply  1,476  MWs  of  net  capacity.  During  January  2014,   unprecedented  customer  demand  associated  with  prolonged  periods  of  bitterly  cold  temperatures  and  unit  unavailability  across  the   PJM  footprint  resulted  in  severe  market  price  volatility  for  electricity  and  natural  gas  throughout  PJM.  Eight  of  the  ten  highest  winter   demands  for  electricity  on  the  PJM  system  occurred  in  January  2014.  The  difference  between  wholesale  generation  revenues,   primarily  associated  with  MP's  regulated  generation,  and  certain  energy  costs  are  deferred  for  future  recovery,  with  no  material  impact   to  earnings.     The  increase  in  transmission  revenues  of  $52  million  reflects  higher  PJM  revenues  at  MP  associated  with  market  conditions  related  to   extreme  weather  events  described  above  and  an  increase  in  the  Ohio  Companies'  NMB  transmission  rider  revenues,  partially  offset   by  the  termination  of  WP's  network  transmission  rider  effective  June  2013  as  discussed  above.  Network  transmission  costs  are  now   recovered  through  WP's  generation  rate.   Other  revenues  decreased  $17  million  primarily  due  to  less  customer  requested  work  in  2014  compared  to  2013.   Operating  Expenses  —   Total  operating  expenses  increased  by  $428  million  primarily  due  to  the  following:   Harrison/Pleasants  asset  transfer.   •     Purchased   power   costs   were   $77   million   higher   in   2014   primarily   due   to   increased   unit   prices   and   capacity   expense   reflecting  higher  auction  clearing  prices,  partially  offset  by  a  decrease  in  purchased  volumes  required.                                       Regulated  Distribution  —  2014  Compared  with  2013     Regulated  Distribution's  net  income  decreased  $36  million  in  2014  compared  to  2013.  Regulated  Distribution's  Pension  and  OPEB   mark-­to-­market  adjustment  increased  $655  million  which  was  partially  offset  by  a  reduction  in  regulatory  asset  impairment  charges  of   $305  million  and  an  impairment  of  long-­lived  assets  of  $322  million  incurred  in  2013.  Excluding  the  impact  of  these  charges,  year-­ over-­year  earnings  were  impacted  by  higher  distribution  operating  and  maintenance  costs,  including  the  impact  of  higher  benefit   costs,  higher  depreciation  and  property  taxes,  and  higher  interest  expense  from  debt  issuances.    These  items  were  partially  offset  by   slightly  higher  distribution  deliveries,  higher  earnings  associated  with  the  October  2013  Harrison/Pleasants  asset  transfer,  and  a  lower   effective  tax  rate.   Revenues  —   The  $382  million  increase  in  total  revenues  resulted  from  the  following  sources:   Revenues  by  Type  of  Service   2014   2013   (Decrease)   For  the  Years  Ended   December  31,   Increase   $   3,694   $   3,762   $   (68  )   (In  millions)   Distribution  services   Generation  sales:   Retail   Wholesale   Total  generation  sales   Transmission  sales:   Retail   Wholesale   Total  transmission  sales   Other   Total  Revenues   4,043   661   4,704   352   148   500   204   3,959   330   4,289   347   101   448   221   $   9,102   $   8,720   $   The  decrease  in  distribution  services  revenue  is  primarily  related  to  a  decrease  in  revenues  from  ME  and  PN  NUG  riders  as  a  result   of  the  expiration  of  certain  NUG  contracts  in  2013  and  a  rider  rate  decrease  associated  with  the  recovery  of  energy  efficiency  and   other  customer  program  costs  for  the  Pennsylvania  Companies.  This  was  partially  offset  by  higher  electric  distribution  MWH  deliveries   of  1.1%  as  described  below,  rate  increases  for  the  Ohio  Companies  associated  with  energy  efficiency  performance  shared  savings   and  the  Rider  DCR,  and  higher  revenues  for  the  Pennsylvania  Companies  associated  with  the  recovery  of  Smart  Meter  program   costs.  Certain  Ohio  energy  efficiency  programs  permit  the  Ohio  Companies  to  bill  and  collect  shared  savings  revenues  if  energy   efficiency  programs  meet  or  exceed  the  state  mandates.  Additionally,  the  Rider  DCR  provides  for  recovery  of  incremental  operating   expenses  and  a  return  on  rate  base  associated  with  incremental  distribution  plant  investments  in  Ohio.  Distribution  deliveries  by   customer  class  are  summarized  in  the  following  table:   Residential   Commercial   Industrial   Other   For  the  Years  Ended   December  31,   (In  thousands)   54,766   42,925   51,276   586   54,479   42,582   50,243   584   Total  Electric  Distribution  MWH  Deliveries   149,553   147,888   Higher  deliveries  to  residential  customers  primarily  reflect  increased  weather-­related  usage  resulting  from  heating  degree  days  that   were  7%  above  2013,  and  9%  above  normal,  partially  offset  by  cooling  degree  days  that  were  15%  below  2013,  and  12%  below   normal.  Increased  deliveries  to  commercial  customers  reflect  improving  economic  conditions  across  FirstEnergy's  service  territories.   In  the  industrial  sector,  increased  sales  to  steel,  automotive  and  shale  gas  customers  were  partially  offset  by  lower  sales  to  chemical   and  paper  customers.   84   331   415   5   47   52   (17  )   382   0.5  %   0.8  %   2.1  %   0.3  %   1.1  %   The  following  table  summarizes  the  price  and  volume  factors  contributing  to  the  $415  million  increase  in  generation  revenues  in  2014   compared  to  2013:   Source  of  Change  in  Generation  Revenues   Increase   (In  millions)   Retail:   Effect  of  increase  in  sales  volumes   $   Change  in  prices   Wholesale:   Effect  of  increase  in  sales  volumes   Change  in  prices   Capacity  revenue   Increase  in  Generation  Revenues   $   14   70   84   166   79   86   331   415   The  increase  in  retail  generation  sales  volume  was  primarily  due  to  weather-­related  usage,  as  described  above,  and  improving   economic  conditions,  partially  offset  by  increased  customer  shopping  in  Pennsylvania.  The  increase  in  retail  generation  prices  reflects   higher  Pennsylvania  PTC  prices,  the  completion  of  marginal  transmission  loss  refunds  to  ME  and  PN  customers  in  the  second   quarter   of   2013   and   a   higher   generation   rate   at   WP,   which   includes   the   recovery   of   transmission   costs   effective   June   2013.   Additionally,  the  impact  on  retail  generation  prices  of  MP's  Temporary  Transaction  Surcharge  (TTS)  associated  with  the  October  2013   Harrison/Pleasants  asset  transfer  was  offset  by  a  rate  reduction  associated  with  the  recovery  of  deferred  energy  costs.  As  part  of  the   TTS,  MP  earns  a  return  on  and  of  the  Harrison  plant  costs.   The  increase  in  wholesale  generation  revenues  of  $331  million  in  2014  resulted  from  increased  volume  and  energy  prices  associated   with  market  conditions  related  to  extreme  weather  events  in  January  2014  and  increased  capacity  revenue  related  to  the  October   2013  Harrison/Pleasants  asset  transfer  whereby  MP  acquired  from  AE  Supply  1,476  MWs  of  net  capacity.  During  January  2014,   unprecedented  customer  demand  associated  with  prolonged  periods  of  bitterly  cold  temperatures  and  unit  unavailability  across  the   PJM  footprint  resulted  in  severe  market  price  volatility  for  electricity  and  natural  gas  throughout  PJM.  Eight  of  the  ten  highest  winter   demands  for  electricity  on  the  PJM  system  occurred  in  January  2014.  The  difference  between  wholesale  generation  revenues,   primarily  associated  with  MP's  regulated  generation,  and  certain  energy  costs  are  deferred  for  future  recovery,  with  no  material  impact   to  earnings.     The  increase  in  transmission  revenues  of  $52  million  reflects  higher  PJM  revenues  at  MP  associated  with  market  conditions  related  to   extreme  weather  events  described  above  and  an  increase  in  the  Ohio  Companies'  NMB  transmission  rider  revenues,  partially  offset   by  the  termination  of  WP's  network  transmission  rider  effective  June  2013  as  discussed  above.  Network  transmission  costs  are  now   recovered  through  WP's  generation  rate.   Other  revenues  decreased  $17  million  primarily  due  to  less  customer  requested  work  in  2014  compared  to  2013.   Operating  Expenses  —   Total  operating  expenses  increased  by  $428  million  primarily  due  to  the  following:   Electric  Distribution  MWH  Deliveries   2014   2013   Increase   •     Fuel  expense  was  $190  million  higher  in  2014  primarily  related  to  increased  generation  as  a  result  of  the  October  2013   Harrison/Pleasants  asset  transfer.   •     Purchased   power   costs   were   $77   million   higher   in   2014   primarily   due   to   increased   unit   prices   and   capacity   expense   reflecting  higher  auction  clearing  prices,  partially  offset  by  a  decrease  in  purchased  volumes  required.   26   27                                       Source  of  Change  in  Purchased  Power   Increase   (Decrease)   (In  millions)   Purchases  from  non-­affiliates:   Change  due  to  increased  unit  costs   $   Change  due  to  decreased  volumes   Purchases  from  affiliates:   Change  due  to  increased  unit  costs   Change  due  to  increased  volumes   Capacity  expense   Increase  in  costs  deferred   Increase  in  Purchased  Power  Costs   $   127   (134  )   (7  )   39   2   41   58   (15  )   77   Other  operating  expenses  increased  $308  million  primarily  due  to:   •     Higher  transmission  expenses  of  $130  million  primarily  due  to  PJM  transmission  costs  associated  with  higher   congestion  rates  at  MP  as  a  result  of  market  conditions  related  to  extreme  weather  events  in  January  2014  and   higher  PJM  transmission  costs  resulting  from  the  October  2013  Harrison/Pleasants  asset  transfer.  The  differences   between  current  transmission  revenues  and  transmission  costs  incurred  are  deferred  for  future  recovery,  resulting   in  no  material  impact  on  current  period  earnings.   •     Higher  distribution  operating  and  maintenance  expenses  of  $75  million  resulting  from  higher  maintenance  activities   and  storm  related  restoration  expenses,  including  $26  million  of  storm  expenses  deferred  for  future  recovery.   •     Higher  vegetation  management  expenses  in  West  Virginia  of  $33  million,  which  were  deferred  for  future  recovery   per  authorization  of  the  WVPSC.   •     Higher   retirement   benefit   costs   of   $33   million   primarily   reflecting   higher   net   periodic   benefit   costs   before   the   pension  and  OPEB  mark-­to-­market  adjustments  discussed  below.   •     Increased  regulated  generation  operating  and  maintenance  expenses  of  $23  million,  reflecting  increased  costs   associated  with  the  October  2013  Harrison/Pleasants  asset  transfer  and  a  planned  outage  at  Fort  Martin.   Operating  Expenses  —   •     Pension  and  OPEB  mark-­to-­market  adjustments  increased  $655  million  to  $506  million,  primarily  reflecting  a  lower  discount   rate  and  revisions  to  mortality  assumptions  extending  the  expected  life  in  key  demographics  used  to  measure  related   obligations  in  2014.   Other  Expenses  —   •     Depreciation  expense  increased  $52  million  due  to  a  higher  asset  base,  including  $22  million  at  MP  associated  with  the   October  2013  Harrison/Pleasants  asset  transfer.   •     Net  regulatory  asset  amortization  decreased  $528  million  primarily  due  to:   •     Impairment  charges  on  regulatory  assets  of  $305  million  associated  with  the  recovery  of  marginal  transmission   losses  at  ME  and  PN  ($254  million)  and  the  recovery  of  RECs  for  the  Ohio  Companies  ($51  million)  that  occurred   in  2013,   •     Decreased  energy  efficiency  amortization  reflecting  a  rate  decrease  associated  with  certain  programs  for  the   •     •     Pennsylvania  Companies  ($67  million),   Lower  default  generation  service  and  NUG  costs  recovery  in  Pennsylvania  ($48  million),   Increased   deferral   of   West   Virginia   vegetation   management   expenses   ($33   million)   and   customer   refunds   associated  with  the  gain  on  the  Pleasants  plant  resulting  from  the  October  2013  Harrison/Pleasants  asset  transfer   ($36  million),  and   •     Higher  storm  cost  deferrals  ($26  million).   •     General  taxes  decreased  $4  million  primarily  due  to  lower  revenue-­related  taxes,  partially  offset  by  higher  property  taxes   and  an  increase  in  the  West  Virginia  business  and  occupation  tax  as  a  result  of  the  October  2013  Harrison/Pleasants  asset   transfer.   •     The  2013  impairment  of  long-­lived  assets  of  $322  million  reflects  MP's  charge  to  reduce  the  net  book  value  of  the  Harrison   plant  to  the  amount  permitted  to  be  included  in  rate  base  as  part  of  the  October  2013  Harrison/Pleasants  asset  transfer.     28   29   Other  expense  increased  $64  million  in  2014  primarily  due  to  higher  interest  expense  at  MP  resulting  from  new  debt  issuances  of   $580  million  associated  with  the  financing  of  the  October  2013  Harrison/Pleasants  asset  transfer,  a  new  debt  issuance  of  $500  million   in  August  2013  at  JCP&L  and  lower  capitalized  financing  costs  related  primarily  to  a  decrease  in  the  rate  used  for  borrowed  funds.   Regulated  Distribution's  effective  tax  rate  was  32.8%  and  37.5%  for  2014  and  2013,  respectively.  The  decrease  in  the  effective  tax   rate  primarily  resulted  from  changes  in  state  apportionment  factors,  an  increase  in  state  flow  through  income  tax  benefits  and  other   Regulated  Transmission  —  2014  Compared  with  2013     Net  income  increased  $9  million  in  2014  compared  to  2013.    Higher  Transmission  revenues  associated  with  increased  capital   investments  and  higher  capitalized  financing  costs  were  partially  offset  by  higher  operating  expenses  and  interest  expense.     Other  Expense  —   Income  Taxes  —   realized  tax  benefits.   Revenues  —   Total  revenues  increased  $38  million  principally  due  to  higher  revenue  at  ATSI  and  TrAIL,  reflecting  recovery  of  incremental  operating   expenses  and  a  higher  rate  base  as  included  in  their  annual  rate  filings  effective  June  2013  and  June  2014.   Revenues  by  transmission  asset  owner  are  shown  in  the  following  table:   Revenues  by  Transmission  Asset  Owner   2014   2013   For  the  Years  Ended   December  31,   Increase   (Decrease)   (In  millions)   $   $   242   $   214   13   300   769   $   209   $   207   20   295   731   $   33   7   (7  )   5   38   ATSI   TrAIL   PATH   Utilities   Total  Revenues   Total  operating  expenses  increased  $40  million  principally  due  to  higher  property  taxes,  depreciation  and  other  operating  expenses.   Total  other  expenses  decreased  $3  million  principally  due  to  higher  capitalized  financing  costs  of  $41  million  related  to  increased   construction  work  in  progress  balances  associated  with  the  Energizing  the  Future  investment  plan,  partially  offset  by  increased   interest  expense  resulting  from  new  debt  issuances  of  $1.0  billion  at  FET  and  $400  million  at  ATSI,  the  proceeds  of  which,  in  part,   paid  off  short  term  borrowings.   Income  Taxes  —   Regulated  Transmission's  effective  tax  rate  was  35.2%  and  37.6%  for  2014  and  2013,  respectively.  The  decrease  in  the  effective  tax   rate  primarily  resulted  from  an  increase  in  AFUDC  equity  flow  through.   CES  —  2014  Compared  with  2013     Operating  results  decreased  $113  million  in  2014,  compared  to  2013.  Lower  impairment  charges  of  $473  million  associated  with  the   deactivation  of  the  Hatfield  and  Mitchell  generating  units  and  a  lower  loss  on  debt  redemptions  of  $141  million  were  partially  offset   with  higher  Pension  and  OPEB  mark-­to-­market  adjustments  of  $434  million.  Excluding  the  impact  of  these  charges,  year-­over-­year   earnings  were  impacted  by  lower  sales  volumes,  reflecting  CES'  selling  efforts  discussed  below  and  an  increase  in  purchased  power   and  transmission  costs  incurred  to  serve  contract  sales  due  to  market  conditions  associated  with  the  extreme  weather  events  in   January  2014.  Partially  offsetting  these  items  were  lower  operating  expenses  due  to  lower  retail-­related  costs,  lower  generation  costs   resulting  from  plant  deactivations  and  asset  transfers,  and  higher  capacity  revenues  from  higher  auction  prices.  Additionally,  operating   results  were  impacted  by  a  $78  million  after-­tax  gain  on  the  sale  of  certain  hydro  facilities  in  February  2014.                                                             Other  Expense  —   Other  expense  increased  $64  million  in  2014  primarily  due  to  higher  interest  expense  at  MP  resulting  from  new  debt  issuances  of   $580  million  associated  with  the  financing  of  the  October  2013  Harrison/Pleasants  asset  transfer,  a  new  debt  issuance  of  $500  million   in  August  2013  at  JCP&L  and  lower  capitalized  financing  costs  related  primarily  to  a  decrease  in  the  rate  used  for  borrowed  funds.   Income  Taxes  —   Regulated  Distribution's  effective  tax  rate  was  32.8%  and  37.5%  for  2014  and  2013,  respectively.  The  decrease  in  the  effective  tax   rate  primarily  resulted  from  changes  in  state  apportionment  factors,  an  increase  in  state  flow  through  income  tax  benefits  and  other   realized  tax  benefits.   Regulated  Transmission  —  2014  Compared  with  2013     Net  income  increased  $9  million  in  2014  compared  to  2013.    Higher  Transmission  revenues  associated  with  increased  capital   investments  and  higher  capitalized  financing  costs  were  partially  offset  by  higher  operating  expenses  and  interest  expense.     Revenues  —   Total  revenues  increased  $38  million  principally  due  to  higher  revenue  at  ATSI  and  TrAIL,  reflecting  recovery  of  incremental  operating   expenses  and  a  higher  rate  base  as  included  in  their  annual  rate  filings  effective  June  2013  and  June  2014.   Revenues  by  transmission  asset  owner  are  shown  in  the  following  table:   Revenues  by  Transmission  Asset  Owner   2014   2013   Increase   (Decrease)   For  the  Years  Ended   December  31,   ATSI   TrAIL   PATH   Utilities   Total  Revenues   Operating  Expenses  —   $   $   (In  millions)   242   $   214   13   300   769   $   209   $   207   20   295   731   $   33   7   (7  )   5   38   Total  operating  expenses  increased  $40  million  principally  due  to  higher  property  taxes,  depreciation  and  other  operating  expenses.   Other  Expenses  —   Total  other  expenses  decreased  $3  million  principally  due  to  higher  capitalized  financing  costs  of  $41  million  related  to  increased   construction  work  in  progress  balances  associated  with  the  Energizing  the  Future  investment  plan,  partially  offset  by  increased   interest  expense  resulting  from  new  debt  issuances  of  $1.0  billion  at  FET  and  $400  million  at  ATSI,  the  proceeds  of  which,  in  part,   paid  off  short  term  borrowings.   Income  Taxes  —   Regulated  Transmission's  effective  tax  rate  was  35.2%  and  37.6%  for  2014  and  2013,  respectively.  The  decrease  in  the  effective  tax   rate  primarily  resulted  from  an  increase  in  AFUDC  equity  flow  through.   CES  —  2014  Compared  with  2013     Operating  results  decreased  $113  million  in  2014,  compared  to  2013.  Lower  impairment  charges  of  $473  million  associated  with  the   deactivation  of  the  Hatfield  and  Mitchell  generating  units  and  a  lower  loss  on  debt  redemptions  of  $141  million  were  partially  offset   with  higher  Pension  and  OPEB  mark-­to-­market  adjustments  of  $434  million.  Excluding  the  impact  of  these  charges,  year-­over-­year   earnings  were  impacted  by  lower  sales  volumes,  reflecting  CES'  selling  efforts  discussed  below  and  an  increase  in  purchased  power   and  transmission  costs  incurred  to  serve  contract  sales  due  to  market  conditions  associated  with  the  extreme  weather  events  in   January  2014.  Partially  offsetting  these  items  were  lower  operating  expenses  due  to  lower  retail-­related  costs,  lower  generation  costs   resulting  from  plant  deactivations  and  asset  transfers,  and  higher  capacity  revenues  from  higher  auction  prices.  Additionally,  operating   results  were  impacted  by  a  $78  million  after-­tax  gain  on  the  sale  of  certain  hydro  facilities  in  February  2014.     29                                         Revenues  —   Total  revenues  decreased  $209  million  in  2014,  compared  to  2013,  primarily  due  to  decreased  sales  volumes  in  the  Direct  and   Governmental  Aggregation  sales  channels,  partially  offset  by  higher  volume  in  the  Structured  Sales  channel.  Revenues  were  also   impacted  by  higher  unit  prices  as  a  result  of  increased  channel  pricing  and  higher  capacity  revenues,  as  described  below.   The  decrease  in  total  revenues  resulted  from  the  following  sources:   Revenues  by  Type  of  Service   2014   2013   (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   (In  millions)   2,359   $   1,184   452   902   522   5,419   461   220   189   6,289   $   2,913   $   1,185   448   858   421   5,825   343   144   186   6,498   $   $   $   (554  )   (1  )   4   44   101   (406  )   118   76   3   (209  )   MWH  Sales  by  Channel   2014   2013   (Decrease)   For  the  Years  Ended   December  31,   Increase   Contract  Sales:   Direct   Governmental  Aggregation   Mass  Market   POLR   Structured  Sales   Total  Contract  Sales   Wholesale   Total  MWH  Sales   (In  thousands)   44,012   19,569   6,773   15,708   12,814   98,876   680   99,556   56,145   20,859   6,761   15,758   9,047   108,570   1,250   109,820   (21.6  )%   (6.2  )%   0.2   %   (0.3  )%   41.6   %   (8.9  )%   (45.6  )%   (9.3  )%   The  following  tables  summarize  the  price  and  volume  factors  contributing  to  changes  in  revenues:   Source  of  Change  in  Revenues   Increase  (Decrease)   Gain  on   Settled   Contracts   (In  millions)   MWH  Sales  Channel:   Sales   Volumes   Prices   Capacity   Revenue   Total   Direct   Governmental  Aggregation   Mass  Market   POLR   Structured  Sales   Wholesale   $   (629  )   $   75   $   —   $   —   $   (554  )   (73  )   1   (3  )   176   (17  )   72   3   47   (75  )   —   —   —   —   —   (21  )   —   —   —   —   156   (1  )   4   44   101   118   Lower  sales  volumes  in  the  Direct,  Governmental  Aggregation  and  Mass  Market  sales  channels  primarily  reflects  CES'  efforts  to  more   effectively  hedge  its  generation  by  reducing  exposure  to  weather  sensitive  load.  Additionally,  although  unit  pricing  was  higher  year-­ over-­year  in  the  Direct,  Governmental  Aggregation  and  Mass  Market  channels  noted  above,  the  increase  was  primarily  attributable  to   higher  capacity  expense  as  discussed  below,  which  is  a  component  of  the  retail  price.  The  increase  in  prices  associated  with  capacity   was  partially  offset  by  lower  energy  pricing  built  into  the  retail  product  at  the  time  customers  were  acquired  for  2014  sales.  Beginning   in  the  fourth  quarter  of  2011,  when  there  was  a  significant  decline  in  energy  prices,  CES’  2014  retail  sales  position  was  approximately   30%  committed,  whereas  its  2013  retail  sales  position  was  approximately  60%  committed,  resulting  in  a  greater  proportion  of  2014   sales  and  unit  prices  being  impacted  by  the  decline  in  the  energy  prices.     The  increase  in  POLR  revenues  of  $44  million  was  due  to  higher  rates  associated  with  the  capacity  expense  component  of  the  rate   discussed  above,  partially  offset  by  lower  sales  volumes.  The  increase  in  Structured  Sales  revenues  of  $101  million  was  due  to  higher   sales  volumes,  partially  offset  by  lower  unit  prices  primarily  due  to  market  conditions  related  to  extreme  weather  events  in  2014  that   reduced  the  gains  on  various  structured  financial  sales  contracts.   Wholesale  revenues  increased  $118  million  primarily  due  to  an  increase  in  capacity  revenue  from  higher  capacity  prices,  partially   offset  by  a  decrease  in  short-­term  (net  hourly  positions)  transactions.  The  decrease  in  Wholesale  sales  volumes  was  due  to  lower   generation  available  to  sell  primarily  as  a  result  of  the  Harrison/Pleasants  asset  transfer  and  the  deactivation  of  certain  power  plants   in  2013.   Transmission  revenue  increased  $76  million  due  to  higher  congestion  revenue  driven  by  market  conditions  related  to  extreme   weather  events  in  2014,  as  discussed  above.   Other  revenue  increased  $3  million  in  2014  as  compared  to  2013  as  higher  lease  revenues  from  additional  repurchased  equity   interests  in  affiliated  sale  and  leasebacks  since  2013,  partially  offset  by  a  $17  million  pre-­tax  gain  recognized  in  2013  on  the  sale  of   property  to  a  regulated  affiliate.  CES  earns  lease  revenue  associated  with  the  equity  interests  it  has  purchased.   Operating  Expenses  —   Total  operating  expenses  increased  $265  million  in  2014  due  to  the  following:   •     Fuel   costs   decreased   $406   million   primarily   due   to   lower   generation   volumes   resulting   from   the   October   2013   Harrison/Pleasants  asset  transfer,  the  deactivation  of  certain  power  plants  in  2013  and  increased  outages  as  compared  to   the  same  period  of  2013.  Higher  unit  prices,  primarily  driven  by  increased  peaking  generation,  was  partially  offset  by  the   suspension  of  the  DOE  nuclear  disposal  fee,  which  was  effective  May  2014.  Additionally,  fuel  costs  were  impacted  by  an   increase  in  settlement  and  termination  costs  related  to  coal  and  transportation  contracts.  Terminations  and  settlements   associated  with  damages  on  coal  and  transportation  contracts  were  approximately  $166  million  and  $128  million  in  2014   and  2013,  respectively.   •     Purchased  power  costs  increased  $725  million  due  to  higher  volumes  ($252  million),  increased  unit  prices  ($565  million)   and  higher  capacity  expenses  ($311  million),  partially  offset  by  lower  losses  on  financially  settled  contracts  ($403  million).   Higher   purchased   volumes   were   primarily   due   to   lower   available   generation   due   to   outages,   the   October   2013   Harrison/Pleasants  asset  transfer  and  the  deactivation  of  certain  power  plants  in  2013,  partially  offset  by  lower  contract   sales  as  described  above.  The  increase  in  unit  prices  was  primarily  a  result  of  market  conditions  related  to  extreme  weather   events  in  January  2014,  partially  offset  by  lower  losses  on  financially  settled  contracts.  The  increase  in  capacity  expense,   which  is  a  component  of  the  segment's  retail  price,  was  primarily  the  result  of  higher  capacity  rates  associated  with  the   segment's  retail  sales  obligations.     30   31                                         Revenues  —   Total  revenues  decreased  $209  million  in  2014,  compared  to  2013,  primarily  due  to  decreased  sales  volumes  in  the  Direct  and   Governmental  Aggregation  sales  channels,  partially  offset  by  higher  volume  in  the  Structured  Sales  channel.  Revenues  were  also   impacted  by  higher  unit  prices  as  a  result  of  increased  channel  pricing  and  higher  capacity  revenues,  as  described  below.   The  decrease  in  total  revenues  resulted  from  the  following  sources:   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   Gain  on   Settled   Contracts   Capacity   Revenue   Total   Revenues  by  Type  of  Service   2014   2013   (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   Contract  Sales:   Direct   Governmental  Aggregation   Mass  Market   POLR   Structured  Sales   Total  Contract  Sales   Wholesale   Total  MWH  Sales   (In  millions)   $   2,359   $   1,184   2,913   $   1,185   452   902   522   5,419   461   220   189   448   858   421   5,825   343   144   186   $   6,289   $   6,498   $   (In  thousands)   44,012   19,569   6,773   15,708   12,814   98,876   680   99,556   56,145   20,859   6,761   15,758   9,047   108,570   1,250   109,820   (554  )   (1  )   4   44   101   (406  )   118   76   3   (209  )   (21.6  )%   (6.2  )%   0.2   %   (0.3  )%   41.6   %   (8.9  )%   (45.6  )%   (9.3  )%   MWH  Sales  by  Channel   2014   2013   (Decrease)   For  the  Years  Ended   December  31,   Increase   (In  millions)   Direct   $   Governmental  Aggregation   Mass  Market   POLR   Structured  Sales   Wholesale   (629  )   $   (73  )   1   (3  )   176   (17  )   75   $   72   3   47   (75  )   —   —   $   —   —   —   —   (21  )   —   $   (554  )   —   (1  )   4   —   44   —   101   —   118   156   Lower  sales  volumes  in  the  Direct,  Governmental  Aggregation  and  Mass  Market  sales  channels  primarily  reflects  CES'  efforts  to  more   effectively  hedge  its  generation  by  reducing  exposure  to  weather  sensitive  load.  Additionally,  although  unit  pricing  was  higher  year-­ over-­year  in  the  Direct,  Governmental  Aggregation  and  Mass  Market  channels  noted  above,  the  increase  was  primarily  attributable  to   higher  capacity  expense  as  discussed  below,  which  is  a  component  of  the  retail  price.  The  increase  in  prices  associated  with  capacity   was  partially  offset  by  lower  energy  pricing  built  into  the  retail  product  at  the  time  customers  were  acquired  for  2014  sales.  Beginning   in  the  fourth  quarter  of  2011,  when  there  was  a  significant  decline  in  energy  prices,  CES’  2014  retail  sales  position  was  approximately   30%  committed,  whereas  its  2013  retail  sales  position  was  approximately  60%  committed,  resulting  in  a  greater  proportion  of  2014   sales  and  unit  prices  being  impacted  by  the  decline  in  the  energy  prices.     The  increase  in  POLR  revenues  of  $44  million  was  due  to  higher  rates  associated  with  the  capacity  expense  component  of  the  rate   discussed  above,  partially  offset  by  lower  sales  volumes.  The  increase  in  Structured  Sales  revenues  of  $101  million  was  due  to  higher   sales  volumes,  partially  offset  by  lower  unit  prices  primarily  due  to  market  conditions  related  to  extreme  weather  events  in  2014  that   reduced  the  gains  on  various  structured  financial  sales  contracts.   Wholesale  revenues  increased  $118  million  primarily  due  to  an  increase  in  capacity  revenue  from  higher  capacity  prices,  partially   offset  by  a  decrease  in  short-­term  (net  hourly  positions)  transactions.  The  decrease  in  Wholesale  sales  volumes  was  due  to  lower   generation  available  to  sell  primarily  as  a  result  of  the  Harrison/Pleasants  asset  transfer  and  the  deactivation  of  certain  power  plants   in  2013.   Transmission  revenue  increased  $76  million  due  to  higher  congestion  revenue  driven  by  market  conditions  related  to  extreme   weather  events  in  2014,  as  discussed  above.   Other  revenue  increased  $3  million  in  2014  as  compared  to  2013  as  higher  lease  revenues  from  additional  repurchased  equity   interests  in  affiliated  sale  and  leasebacks  since  2013,  partially  offset  by  a  $17  million  pre-­tax  gain  recognized  in  2013  on  the  sale  of   property  to  a  regulated  affiliate.  CES  earns  lease  revenue  associated  with  the  equity  interests  it  has  purchased.   Operating  Expenses  —   Total  operating  expenses  increased  $265  million  in  2014  due  to  the  following:   •     Fuel   costs   decreased   $406   million   primarily   due   to   lower   generation   volumes   resulting   from   the   October   2013   Harrison/Pleasants  asset  transfer,  the  deactivation  of  certain  power  plants  in  2013  and  increased  outages  as  compared  to   the  same  period  of  2013.  Higher  unit  prices,  primarily  driven  by  increased  peaking  generation,  was  partially  offset  by  the   suspension  of  the  DOE  nuclear  disposal  fee,  which  was  effective  May  2014.  Additionally,  fuel  costs  were  impacted  by  an   increase  in  settlement  and  termination  costs  related  to  coal  and  transportation  contracts.  Terminations  and  settlements   associated  with  damages  on  coal  and  transportation  contracts  were  approximately  $166  million  and  $128  million  in  2014   and  2013,  respectively.   •     Purchased  power  costs  increased  $725  million  due  to  higher  volumes  ($252  million),  increased  unit  prices  ($565  million)   and  higher  capacity  expenses  ($311  million),  partially  offset  by  lower  losses  on  financially  settled  contracts  ($403  million).   Higher   purchased   volumes   were   primarily   due   to   lower   available   generation   due   to   outages,   the   October   2013   Harrison/Pleasants  asset  transfer  and  the  deactivation  of  certain  power  plants  in  2013,  partially  offset  by  lower  contract   sales  as  described  above.  The  increase  in  unit  prices  was  primarily  a  result  of  market  conditions  related  to  extreme  weather   events  in  January  2014,  partially  offset  by  lower  losses  on  financially  settled  contracts.  The  increase  in  capacity  expense,   which  is  a  component  of  the  segment's  retail  price,  was  primarily  the  result  of  higher  capacity  rates  associated  with  the   segment's  retail  sales  obligations.     30   31                                         •     Fossil  operating  costs  decreased  $73  million  primarily  due  to  lower  contractor,  labor  and  materials  and  equipment  costs   resulting  from  previously  deactivated  units  and  the  October  2013  Harrison/Pleasants  asset  transfer.     •     Nuclear  operating  costs  increased  $6  million  as  a  result  of  higher  labor,  contractor,  materials  and  equipment  costs.  There   were  two  refueling  outages  in  each  of  2014  and  2013,  however,  the  duration  of  the  outages  in  2014  exceeded  the  prior  year.     •     Transmission  expenses  increased  $80  million  primarily  due  to  higher  operating  reserve  and  market-­based  ancillary  costs   associated  with  market  conditions  related  to  extreme  weather  events  in  2014.  Additionally,  effective  June  1,  2013,  network   expenses  associated  with  POLR  sales  in  Pennsylvania  became  the  responsibility  of  suppliers.     •     General  taxes  decreased  $31  million  primarily  due  to  lower  gross  receipts  taxes  resulting  from  reduced  retail  sales  volumes,   lower   payroll   taxes   as   a   result   of   lower   labor   costs   noted   above,   lower   property   taxes   due   to   the   October   2013   Harrison/Pleasants  asset  transfer,  and  reduced  Ohio  personal  property  taxes.   •     Impairments  of  long-­lived  assets  decreased  $473  million  due  to  the  impairment  of  two  unregulated,  coal-­fired  generating   plants  recognized  in  2013.     •     Depreciation   expense   decreased   $52   million   primarily   due   to   a   reduction   in   the   asset   base   as   a   result   of   the   plant   deactivations  and  the  October  2013  Harrison/Pleasants  asset  transfer  noted  above.     •     Pension  and  OPEB  mark-­to-­market  adjustments  increased  $434  million  to  $327  million,  primarily  reflecting  a  lower  discount   rate  and  revisions  to  mortality  assumptions  extending  the  expected  life  in  key  demographics  used  to  measure  related   obligations  in  2014.   •     Other  operating  expenses  increased  $55  million  primarily  due  to  an  increase  in  mark-­to-­market  expenses  on  commodity   contract  positions,  and  an  impairment  of  deferred  advertising  costs  of  $23  million  associated  with  the  elimination  of  future   selling  efforts  in  the  Mass  Market  and  certain  Direct  sales  channels,  partially  offset  by  lower  retail  and  marketing  related   costs.     Other  Expense  —   Total  other  expense  in  2014  decreased  $209  million  compared  to  2013  due  to  the  absence  of  a  $141  million  loss  on  debt  redemptions   in  connection  with  senior  notes  that  were  repurchased  in  2013,  higher  investment  income  primarily  on  the  NDT  investments,  lower   OTTI  and  lower  net  interest  expense  of  $28  million  due  to  debt  redemptions.   Income  Tax  Benefits  —   CES'  effective  tax  rate  was  34.8%  and  37.3%  for  2014  and  2013,  respectively.  The  decrease  in  the  effective  tax  rate,  which  resulted   in   a   lower   tax   benefit   on   pre-­tax   losses,   primarily   resulted   from   changes   in   state   apportionment   factors   and   higher   valuation   allowances  on  certain  NOL  carryforwards.     Discontinued  Operations  —   Discontinued  operations  increased  $69  million  in  2014  compared  to  the  same  period  of  last  year  primarily  due  to  a  pre-­tax  gain  of   approximately  $142  million  ($78  million  after-­tax)  associated  with  the  sale  of  hydro  assets  in  February  2014.   other  conditions.   Corporate/Other  —  2014  Compared  with  2013     Financial  results  from  Corporate/Other  resulted  in  a  $47  million  increase  in  net  income  in  2014  compared  to  2013  primarily  due  to   higher  tax  benefits,  partially  offset  by  $17  million  of  gains  on  debt  redemptions  in  2013.  The  higher  tax  benefits  primarily  resulted  from   an  IRS-­approved  change  in  accounting  method  that  increased  the  tax  basis  of  certain  assets  resulting  in  higher  future  tax  deductions,   and  the  resolution  of  state  tax  benefits  resulting  from  the  expiration  of  the  statute  of  limitation  on  certain  state  tax  positions.  Additional   income  tax  benefits  of  $25  million  were  recognized  in  2014  that  relate  to  prior  periods.  The  out-­of-­period  adjustment  primarily  related   to  the  correction  of  amounts  included  on  FirstEnergy's  tax  basis  balance  sheet.  Management  has  determined  that  these  adjustments   are  not  material  to  the  current  or  any  prior  period.  The  2013  effective  tax  rate  benefited  from  reductions  to  valuation  allowances   against  state  NOL  carryforwards,  as  well  as  changes  in  state  apportionment  factors,  which  reduced  deferred  tax  liabilities.   Regulatory  Assets   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.  The  following  table  provides  information  about  the  composition  of  net   regulatory  assets  as  of  December  31,  2015  and  December  31,  2014,  and  the  changes  during  the  year  ended  December  31,  2015:     Regulatory  Assets  (Liabilities)  by  Source   Regulatory  transition  costs   Customer  receivables  for  future  income  taxes   Nuclear  decommissioning  and  spent  fuel  disposal  costs   Asset  removal  costs   Deferred  transmission  costs   Deferred  generation  costs   Deferred  distribution  costs   Contract  valuations   Storm-­related  costs   Other   December  31,   December  31,    2015    2014   Increase   (Decrease)   $   185   $   240   $   (In  millions)   355   (272  )   (372  )   115   243   335   186   403   170   370   (305  )   (254  )   90   281   182   153   465   189   (55  )   (15  )   33   (118  )   25   (38  )   153   33   (62  )   (19  )   (63  )   Net  Regulatory  Assets  included  on  the  Consolidated  Balance  Sheets   $   1,348   $   1,411   $   Regulatory  assets  that  do  not  earn  a  current  return  totaled  approximately  $148  million  and  $488  million  as  of  December  31,  2015  and   2014, respectively, primarily  related  to  storm  damage  costs.  JCP&L's  regulatory  asset  related  to  2011  and  2012  storm  damage  costs   began  earning  a  return  on  April  1,  2015.  Effective  with  the  approved  settlement  on  April  9,  2015,  associated  with  their  general  base   rate  case,  the  Pennsylvania  Companies  transferred  the  net  book  value  of  legacy  meters  from  plant-­in-­service  to  regulatory  assets,   which  is  being  recovered  over  five  years.     As  of  December  31,  2015 and  December  31,  2014,  FirstEnergy  had  approximately  $116  million  and  $243  million of  net  regulatory   liabilities  that  are  primarily  related  to  asset  removal  costs.  Net  regulatory  liabilities  are  classified  within  other  noncurrent  liabilities  on   the  Consolidated  Balance  Sheets.   CAPITAL  RESOURCES  AND  LIQUIDITY   FirstEnergy  expects  its  existing  sources  of  liquidity  to  remain  sufficient  to  meet  its  anticipated  obligations  and  those  of  its  subsidiaries.   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.  During  2015,  FirstEnergy   received  $630  million  of  cash  dividends  and  capital  returned  from  its  subsidiaries  and  paid  $607  million  in  cash  dividends  to  common   shareholders.  In  addition  to  internal  sources  to  fund  liquidity  and  capital  requirements  for  2016  and  beyond,  FirstEnergy  expects  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  and/or  equity.  FirstEnergy   expects  that  borrowing  capacity  under  credit  facilities  will  continue  to  be  available  to  manage  working  capital  requirements  along  with   continued  access  to  long-­term  capital  markets.  Additionally,  FirstEnergy  also  expects  to  issue  long-­term  debt  at  certain  Utilities  and   certain  other  subsidiaries  to,  among  other  things,  refinance  short-­term  and  maturing  debt  in  the  ordinary  course,  subject  to  market  and   Additionally  in  2016,  FirstEnergy  has  minimum  required  funding  obligations  of $381  million  to  its  qualified  pension  plan,  of  which  $160   million  has  been  contributed  to  date.  FirstEnergy  expects  to  make  future  contributions  to  the  qualified  pension  plan  in  2016  with  cash,   equity  or  a  combination  thereof,  depending  on,  among  other  things,  market  conditions.     FirstEnergy's  longer  term  strategic  outlook  for  its  regulated  and  competitive  businesses  will  be  determined  following  resolution  of  the   Ohio   Companies'   ESP   IV,   including   the   proposed   PPA   between   FES   and   the   Ohio   Companies.   Once   the   ESP   IV   is   finalized,   FirstEnergy  expects  to  be  in  a  position  to  more  fully  understand  the  longer-­term  outlook  of  its  competitive  businesses  and  the  longer   term  growth  rate  of  its  regulated  businesses,  including  planned  capital  investments  and  any  additional  equity  to  fund  growth  in  its   regulated  businesses.  With  the  exception  of  Regulated  Transmission's  2016  projected  capital  expenditures  discussed  below,  planned   capital   expenditures   for   2016   for   Regulated   Distribution,   CES,   and   Corporate/Other   will   depend   on   the   outcome   of   the   Ohio   Companies'  ESP  IV  and  remain  subject  to  Board  approval.   FirstEnergy's   strategy   is   to   focus   on   investments   in   its   regulated   operations.   The   centerpiece   of   this   strategy   is   a   $4.2   billion   Energizing  the  Future  investment  plan  that  began  in  2014  and  will  continue  through  2017  to  upgrade  and  expand  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.  Through  2015,   FirstEnergy's  capital  expenditures  under  this  plan  were  $2.4  billion  and  in  2016  capital  expenditures  under  this  plan  are  currently   projected  to  be  approximately  $1  billion.  In  total,  FirstEnergy  has  identified  at  least  $15  billion  in  transmission  investment  opportunities   across  the  24,000  mile  transmission  system,  making  this  a  continuing  platform  for  investment  in  the  years  beyond  2017.   32   33                                         •   Nuclear operating  costs increased  $6  million  as a  result of higher labor, contractor, materials and  equipment costs. There   were  two  refueling  outages in  each  of 2014  and  2013, however, the  duration  of the  outages in  2014  exceeded  the  prior year. •   Transmission  expenses increased  $80 million  primarily due  to  higher operating  reserve  and  market-­based  ancillary costs associated  with  market conditions related  to  extreme  weather events in  2014. Additionally, effective  June  1, 2013, network expenses associated  with  POLR sales in  Pennsylvania  became  the  responsibility of suppliers. •   General taxes decreased  $31  million  primarily due  to  lower gross receipts taxes resulting  from reduced  retail sales volumes, lower payroll taxes as a   result of lower labor costs noted   above, lower property taxes due   to   the   October 2013   Harrison/Pleasants asset transfer, and  reduced  Ohio  personal property taxes. •   Impairments  of long-­lived  assets decreased  $473  million  due  to  the  impairment of two  unregulated, coal-­fired generating   plants recognized  in  2013. •   Depreciation   expense   decreased   $52   million   primarily due   to   a   reduction   in   the   asset base   as a   result of the   plant deactivations and  the  October 2013  Harrison/Pleasants asset transfer noted  above. •   Pension  and  OPEB mark-­to-­market adjustments increased  $434  million  to  $327  million, primarily reflecting  a  lower discount rate  and  revisions to  mortality assumptions extending  the  expected  life  in  key demographics used  to  measure  related   obligations in  2014. •   Other operating  expenses increased  $55  million  primarily due  to  an  increase  in  mark-­to-­market expenses on  commodity contract positions, and  an  impairment of deferred  advertising  costs of $23  million  associated  with  the  elimination  of future   selling  efforts in  the  Mass Market and  certain  Direct sales channels, partially offset by lower retail and  marketing  related   costs. Other Expense  — Income Tax  Benefits  — Total other expense  in  2014  decreased  $209  million  compared  to  2013  due  to  the  absence  of a  $141  million  loss on  debt redemptions in connection  with  senior notes that were  repurchased  in  2013, higher investment income  primarily on  the  NDT investments, lower OTTI and  lower net interest expense  of $28  million  due  to  debt redemptions. CES' effective  tax rate  was 34.8% and  37.3% for 2014  and  2013, respectively. The  decrease  in  the  effective  tax rate, which  resulted   in   a   lower tax benefit on   pre-­tax   losses, primarily   resulted from changes   in state apportionment factors   and higher valuation allowances on  certain  NOL carryforwards. Discontinued  Operations — Discontinued  operations increased  $69  million  in  2014  compared  to  the  same  period  of last year primarily due  to  a  pre-­tax  gain of approximately $142  million  ($78  million  after-­tax) associated with the sale of hydro assets in  February 2014. Corporate/Other — 2014  Compared  with  2013   Financial results from Corporate/Other resulted  in  a  $47  million  increase  in  net income  in  2014  compared  to  2013  primarily due  to   higher tax benefits, partially offset by $17  million  of gains on  debt redemptions in  2013. The  higher tax benefits primarily resulted  from an  IRS-­approved  change  in  accounting  method  that increased  the  tax basis of certain  assets resulting  in  higher future  tax deductions,   and  the  resolution of state tax  benefits  resulting from the expiration of the statute of limitation on certain state tax  positions. Additional income  tax benefits of $25  million  were  recognized  in  2014  that relate  to  prior periods. The  out-­of-­period  adjustment primarily related   to  the  correction  of amounts included  on  FirstEnergy's tax basis balance  sheet. Management has determined  that these  adjustments are  not material to  the  current or any prior period. The  2013  effective  tax rate  benefited  from reductions to  valuation  allowances against state  NOL carryforwards, as well as changes in  state  apportionment factors, which  reduced  deferred  tax liabilities. Regulatory  Assets 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. The  following  table  provides information  about the  composition  of net regulatory assets as of December 31, 2015  and  December 31, 2014, and  the  changes during  the  year ended  December 31, 2015: •   Fossil operating  costs decreased  $73  million  primarily due  to  lower contractor, labor and  materials and  equipment costs resulting  from previously deactivated  units and  the  October 2013  Harrison/Pleasants asset  transfer.   Regulatory  Assets  (Liabilities)  by  Source   December  31,    2015   December  31,    2014   Increase   (Decrease)   (In  millions)   Regulatory  transition  costs   $   Customer  receivables  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   185   $   355   (272  )   (372  )   115   243   335   186   403   170   240   $   370   (305  )   (254  )   90   281   182   153   465   189   Net  Regulatory  Assets  included  on  the  Consolidated  Balance  Sheets   $   1,348   $   1,411   $   (55  )   (15  )   33   (118  )   25   (38  )   153   33   (62  )   (19  )   (63  )   Regulatory  assets  that  do  not  earn  a  current  return  totaled  approximately  $148  million  and  $488  million  as  of  December  31,  2015  and   2014, respectively, primarily  related  to  storm  damage  costs.  JCP&L's  regulatory  asset  related  to  2011  and  2012  storm  damage  costs   began  earning  a  return  on  April  1,  2015.  Effective  with  the  approved  settlement  on  April  9,  2015,  associated  with  their  general  base   rate  case,  the  Pennsylvania  Companies  transferred  the  net  book  value  of  legacy  meters  from  plant-­in-­service  to  regulatory  assets,   which  is  being  recovered  over  five  years.     As  of  December  31,  2015 and  December  31,  2014,  FirstEnergy  had  approximately  $116  million  and  $243  million of  net  regulatory   liabilities  that  are  primarily  related  to  asset  removal  costs.  Net  regulatory  liabilities  are  classified  within  other  noncurrent  liabilities  on   the  Consolidated  Balance  Sheets.   CAPITAL  RESOURCES  AND  LIQUIDITY   FirstEnergy  expects  its  existing  sources  of  liquidity  to  remain  sufficient  to  meet  its  anticipated  obligations  and  those  of  its  subsidiaries.   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.  During  2015,  FirstEnergy   received  $630  million  of  cash  dividends  and  capital  returned  from  its  subsidiaries  and  paid  $607  million  in  cash  dividends  to  common   shareholders.  In  addition  to  internal  sources  to  fund  liquidity  and  capital  requirements  for  2016  and  beyond,  FirstEnergy  expects  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  and/or  equity.  FirstEnergy   expects  that  borrowing  capacity  under  credit  facilities  will  continue  to  be  available  to  manage  working  capital  requirements  along  with   continued  access  to  long-­term  capital  markets.  Additionally,  FirstEnergy  also  expects  to  issue  long-­term  debt  at  certain  Utilities  and   certain  other  subsidiaries  to,  among  other  things,  refinance  short-­term  and  maturing  debt  in  the  ordinary  course,  subject  to  market  and   other  conditions.   Additionally  in  2016,  FirstEnergy  has  minimum  required  funding  obligations  of $381  million  to  its  qualified  pension  plan,  of  which  $160   million  has  been  contributed  to  date.  FirstEnergy  expects  to  make  future  contributions  to  the  qualified  pension  plan  in  2016  with  cash,   equity  or  a  combination  thereof,  depending  on,  among  other  things,  market  conditions.     FirstEnergy's  longer  term  strategic  outlook  for  its  regulated  and  competitive  businesses  will  be  determined  following  resolution  of  the   Ohio   Companies'   ESP   IV,   including   the   proposed   PPA   between   FES   and   the   Ohio   Companies.   Once   the   ESP   IV   is   finalized,   FirstEnergy  expects  to  be  in  a  position  to  more  fully  understand  the  longer-­term  outlook  of  its  competitive  businesses  and  the  longer   term  growth  rate  of  its  regulated  businesses,  including  planned  capital  investments  and  any  additional  equity  to  fund  growth  in  its   regulated  businesses.  With  the  exception  of  Regulated  Transmission's  2016  projected  capital  expenditures  discussed  below,  planned   capital   expenditures   for   2016   for   Regulated   Distribution,   CES,   and   Corporate/Other   will   depend   on   the   outcome   of   the   Ohio   Companies'  ESP  IV  and  remain  subject  to  Board  approval.   FirstEnergy's   strategy   is   to   focus   on   investments   in   its   regulated   operations.   The   centerpiece   of   this   strategy   is   a   $4.2   billion   Energizing  the  Future  investment  plan  that  began  in  2014  and  will  continue  through  2017  to  upgrade  and  expand  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.  Through  2015,   FirstEnergy's  capital  expenditures  under  this  plan  were  $2.4  billion  and  in  2016  capital  expenditures  under  this  plan  are  currently   projected  to  be  approximately  $1  billion.  In  total,  FirstEnergy  has  identified  at  least  $15  billion  in  transmission  investment  opportunities   across  the  24,000  mile  transmission  system,  making  this  a  continuing  platform  for  investment  in  the  years  beyond  2017.   32 33   In   alignment   with   FirstEnergy’s   strategy   to   invest   in   its   Regulated   Transmission   and   Regulated   Distribution   segments   and   the   repositioning  of  the  CES  segment,  FirstEnergy  is  also  focused  on  improving  the  balance  sheet  over  time  consistent  with  its  business   profile,  maintaining  investment  grade  metrics  at  each  business  unit,  and  maintaining  strong  liquidity  for  an  overall  stable  financial   position.  Specifically,  at  the  regulated  businesses,  authority  has  been  obtained  for  various  regulated  distribution  and  transmission   subsidiaries  to  issue  and/or  refinance  debt.   As  part  of  an  ongoing  effort  to  manage  costs,  FirstEnergy  identified  both  immediate  and  long-­term  savings  opportunities  through  its   cash  flow  improvement  plan.  The  cash  flow  improvement  plan  identified  targeted  cash  savings  of  approximately  $58  million  in  2015,   $155  million  in  2016  and  $240  million  annually  by  2017,  with  reductions  in  operating  expenses  representing  approximately  65%  of  the   savings  over  the  three-­year  period.   Any   financing   plans   by   FirstEnergy,   including   the   issuance   of   equity,   refinancing   of   maturing   debt   and   reductions   in   short-­term   borrowings,  are  subject  to  market  conditions  and  other  factors.  No  assurance  can  be  given  that  any  such  issuances,  financings,   refinancings,  or  reductions  in  short-­term  debt,  as  the  case  may  be,  will  be  completed  as  anticipated.  In  addition,  FirstEnergy  expects   to  continually  evaluate  any  planned  financings,  which  may  result  in  changes  from  time  to  time.   As  of  December  31,  2015,  FirstEnergy’s  net  deficit  in  working  capital  (current  assets  less  current  liabilities)  was  due  in  large  part  to   currently  payable  long-­term  debt  and  short-­term  borrowings.  Currently  payable  long-­term  debt  as  of  December  31,  2015,  included  the   following:   Currently  Payable  Long-­Term  Debt   PCRBs  supported  by  bank  LOCs  (1)   FMBs   Unsecured  notes   Unsecured  PCRBs  (1)   Collateralized  lease  obligation  bonds   Sinking  fund  requirements   Other  notes   (In  millions)   92   245   300   391   23   87   28   1,166   $   $   (1) These  PCRBs  are  classified  as  currently  payable  long-­term  debt  because  the  applicable  interest  rate mode  permits  individual  debt  holders  to  put  the  respective  debt  back  to  the  issuer  prior  to  maturity. Short-­Term  Borrowings  /  Revolving  Credit  Facilities   FE  and  certain  of  its  subsidiaries  participate  in  three  five-­year  syndicated  revolving  credit  facilities  with  aggregate  commitments  of   $6.0  billion  (Facilities),  which  are  available  until  March  31,  2019.  FirstEnergy  had  $1,708  million  and  $1,799  million  of  short-­term   borrowings  as  of  December  31,  2015  and  2014,  respectively.  FirstEnergy’s  available  liquidity  under  the  Facilities  as  of  January  31,   2016  was  as  follows:   Borrower(s)   Type   Maturity   Commitment   Available   Liquidity   FirstEnergy(1)   FES  /  AE  Supply   FET(2)   Revolving   March  2019   $   Revolving   March  2019   Revolving   March  2019   Subtotal   $   Cash   Total   $   (1) (2) FE  and  the  Utilities.   Includes  FET,  ATSI  and  TrAIL. (In  millions)   3,500   $   1,500   1,000   6,000   $   —   6,000   $   1,595   1,442   1,000   4,037   63   4,100   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.     34   35 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   December 31, 2015: Borrower AE Supply JCP&L FE FES FET OE CEI TE ME PN WP MP PE ATSI Penn TrAIL FirstEnergy   Revolving Credit  Facility Sub-­Limit FES/AE Supply   Revolving Credit  Facility Sub-­Limit FET  Revolving Credit  Facility Sub-­Limit Regulatory  and Other Short-­Term Debt Limitations $ 3,500 $ $ $ (In millions) — 1,500 1,000 — — — 500 500 500 600 300 300 200 500 150 — 50 — 1,000 — — — — — — — — — — — — 500 — 400 — — — — — — — — — — — — — — (1)   — (2)   — (2) — (1)   500 (3)   500 (3) 500 (3)   500 (3)   500 (3) 300 (3)   200 (3)   500 (3)   150 (3)   500 (3)   100 (3)   400 (3)   No  limitations. (1) (2) (3) No  limitation  based  upon  blanket financing  authorization  from the  FERC under existing  market-­based  rate  tariffs. Includes  amounts  which  may  be  borrowed  under the  regulated  companies' money pool. The  entire  amount of the  FES/AE Supply Facility, $600  million  of the  FE Facility and  $225  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, 2015, the  borrowers were  in  compliance  with  the  applicable  debt to  total capitalization ratio  covenants under the   respective Facilities. Term Loans FE has a  $1  billion  variable  rate  term loan  credit agreement with  a  maturity date  of March  31, 2019. The  initial borrowing  under the   term loan, which  took the  form of a  Eurodollar rate  advance, may be  converted  from time  to  time, in  whole  or in  part, to  alternate  base   rate  advances or other Eurodollar rate  advances. The  proceeds from this term loan  reduced  borrowings under the  FE Facility. Additionally, FE has a  $200  million  variable  rate  term loan  with  a  maturity date  of May 29, 2020. Each  of the  term loans contains covenants and  other terms and  conditions substantially similar to  those  of the  FE Facility described  above, including  the  same   consolidated  debt to  total capitalization  ratio  requirement. As of December 31, 2015, FE was  in compliance with the applicable consolidated debt to  total capitalization ratio covenants  under each  of these  term loans. In alignment with FirstEnergy’s   strategy   to invest in its Regulated Transmission and Regulated Distribution segments   and the repositioning  of the  CES segment, FirstEnergy is also  focused  on  improving  the  balance  sheet over time  consistent with  its  business   profile, maintaining  investment grade  metrics at each  business unit, and  maintaining  strong  liquidity for an  overall stable  financial position. Specifically, at the  regulated  businesses, authority has been  obtained  for various regulated  distribution  and  transmission subsidiaries to  issue  and/or refinance  debt. As part of an  ongoing  effort to  manage  costs, FirstEnergy identified  both  immediate  and  long-­term savings  opportunities  through its   cash  flow improvement plan. The  cash  flow improvement plan  identified  targeted  cash  savings of approximately $58  million  in  2015, $155 million in 2016 and $240 million annually  by  2017, with reductions in operating expenses  representing approximately  65% of the savings over the  three-­year period. Any financing plans by FirstEnergy, including   the   issuance   of equity, refinancing   of maturing   debt and   reductions in   short-­term borrowings, are  subject to  market conditions and  other factors. No  assurance  can  be  given  that any such  issuances, financings,   refinancings, or reductions in  short-­term debt, as  the case may  be, will be completed as  anticipated. In addition, FirstEnergy  expects   to continually  evaluate any  planned financings, which may  result in changes  from time to time. As of December 31, 2015, FirstEnergy’s net deficit in  working  capital (current assets less current liabilities) was due  in  large  part to   currently payable  long-­term debt and  short-­term borrowings. Currently payable  long-­term debt as of December 31, 2015, included  the   following: Currently  Payable  Long-­Term Debt PCRBs supported  by bank LOCs (1) FMBs Unsecured  notes Unsecured  PCRBs (1) Collateralized  lease  obligation  bonds Sinking  fund  requirements Other notes (In millions) $ 92 245 300 391 23 87 28 $ 1,166 (1) These  PCRBs are  classified  as currently payable  long-­term debt because  the  applicable  interest rate   mode  permits  individual debt holders  to  put the  respective  debt back  to  the  issuer prior to  maturity. Short-­Term Borrowings / Revolving Credit  Facilities FE and  certain  of its subsidiaries participate  in  three  five-­year syndicated  revolving  credit facilities with  aggregate  commitments of $6.0  billion  (Facilities), which  are  available  until March  31, 2019. FirstEnergy had  $1,708  million  and  $1,799  million  of short-­term borrowings as of December 31, 2015  and  2014, respectively. FirstEnergy’s available  liquidity under the  Facilities as of January 31, 2016  was as follows: Borrower(s) Type Maturity Commitment FirstEnergy(1) Revolving March  2019 $ 3,500 $ FES  / AE  Supply Revolving March  2019 FET(2) Revolving March  2019 1,500 1,000 Available   Liquidity (In millions) Subtotal $ 6,000 $ Cash Total $ — 6,000 $ 1,595 1,442 1,000 4,037 63 4,100 (1) (2) FE  and  the  Utilities. Includes  FET, ATSI and  TrAIL. 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. 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   December  31,  2015:   Borrower   FE   FES   AE  Supply   FET   OE   CEI   TE   JCP&L   ME   PN   WP   MP   PE   ATSI   Penn   TrAIL   FirstEnergy   Revolving   Credit  Facility   Sub-­Limit   FES/AE  Supply   Revolving   Credit  Facility   Sub-­Limit   FET  Revolving   Credit  Facility   Sub-­Limit   Regulatory  and   Other  Short-­Term   Debt  Limitations   (In  millions)   $   3,500   —   —   —   500   500   500   600   300   300   200   500   150   —   50   —   $   —   1,500   1,000   —   —   —   —   —   —   —   —   —   —   —   —   —   $   —   —   —   1,000   —   —   —   —   —   —   —   —   —   500   —   400   $   —   (1)   —   (2)   —   (2) —   (1)   500   (3)   500   (3) 500   (3)   500   (3)   500   (3) 300   (3)   200   (3)   500   (3)   150   (3)   500   (3)   100   (3)   400   (3)   (1) (2) (3) No  limitations. No  limitation  based  upon  blanket  financing  authorization  from  the  FERC  under  existing  market-­based  rate  tariffs.   Includes  amounts  which  may  be  borrowed  under  the  regulated  companies'  money  pool.   The  entire  amount  of  the  FES/AE  Supply  Facility,  $600  million  of  the  FE  Facility  and  $225  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,  2015,  the  borrowers  were  in  compliance  with  the  applicable  debt  to  total  capitalization  ratio  covenants  under  the   respective  Facilities.   Term  Loans   FE  has  a  $1  billion  variable  rate  term  loan  credit  agreement  with  a  maturity  date  of  March  31,  2019.  The  initial  borrowing  under  the   term  loan,  which  took  the  form  of  a  Eurodollar  rate  advance,  may  be  converted  from  time  to  time,  in  whole  or  in  part,  to  alternate  base   rate  advances  or  other  Eurodollar  rate  advances.  The  proceeds  from  this  term  loan  reduced  borrowings  under  the  FE  Facility.   Additionally,  FE  has  a  $200  million  variable  rate  term  loan  with  a  maturity  date  of  May  29,  2020.  Each  of  the  term  loans  contains   covenants  and  other  terms  and  conditions  substantially  similar  to  those  of  the  FE  Facility  described  above,  including  the  same   consolidated  debt  to  total  capitalization  ratio  requirement.     As  of  December  31,  2015,  FE  was  in  compliance  with  the  applicable  consolidated  debt  to  total  capitalization  ratio  covenants  under   each  of  these  term  loans.     34 35   FirstEnergy  Money  Pools   Changes  in  Cash  Position 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.  A  similar  but  separate  arrangement  exists  among  FirstEnergy’s  unregulated  companies.   FESC  administers  these  two  money  pools  and  tracks  surplus  funds  of  FirstEnergy  and  the  respective  regulated  and  unregulated   subsidiaries,  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  2015  was  0.84%  per  annum  for  the  regulated  companies’  money  pool   and  1.64%  per  annum  for  the  unregulated  companies’  money  pool.     Pollution  Control  Revenue  Bonds   As  of  December  31,  2015,  FirstEnergy’s  currently  payable  long-­term  debt  included  approximately  $92  million  of  FES  variable  interest   rate  PCRBs,  the  bondholders  of  which  are  entitled  to  the  benefit  of  irrevocable  direct  pay  bank  LOCs.  The  interest  rates  on  the   PCRBs  are  reset  daily  or  weekly.  Bondholders  can  tender  their  PCRBs  for  mandatory  purchase  prior  to  maturity  with  the  purchase   price  payable  from  remarketing  proceeds  or,  if  the  PCRBs  are  not  successfully  remarketed,  by  drawings  on  the  irrevocable  direct  pay   LOCs.  The  subsidiary  obligor  is  required  to  reimburse  the  applicable  LOC  bank  for  any  such  drawings  or,  if  the  LOC  bank  fails  to   honor   its   LOC   for   any   reason,   must   itself   pay   the   purchase   price.   The   LOCs   for   FirstEnergy's   variable   interest   rate   PCRBs   outstanding  as  of  December  31,  2015  were  issued  by  the  following  bank:   Bank   Aggregate   Amount(1)   (In  millions)   Termination  Date   Reimbursements   of  Draws  Due   The  Bank  of  Nova  Scotia   $   92   March  2017   March  2017   (1) Excludes  approximately  $1  million  of  applicable  interest  coverage. 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  December  31,  2015:     As of December 31, 2015, FirstEnergy had  $131  million  of cash  and  cash  equivalents compared  to  $85  million  of cash  and  cash   equivalents as of December 31, 2014. As of December 31, 2015  and  2014, FirstEnergy had  approximately $82  million  and  $79   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 services provided  by its utility operating  subsidiaries and  the   sale  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, interest, employees, tax authorities, lenders and  others for a  wide  range  of materials and  services. Net cash  provided  from operating  activities was $3,447  million  during  2015, $2,713  million  during  2014  and  $2,662  million  during   2013. Cash  flows from operations increased  $734 million  in  2015  compared  with  2014  due  to  the  following: •   Distribution  rate  increases associated  with  the  implementation  of new rates, partially offset by a  year-­over-­year decline   •   Higher transmission  revenue  and  earnings, reflecting  recovery of incremental operating  expenses, a  higher rate  base   in  distribution  deliveries;; and  forward-­looking  rates at ATSI;; •   Higher capacity revenues at CES, partially offset by a  decline  in  sales volume;; Lower disbursements for fuel and  purchased power resulting from the  lower sales volumes;; and •   •   •   Lower posted  collateral;; partially offset by, A $143  million  contribution  to  the  qualified  pension  plan  in  2015. Cash  Flows  From Financing  Activities In 2015, cash used for financing activities  was  $279 million compared to $513 million and $477 million of net cash provided from financing activities  during 2014 and 2013, respectively. The  following table summarizes  new debt financing (net of any  discounts),   redemptions and  common  stock dividend  payments: Securities  Issued  or Redeemed  / Repaid 2015 2014 2013 Issuer   FE   FES   AE  Supply   AGC   ATSI   CEI   FET   JCP&L   ME   MP   OE   PN   Penn   PE   TE   TrAIL   WP   Senior  Secured   Senior  Unsecured   S&P   —   BBB-­   BBB-­   —   —   Moody’s   —   —   —   —   —   BBB+   Baa1   —   —   —   BBB+   BBB+   —   —   BBB+   BBB   —   BBB+   —   —   —   A3   A2   —   A2   A3   Baa1   —   A2   S&P   BB+   BBB-­   BBB-­   BBB-­   BBB-­   BBB-­   BB+   BBB-­   BBB-­   —   BBB-­   BBB-­   —   —   —   BBB-­   —   Moody’s   Baa3   Baa3   Baa3   Baa3   Baa2   Baa3   Baa3   Baa2   Baa1   —   Baa1   Baa2   —   —   —   A3   —   Fitch   BB+   —   —   —   —   —   —   —   —   —   —   —   —   —   —   —   Debt  capacity  is  subject  to  the  consolidated  debt  to  total  capitalization  limits  in  the  Facilities  previously  discussed.  As  of  December  31,   2015,  FE  and  its  subsidiaries  could  issue  additional  debt  of  approximately  $5.1  billion  and  remain  within  the  limitations  of  the  financial   covenants  required  by  the  Facilities.  As  of  December  31,  2015,  FES'  incremental  debt  capacity  under  its  consolidated  debt  to  total   capitalization  financial  covenant  is  also  $5.1  billion  given  FE's  consolidated  debt  to  total  capitalization  ratio  under  the  FE  Facility.   Tender premiums paid  on  debt redemptions — $ — $ (110) Short-­term borrowings, net (91) $ (1,605) $ 1,435 Common  stock dividend  payments (607) $ (604) $ (920) 36   37 New Issues Unsecured  notes PCRBs FMBs Term loan Senior secured  notes Redemptions / Repayments Unsecured  notes PCRBs FMBs Term loan Senior secured  notes Long-­term revolving credit For the  Years  Ended  December 31, (In millions) $ 475 $ 2,400 $ 2,300 878 200 1,050 — — 1,000 — 445 1,311 $ 4,528 $ 3,745 — $ (600) $ (2,284) (793) (175) (191) — — (470) (420) — (376) (50) (879) $ (1,759) $ (3,600) 339 295 200 2 (313) (215) (200) (151) — $ $ $ $ $ $ FirstEnergy  Money  Pools   Changes  in  Cash  Position   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.  A  similar  but  separate  arrangement  exists  among  FirstEnergy’s  unregulated  companies.   FESC  administers  these  two  money  pools  and  tracks  surplus  funds  of  FirstEnergy  and  the  respective  regulated  and  unregulated   subsidiaries,  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  2015  was  0.84%  per  annum  for  the  regulated  companies’  money  pool   and  1.64%  per  annum  for  the  unregulated  companies’  money  pool.     Pollution  Control  Revenue  Bonds   As  of  December  31,  2015,  FirstEnergy’s  currently  payable  long-­term  debt  included  approximately  $92  million  of  FES  variable  interest   rate  PCRBs,  the  bondholders  of  which  are  entitled  to  the  benefit  of  irrevocable  direct  pay  bank  LOCs.  The  interest  rates  on  the   PCRBs  are  reset  daily  or  weekly.  Bondholders  can  tender  their  PCRBs  for  mandatory  purchase  prior  to  maturity  with  the  purchase   price  payable  from  remarketing  proceeds  or,  if  the  PCRBs  are  not  successfully  remarketed,  by  drawings  on  the  irrevocable  direct  pay   LOCs.  The  subsidiary  obligor  is  required  to  reimburse  the  applicable  LOC  bank  for  any  such  drawings  or,  if  the  LOC  bank  fails  to   honor   its   LOC   for   any   reason,   must   itself   pay   the   purchase   price.   The   LOCs   for   FirstEnergy's   variable   interest   rate   PCRBs   outstanding  as  of  December  31,  2015  were  issued  by  the  following  bank:   Bank   Aggregate   Amount(1)   (In  millions)   Termination  Date   Reimbursements   of  Draws  Due   The  Bank  of  Nova  Scotia   $   92   March  2017   March  2017   (1)   Excludes  approximately  $1  million  of  applicable  interest  coverage.   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  December  31,  2015:     As  of  December  31,  2015,  FirstEnergy  had  $131  million  of  cash  and  cash  equivalents  compared  to  $85  million  of  cash  and  cash   equivalents  as  of  December  31,  2014.  As  of  December  31,  2015  and  2014,  FirstEnergy  had  approximately  $82  million  and  $79   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  services  provided  by  its  utility  operating  subsidiaries  and  the   sale  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,  interest,  employees,  tax  authorities,  lenders   and  others  for  a  wide  range  of  materials  and  services.   Net  cash  provided  from  operating  activities  was  $3,447  million  during  2015,  $2,713  million  during  2014  and  $2,662  million  during   2013.  Cash  flows  from  operations  increased  $734  million  in  2015  compared  with  2014  due  to  the  following:   •     Distribution  rate  increases  associated  with  the  implementation  of  new  rates,  partially  offset  by  a  year-­over-­year  decline   in  distribution  deliveries;;   •     Higher  transmission  revenue  and  earnings,  reflecting  recovery  of  incremental  operating  expenses,  a  higher  rate  base   and  forward-­looking  rates  at  ATSI;;   •     Higher  capacity  revenues  at  CES,  partially  offset  by  a  decline  in  sales  volume;;   •     •     •     A  $143  million  contribution  to  the  qualified  pension  plan  in  2015.   Lower  disbursements  for  fuel  and  purchased  power  resulting  from  the  lower  sales  volumes;;  and   Lower  posted  collateral;;  partially  offset  by,   Cash  Flows  From  Financing  Activities   In  2015,  cash  used  for  financing  activities  was  $279  million  compared  to  $513  million  and  $477  million  of  net  cash  provided  from   financing  activities  during  2014  and  2013,  respectively.  The  following  table  summarizes  new  debt  financing  (net  of  any  discounts),   redemptions  and  common  stock  dividend  payments:   Securities  Issued  or  Redeemed  /  Repaid   2015   2014   2013   For  the  Years  Ended  December  31,   Issuer   FE   FES   AE  Supply   JCP&L   AGC   ATSI   CEI   FET   ME   MP   OE   PN   Penn   PE   TE   TrAIL   WP   Senior  Secured   S&P   Moody’s   Senior  Unsecured   Moody’s   BBB+   Baa1   —   BBB-­   BBB-­   —   —   —   —   —   —   —   BBB+   BBB+   BBB+   BBB   —   BBB+   —   —   —   —   —   —   —   —   A3   A2   —   A2   A3   —   A2   Baa1   S&P   BB+   BBB-­   BBB-­   BBB-­   BBB-­   BBB-­   BB+   BBB-­   BBB-­   —   BBB-­   BBB-­   —   —   —   —   BBB-­   Baa3   Baa3   Baa3   Baa3   Baa2   Baa3   Baa3   Baa2   Baa1   —   Baa1   Baa2   —   —   —   A3   —   Fitch   BB+   —   —   —   —   —   —   —   —   —   —   —   —   —   —   —   Debt  capacity  is  subject  to  the  consolidated  debt  to  total  capitalization  limits  in  the  Facilities  previously  discussed.  As  of  December  31,   2015,  FE  and  its  subsidiaries  could  issue  additional  debt  of  approximately  $5.1  billion  and  remain  within  the  limitations  of  the  financial   covenants  required  by  the  Facilities.  As  of  December  31,  2015,  FES'  incremental  debt  capacity  under  its  consolidated  debt  to  total   capitalization  financial  covenant  is  also  $5.1  billion  given  FE's  consolidated  debt  to  total  capitalization  ratio  under  the  FE  Facility.   New  Issues   Unsecured  notes   PCRBs   FMBs   Term  loan   Senior  secured  notes   Redemptions  /  Repayments   Unsecured  notes   PCRBs   FMBs   Term  loan   Senior  secured  notes   Long-­term  revolving  credit   Tender  premiums  paid  on  debt  redemptions   Short-­term  borrowings,  net   Common  stock  dividend  payments   (In  millions)   475   $   339   295   200   2   1,311   $   2,400   $   878   200   1,050   —   4,528   $   2,300   —   1,000   —   445   3,745   —   $   (313  )   (215  )   (200  )   (151  )   —   (879  )   $   (600  )   $   (793  )   (175  )   —   (191  )   —   (1,759  )   $   (2,284  )   (470  )   (420  )   —   (376  )   (50  )   (3,600  )   —   $   —   $   (110  )   (91  )   $   (1,605  )   $   1,435   (607  )   $   (604  )   $   (920  )   $   $   $   $   $   $   $   36   37                                           During  the  second  quarter  of  2015,  FE  refinanced  a  $200  million  variable  interest  term  loan,  maturing  on  December  31,  2016  with  a   new  $200  million  variable  interest  term  loan  maturing  on  May  29,  2020.   CONTRACTUAL  OBLIGATIONS   On  July  1,  2015,  FG  and  NG  remarketed  approximately  $43  million  and  $296  million,  respectively,  of  PCRBs.  The  PCRBs  were   remarketed  with  fixed  interest  rates  ranging  from  3.125%  to  4.00%  and  mandatory  put  dates  ranging  from  July  2,  2018  to  July  1,   2021.     as  follows:   As  of  December  31,  2015,  our  estimated  cash  payments  under  existing  contractual  obligations  that  we  consider  firm  obligations  are   Contractual  Obligations   Total   2016   2017-­2018   2019-­2020   Thereafter   In  August  2015,  JCP&L  issued  $250  million  of  4.30%  senior  notes  due  January  2026.  The  proceeds  received  from  the  issuance  of  the   senior  notes  were  used  to  repay  a  portion  of  JCP&L’s  short-­term  borrowings  under  the  FirstEnergy  regulated  companies'  money  pool   and  an  external  revolving  credit  facility.       Also,  in  the  second  quarter  of  2015,  WP  agreed  to  sell  $150  million  of  new  4.45%  FMBs  due  September  2045  and  PE  agreed  to  sell   $145   million   of   new   4.47%   FMBs   due   August   2045.   The   transactions   closed   on   September   17,   2015   and   August   17,   2015,   respectively.  The  proceeds  resulting  from  the  issuance  of  the  WP  FMBs  were  used  to  repay  WP’s  borrowings  under  the  FirstEnergy   regulated  companies'  money  pool  and  for  other  general  corporate  purposes.  The  proceeds  resulting  from  the  issuance  of  the  PE   FMBs  were  used  to  repay  PE’s  $145  million  5.125%  FMBs  that  matured  on  August  15,  2015.     In  October  2015,  TrAIL  issued  $75  million  of  3.76%  senior  notes  due  May  2025.  The  proceeds  resulting  from  the  issuance  of  the   senior  notes  were  used:  (i)  to  fund  capital  expenditures,  including  with  respect  to  TrAIL's  transmission  expansion  plans;;  and  (ii)  for   working  capital  needs  and  other  general  business  purposes.     Additionally,  in  October  2015,  ATSI  issued  in  total  $150  million  of  senior  notes:  $75  million  of  4.00%  senior  notes  due  April  2026  and   $75  million  of  5.23%  senior  notes  due  October  2045.  The  proceeds  resulting  from  the  issuance  of  the  senior  notes  were  used:  (i)  to   fund  capital  expenditures,  including  with  respect  to  ATSI's  transmission  expansion  plans;;  (ii)  for  working  capital  needs  and  other   general  business  purposes;;  and  (iii)  to  repay  borrowings  under  the  FirstEnergy  regulated  companies'  money  pool.       Cash  Flows  From  Investing  Activities   Cash  used  for  investing  activities  in  2015  principally  represented  cash  used  for  property  additions.  The  following  table  summarizes   investing  activities  for  2015,  2014  and  2013:   Cash  Used  for  Investing  Activities   2015   2014   2013   For  the  Years  Ended  December  31,   Property  Additions:   Regulated  distribution   Regulated  transmission   Competitive  energy  services   Other  and  reconciling  adjustments   Nuclear  fuel   Proceeds  from  asset  sales   Investments   Asset  removal  costs   Other   (In  millions)   1,108   $   952   588   56   190   (20  )   107   142   (1  )   3,122   $   972   $   1,329   939   72   233   (394  )   68   153   (13  )   3,359   $   $   $   1,272   461   827   78   250   (4  )   72   146   (9  )   3,093   Cash  used  for  investing  activity  in  2015  as  compared  to  2014  were  impacted  by  lower  property  additions  of  $608  million,  partially   offset   by   a   $374   million   reduction   in   proceeds   received   from   asset   sales,   as   2014   included   proceeds   from   the   sale   of   certain   hydroelectric  assets.  The  decline  in  property  additions  were  due  to  the  following:   •     •     •     a  decrease  of  $351  million  at  CES,  resulting  from  the  absence  of  capital  investments  associated  with  the  Davis-­Besse  steam   generators  that  were  placed  into  service  in  May  2014,   a  decrease  of  $377  million  at  Regulated  Transmission  primarily  relating  to  the  timing  of  capital  investments  associated  with   its  Energizing  the  Future  investment  program,  partially  offset  by   an  increase  of  $136  million  at  Regulated  Distribution  relating  to  utility  specific  project  investments  and  costs  associated  with   the  Pennsylvania  smart  meter  program.     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   Total   $   20,238   $   1,039   $   3,435   $   3,499   $   12,265   (In  millions)   1,708   12,523   2,083   150   13,578   2,213   3,564   1,708   1,015   184   36   1,812   877   381   —   1,839   254   55   2,539   938   1,122   —   1,500   207   32   2,117   398   787   $   56,057   $   7,052   $   10,182   $   8,540   $   —   8,169   1,438   27   7,110   —   1,274   30,283   (1)   Excludes  unamortized  discounts  and  premiums,  fair  value  accounting  adjustments  and  capital  leases.   (2)   Interest  on  variable-­rate  debt  based  on  rates  as  of  December  31,  2015.   (3)   See  Note  6,  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,  2015.   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  $3.5  billion  in  2016,  $0.5  billion  of  which  are  expected  to  relate  to  the   Utilities'  contracts  with  FES.   The   table   above   also   excludes   regulatory   liabilities   (see   Note   14,   Regulatory   Matters),  AROs   (see   Note   13,  Asset   Retirement   Obligations),  reserves  for  litigation,  injuries  and  damages,  environmental  remediation,  and  annual  insurance  premiums,  including   nuclear  insurance  (see  Note  15,  Commitments,  Guarantees  and  Contingencies)  since  the  amount  and  timing  of  the  cash  payments   are  uncertain.  The  table  also  excludes  accumulated  deferred  income  taxes  and  investment  tax  credits  since  cash  payments  for   income  taxes  are  determined  based  primarily  on  taxable  income  for  each  applicable  fiscal  year.   NUCLEAR  INSURANCE   The   Price-­Anderson  Act   limits   the   public   liability   which   can   be   assessed   with   respect   to   a   nuclear   power   plant   to   $13.5   billion   (assuming  103  units  licensed  to  operate)  for  a  single  nuclear  incident,  which  amount  is  covered  by:  (i)  private  insurance  amounting  to   $375  million;;  and  (ii)  $13.1  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  maximum  potential  assessment  under   these  provisions  would  be  $509  million  (NG-­$501  million)  per  incident  but  not  more  than  $76  million  (NG-­$75  million)  in  any  one  year   for  each  incident.   In  addition  to  the  public  liability  insurance  provided  pursuant  to  the  Price-­Anderson  Act,  FirstEnergy  has  also  obtained  insurance   coverage  in  limited  amounts  for  economic  loss  and  property  damage  arising  out  of  nuclear  incidents.  FirstEnergy  is  a  member  of   NEIL,  which  provides  coverage  (NEIL  I)  for  the  extra  expense  of  replacement  power  incurred  due  to  prolonged  accidental  outages  of   nuclear  units.  Under  NEIL  I,  FirstEnergy’s  subsidiaries  have  policies,  renewable  annually,  corresponding  to  their  respective  nuclear   interests,  which  provide  an  aggregate  indemnity  of  up  to  approximately  $1.96  billion  (NG-­$1.93  billion)  for  replacement  power  costs   incurred  during  an  outage  after  an  initial  20-­week  waiting  period.  Members  of  NEIL  I  pay  annual  premiums  and  are  subject  to   assessments  if  losses  exceed  the  accumulated  funds  available  to  the  insurer.  FirstEnergy’s  present  maximum  aggregate  assessment   for  incidents  at  any  covered  nuclear  facility  occurring  during  a  policy  year  would  be  approximately  $15  million  (NG-­$15.1  million).   FirstEnergy  is  insured  as  to  its  respective  nuclear  interests  under  property  damage  insurance  provided  by  NEIL  to  the  operating   company  for  each  plant.  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.  FirstEnergy  pays  annual  premiums  for  this  coverage  and   is  liable  for  retrospective  assessments  of  up  to  approximately  $83  million  (NG-­$81  million).   38   39                                           During  the  second  quarter  of  2015,  FE  refinanced  a  $200  million  variable  interest  term  loan,  maturing  on  December  31,  2016  with  a   new  $200  million  variable  interest  term  loan  maturing  on  May  29,  2020.   CONTRACTUAL  OBLIGATIONS   On  July  1,  2015,  FG  and  NG  remarketed  approximately  $43  million  and  $296  million,  respectively,  of  PCRBs.  The  PCRBs  were   remarketed  with  fixed  interest  rates  ranging  from  3.125%  to  4.00%  and  mandatory  put  dates  ranging  from  July  2,  2018  to  July  1,   2021.     In  August  2015,  JCP&L  issued  $250  million  of  4.30%  senior  notes  due  January  2026.  The  proceeds  received  from  the  issuance  of  the   senior  notes  were  used  to  repay  a  portion  of  JCP&L’s  short-­term  borrowings  under  the  FirstEnergy  regulated  companies'  money  pool   and  an  external  revolving  credit  facility.       Also,  in  the  second  quarter  of  2015,  WP  agreed  to  sell  $150  million  of  new  4.45%  FMBs  due  September  2045  and  PE  agreed  to  sell   $145   million   of   new   4.47%   FMBs   due   August   2045.   The   transactions   closed   on   September   17,   2015   and   August   17,   2015,   respectively.  The  proceeds  resulting  from  the  issuance  of  the  WP  FMBs  were  used  to  repay  WP’s  borrowings  under  the  FirstEnergy   regulated  companies'  money  pool  and  for  other  general  corporate  purposes.  The  proceeds  resulting  from  the  issuance  of  the  PE   FMBs  were  used  to  repay  PE’s  $145  million  5.125%  FMBs  that  matured  on  August  15,  2015.     In  October  2015,  TrAIL  issued  $75  million  of  3.76%  senior  notes  due  May  2025.  The  proceeds  resulting  from  the  issuance  of  the   senior  notes  were  used:  (i)  to  fund  capital  expenditures,  including  with  respect  to  TrAIL's  transmission  expansion  plans;;  and  (ii)  for   working  capital  needs  and  other  general  business  purposes.     Additionally,  in  October  2015,  ATSI  issued  in  total  $150  million  of  senior  notes:  $75  million  of  4.00%  senior  notes  due  April  2026  and   $75  million  of  5.23%  senior  notes  due  October  2045.  The  proceeds  resulting  from  the  issuance  of  the  senior  notes  were  used:  (i)  to   fund  capital  expenditures,  including  with  respect  to  ATSI's  transmission  expansion  plans;;  (ii)  for  working  capital  needs  and  other   general  business  purposes;;  and  (iii)  to  repay  borrowings  under  the  FirstEnergy  regulated  companies'  money  pool.       Cash  Flows  From  Investing  Activities   Cash  used  for  investing  activities  in  2015  principally  represented  cash  used  for  property  additions.  The  following  table  summarizes   investing  activities  for  2015,  2014  and  2013:   Cash  Used  for  Investing  Activities   2015   2014   2013   For  the  Years  Ended  December  31,   Property  Additions:   Regulated  distribution   Regulated  transmission   Competitive  energy  services   Other  and  reconciling  adjustments   Nuclear  fuel   Proceeds  from  asset  sales   Investments   Asset  removal  costs   Other   (In  millions)   $   1,108   $   952   588   56   190   (20  )   107   142   (1  )   972   $   1,329   939   72   233   (394  )   68   153   (13  )   1,272   461   827   78   250   (4  )   72   146   (9  )   $   3,122   $   3,359   $   3,093   Cash  used  for  investing  activity  in  2015  as  compared  to  2014  were  impacted  by  lower  property  additions  of  $608  million,  partially   offset   by   a   $374   million   reduction   in   proceeds   received   from   asset   sales,   as   2014   included   proceeds   from   the   sale   of   certain   hydroelectric  assets.  The  decline  in  property  additions  were  due  to  the  following:   •     a  decrease  of  $351  million  at  CES,  resulting  from  the  absence  of  capital  investments  associated  with  the  Davis-­Besse  steam   generators  that  were  placed  into  service  in  May  2014,   •     a  decrease  of  $377  million  at  Regulated  Transmission  primarily  relating  to  the  timing  of  capital  investments  associated  with   its  Energizing  the  Future  investment  program,  partially  offset  by   •     an  increase  of  $136  million  at  Regulated  Distribution  relating  to  utility  specific  project  investments  and  costs  associated  with   the  Pennsylvania  smart  meter  program.     As  of  December  31,  2015,  our  estimated  cash  payments  under  existing  contractual  obligations  that  we  consider  firm  obligations  are   as  follows:   Contractual  Obligations   Total   2016   2017-­2018   2019-­2020   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   Total   $   $   20,238   $   1,708   12,523   2,083   150   13,578   2,213   3,564   56,057   $   (In  millions)   1,039   $   1,708   1,015   184   36   1,812   877   381   7,052   $   3,435   $   —   1,839   254   55   2,539   938   1,122   10,182   $   3,499   $   —   1,500   207   32   2,117   398   787   8,540   $   12,265   —   8,169   1,438   27   7,110   —   1,274   30,283   Interest  on  variable-­rate  debt  based  on  rates  as  of  December  31,  2015.   (1)   Excludes  unamortized  discounts  and  premiums,  fair  value  accounting  adjustments  and  capital  leases.   (2)   (3)   See  Note  6,  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,  2015.   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  $3.5  billion  in  2016,  $0.5  billion  of  which  are  expected  to  relate  to  the   Utilities'  contracts  with  FES.   The   table   above   also   excludes   regulatory   liabilities   (see   Note   14,   Regulatory   Matters),  AROs   (see   Note   13,  Asset   Retirement   Obligations),  reserves  for  litigation,  injuries  and  damages,  environmental  remediation,  and  annual  insurance  premiums,  including   nuclear  insurance  (see  Note  15,  Commitments,  Guarantees  and  Contingencies)  since  the  amount  and  timing  of  the  cash  payments   are  uncertain.  The  table  also  excludes  accumulated  deferred  income  taxes  and  investment  tax  credits  since  cash  payments  for   income  taxes  are  determined  based  primarily  on  taxable  income  for  each  applicable  fiscal  year.   NUCLEAR  INSURANCE   The   Price-­Anderson  Act   limits   the   public   liability   which   can   be   assessed   with   respect   to   a   nuclear   power   plant   to   $13.5   billion   (assuming  103  units  licensed  to  operate)  for  a  single  nuclear  incident,  which  amount  is  covered  by:  (i)  private  insurance  amounting  to   $375  million;;  and  (ii)  $13.1  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  maximum  potential  assessment  under   these  provisions  would  be  $509  million  (NG-­$501  million)  per  incident  but  not  more  than  $76  million  (NG-­$75  million)  in  any  one  year   for  each  incident.   In  addition  to  the  public  liability  insurance  provided  pursuant  to  the  Price-­Anderson  Act,  FirstEnergy  has  also  obtained  insurance   coverage  in  limited  amounts  for  economic  loss  and  property  damage  arising  out  of  nuclear  incidents.  FirstEnergy  is  a  member  of   NEIL,  which  provides  coverage  (NEIL  I)  for  the  extra  expense  of  replacement  power  incurred  due  to  prolonged  accidental  outages  of   nuclear  units.  Under  NEIL  I,  FirstEnergy’s  subsidiaries  have  policies,  renewable  annually,  corresponding  to  their  respective  nuclear   interests,  which  provide  an  aggregate  indemnity  of  up  to  approximately  $1.96  billion  (NG-­$1.93  billion)  for  replacement  power  costs   incurred  during  an  outage  after  an  initial  20-­week  waiting  period.  Members  of  NEIL  I  pay  annual  premiums  and  are  subject  to   assessments  if  losses  exceed  the  accumulated  funds  available  to  the  insurer.  FirstEnergy’s  present  maximum  aggregate  assessment   for  incidents  at  any  covered  nuclear  facility  occurring  during  a  policy  year  would  be  approximately  $15  million  (NG-­$15.1  million).   FirstEnergy  is  insured  as  to  its  respective  nuclear  interests  under  property  damage  insurance  provided  by  NEIL  to  the  operating   company  for  each  plant.  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.  FirstEnergy  pays  annual  premiums  for  this  coverage  and   is  liable  for  retrospective  assessments  of  up  to  approximately  $83  million  (NG-­$81  million).   38   39                                           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  FirstEnergy’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  could  be  required  to  make   under  these  guarantees  as  of  December  31,  2015,  was  approximately  $3.7  billion,  as  summarized  below:   Guarantees  and  Other  Assurances   Maximum   Exposure   (In  millions)   FE's  Guarantees  on  Behalf  of  its  Subsidiaries   Energy  and  Energy-­Related  Contracts(1)   Deferred  compensation  arrangements   Other(2)   $   Subsidiaries’  Guarantees   Energy  and  Energy-­Related  Contracts(3)   FES’  guarantee  of  NG’s  nuclear  property  insurance   FES'  guarantee  of  nuclear  decommissioning  costs   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   FES'  LOC  (long-­term  tax-­exempt  debt)(4)   LOCs(5)   Total  Guarantees  and  Other  Assurances   $   33   533   17   583   251   98   21   1,767   2,137   300   398   22   93   154   667   3,687   Issued  for  open-­ended  terms,  with  a  10-­day  termination  right  by  FirstEnergy.   Includes  guarantees  of  $4  million  for  nuclear  decommissioning  funding  assurances,  $7  million  for  railcar  leases,  and  $6  million  for  various  leases.   Includes  energy  and  energy-­related  contracts  associated  with  FES  of  approximately  $248  million.   (1)   (2)   (3)   (4)   Reflects  the  $1  million  of  interest  coverage  portion  of  LOCs  issued  in  support  of  floating  rate  PCRBs  with  various  maturities  and  the  principal   amount  of  floating-­rate  PCRBs  of  $92  million,  all  of  which  is  reflected  in  currently  payable  long-­term  debt  on  FirstEnergy's  consolidated  balance   sheets.   Includes  $54  million  issued  for  various  terms  pursuant  to  LOC  capacity  available  under  FirstEnergy's  revolving  credit  facilities,  $88  million  issued   in  connection  with  energy  and  energy  related  contracts,  $2  million  issued  in  connection  with  railcar  leases,  $7  million  pledged  in  connection  with   the  sale  and  leaseback  of  the  Beaver  Valley  Unit  2  by  OE  and  $3  million  pledged  in  connection  with  the  sale  and  leaseback  of  Perry  by  OE.   (5)   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  FES'  power  portfolio  exposure  as  of  December  31,  2015,  FES  has  posted  collateral  of  $188  million  and  AE   Supply  has  posted  no  collateral.  The  Regulated  Distribution  segment  has  posted  collateral  of  $1  million.   These  credit-­risk-­related  contingent  features  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  could  be  required.   Subsequent  to  the  occurrence  of  a  senior  unsecured  credit  rating  downgrade  to  below  S&P's  BBB-­  and  Moody's  Baa3,  or  a  “material   adverse  event,”  the  immediate  posting  of  collateral  or  accelerated  payments  may  be  required  of  FE  or  its  subsidiaries.  The  following   table  discloses  the  additional  credit  contingent  contractual  obligations  that  may  be  required  under  certain  events  as  of  December  31,   2015:   Collateral  Provisions   Split  Rating  (One  rating  agency's  rating  below  investment  grade)   BB+/Ba1  Credit  Ratings   Full  impact  of  credit  contingent  contractual  obligations   FES   AE  Supply   Utilities   Total   $   $   $   198   $   231   $   363   $   (In  millions)   6   $   6   $   16   $   41   $   41   $   41   $   245   278   420   Excluded   from   the   preceding   chart   are   the   potential   collateral   obligations   due   to   affiliate   transactions   between   the   Regulated   Distribution  segment  and  CES  segment.  As  of  December  31,  2015,  neither  FES  nor  AE  Supply  had  any  collateral  posted  with  their   affiliates.  In  the  event  of  a  senior  unsecured  credit  rating  downgrade  to  below  S&P's  BB-­  or  Moody's  Ba3,  FES  would  be  required  to   post  $8  million  with  affiliated  parties.     Other  Commitments  and  Contingencies   FirstEnergy  is  a  guarantor  under  a  syndicated  senior  secured  term  loan  facility  due  March  3,  2020,  under  which  Global  Holding   borrowed  $300  million.  In  addition  to  FirstEnergy,  Signal  Peak,  Global  Rail,  Global  Mining  Group,  LLC  and  Global  Coal  Sales  Group,   LLC,   each   being   a   direct   or   indirect   subsidiary   of   Global   Holding,   have   also   provided   their   joint   and   several   guaranties   of   the   obligations  of  Global  Holding  under  the  facility.   In  connection  with  Global  Holding's  term  loan  facility,  a  portion  of  Global  Holding's  direct  and  indirect  membership  interests  in  Signal   Peak,  Global  Rail  and  their  affiliates  along  with  each  of  FEV's  and  WMB  Marketing  Ventures,LLC's    33-­1/3%  membership  interests  in   Global  Holding,  are  pledged  to  the  lenders  under  Global  Holding's  facility  as  collateral.  Failure  by  Global  Holding  to  meet  the  terms   and  conditions  under  its  term  loan  facility  could  require  FirstEnergy  to  be  obligated  under  the  provisions  of  its  guarantee,  resulting  in   consolidation  of  Global  Holding  by  FE.   During  the  first  quarter  of  2015,  a  subsidiary  of  Global  Holding  eliminated  its  right  to  put  2  million  tons  annually  through  2024  from  the   Signal  Peak  mine  to  FG  in  exchange  for  FirstEnergy  extending  its  guarantee  under  Global  Holding's  $300  million  senior  secured  term   loan  facility  through  2020,  resulting  in  a  pre-­tax  charge  of  $24  million.  See  Note  8,  Variable  Interest  Entities,  and  Note  1,  Organization,   Basis  of  Presentation  and  Significant  Accounting  Policies  -­  Investments,  for  additional  information  regarding  FEV's  investment  in   Global  Holding.   OFF-­BALANCE  SHEET  ARRANGEMENTS   FES  and  certain  of  the  Ohio  Companies  have  obligations  that  are  not  included  on  their  Consolidated  Balance  Sheets  related  to  the   Perry  Unit  1,  Beaver  Valley  Unit  2,  and  2007  Bruce  Mansfield  Unit  1  sale  and  leaseback  arrangements,  which  are  satisfied  through   operating   lease   payments.   The   total   present   value   of   these   sale   and   leaseback   operating   lease   commitments,   net   of   trust   investments,  was  $950  million  as  of  December  31,  2015  and  primarily  relates  to  the  2007  Bruce  Mansfield  Unit  1  sale  and  leaseback   40   41                                             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  FirstEnergy’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   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.   becomes  unavailable  in  the  future,  FirstEnergy  would  remain  at  risk  for  such  costs.   Collateral  and  Contingent-­Related  Features   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  could  be  required  to  make   under  these  guarantees  as  of  December  31,  2015,  was  approximately  $3.7  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   Other(2)   Subsidiaries’  Guarantees   Energy  and  Energy-­Related  Contracts(3)   FES’  guarantee  of  NG’s  nuclear  property  insurance   FES'  guarantee  of  nuclear  decommissioning  costs   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   FES'  LOC  (long-­term  tax-­exempt  debt)(4)   Surety  Bonds   LOCs(5)   Maximum   Exposure   (In  millions)   $   33   533   17   583   251   98   21   1,767   2,137   300   398   22   93   154   667   Total  Guarantees  and  Other  Assurances   $   3,687   (1)   (2)   (3)   (5)   sheets.   Issued  for  open-­ended  terms,  with  a  10-­day  termination  right  by  FirstEnergy.   Includes  guarantees  of  $4  million  for  nuclear  decommissioning  funding  assurances,  $7  million  for  railcar  leases,  and  $6  million  for  various  leases.   Includes  energy  and  energy-­related  contracts  associated  with  FES  of  approximately  $248  million.   (4)   Reflects  the  $1  million  of  interest  coverage  portion  of  LOCs  issued  in  support  of  floating  rate  PCRBs  with  various  maturities  and  the  principal   amount  of  floating-­rate  PCRBs  of  $92  million,  all  of  which  is  reflected  in  currently  payable  long-­term  debt  on  FirstEnergy's  consolidated  balance   Includes  $54  million  issued  for  various  terms  pursuant  to  LOC  capacity  available  under  FirstEnergy's  revolving  credit  facilities,  $88  million  issued   in  connection  with  energy  and  energy  related  contracts,  $2  million  issued  in  connection  with  railcar  leases,  $7  million  pledged  in  connection  with   the  sale  and  leaseback  of  the  Beaver  Valley  Unit  2  by  OE  and  $3  million  pledged  in  connection  with  the  sale  and  leaseback  of  Perry  by  OE.   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  FES'  power  portfolio  exposure  as  of  December  31,  2015,  FES  has  posted  collateral  of  $188  million  and  AE   Supply  has  posted  no  collateral.  The  Regulated  Distribution  segment  has  posted  collateral  of  $1  million.   These  credit-­risk-­related  contingent  features  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  could  be  required.   Subsequent  to  the  occurrence  of  a  senior  unsecured  credit  rating  downgrade  to  below  S&P's  BBB-­  and  Moody's  Baa3,  or  a  “material   adverse  event,”  the  immediate  posting  of  collateral  or  accelerated  payments  may  be  required  of  FE  or  its  subsidiaries.  The  following   table  discloses  the  additional  credit  contingent  contractual  obligations  that  may  be  required  under  certain  events  as  of  December  31,   2015:   Collateral  Provisions   Split  Rating  (One  rating  agency's  rating  below  investment  grade)   BB+/Ba1  Credit  Ratings   Full  impact  of  credit  contingent  contractual  obligations   FES   AE  Supply   Utilities   Total   $   $   $   198   $   231   $   363   $   (In  millions)   6   $   6   $   16   $   41   $   41   $   41   $   245   278   420   Excluded   from   the   preceding   chart   are   the   potential   collateral   obligations   due   to   affiliate   transactions   between   the   Regulated   Distribution  segment  and  CES  segment.  As  of  December  31,  2015,  neither  FES  nor  AE  Supply  had  any  collateral  posted  with  their   affiliates.  In  the  event  of  a  senior  unsecured  credit  rating  downgrade  to  below  S&P's  BB-­  or  Moody's  Ba3,  FES  would  be  required  to   post  $8  million  with  affiliated  parties.     Other  Commitments  and  Contingencies   FirstEnergy  is  a  guarantor  under  a  syndicated  senior  secured  term  loan  facility  due  March  3,  2020,  under  which  Global  Holding   borrowed  $300  million.  In  addition  to  FirstEnergy,  Signal  Peak,  Global  Rail,  Global  Mining  Group,  LLC  and  Global  Coal  Sales  Group,   LLC,   each   being   a   direct   or   indirect   subsidiary   of   Global   Holding,   have   also   provided   their   joint   and   several   guaranties   of   the   obligations  of  Global  Holding  under  the  facility.   In  connection  with  Global  Holding's  term  loan  facility,  a  portion  of  Global  Holding's  direct  and  indirect  membership  interests  in  Signal   Peak,  Global  Rail  and  their  affiliates  along  with  each  of  FEV's  and  WMB  Marketing  Ventures,LLC's    33-­1/3%  membership  interests  in   Global  Holding,  are  pledged  to  the  lenders  under  Global  Holding's  facility  as  collateral.  Failure  by  Global  Holding  to  meet  the  terms   and  conditions  under  its  term  loan  facility  could  require  FirstEnergy  to  be  obligated  under  the  provisions  of  its  guarantee,  resulting  in   consolidation  of  Global  Holding  by  FE.   During  the  first  quarter  of  2015,  a  subsidiary  of  Global  Holding  eliminated  its  right  to  put  2  million  tons  annually  through  2024  from  the   Signal  Peak  mine  to  FG  in  exchange  for  FirstEnergy  extending  its  guarantee  under  Global  Holding's  $300  million  senior  secured  term   loan  facility  through  2020,  resulting  in  a  pre-­tax  charge  of  $24  million.  See  Note  8,  Variable  Interest  Entities,  and  Note  1,  Organization,   Basis  of  Presentation  and  Significant  Accounting  Policies  -­  Investments,  for  additional  information  regarding  FEV's  investment  in   Global  Holding.   OFF-­BALANCE  SHEET  ARRANGEMENTS   FES  and  certain  of  the  Ohio  Companies  have  obligations  that  are  not  included  on  their  Consolidated  Balance  Sheets  related  to  the   Perry  Unit  1,  Beaver  Valley  Unit  2,  and  2007  Bruce  Mansfield  Unit  1  sale  and  leaseback  arrangements,  which  are  satisfied  through   operating   lease   payments.   The   total   present   value   of   these   sale   and   leaseback   operating   lease   commitments,   net   of   trust   investments,  was  $950  million  as  of  December  31,  2015  and  primarily  relates  to  the  2007  Bruce  Mansfield  Unit  1  sale  and  leaseback   40   41                                             arrangement  expiring  in  2040.  From  time  to  time  FirstEnergy  and  these  companies  enter  into  discussions  with  certain  parties  to  the   arrangements  regarding  acquisition  of  owner  participant  and  other  interests.  However,  FirstEnergy  cannot  provide  assurance  that  any   such  acquisitions  will  occur  on  satisfactory  terms  or  at  all.   In  February  2014,  NG  purchased  lessor  equity  interests  in  OE's  existing  sale  and  leaseback  of  Beaver  Valley  Unit  2  for  approximately   $94  million.  In  November  2014,  NG  repurchased  lessor  equity  interests  in  OE's  existing  sale  and  leaseback  of  Perry  Unit  1  for   approximately  $87  million.  As  of  December  31,  2015,  FirstEnergy's  leasehold  interest  was  3.75%  of  Perry  Unit  1,  93.83%  of  Bruce   Mansfield  Unit  1  and  2.60%  of  Beaver  Valley  Unit  2.     NDT  funds  have  been  established  to  satisfy  NG’s  and  other  FirstEnergy  subsidiaries'  nuclear  decommissioning  obligations.  As  of   December  31,  2015,  approximately  68%  of  the  funds  were  invested  in  fixed  income  securities,  25%  of  the  funds  were  invested  in   equity  securities  and  7%  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  $1,552  million,  $576  million  and  $147  million  for  fixed   income  securities,  equity  securities  and  short-­term  investments,  respectively,  as  of  December  31,  2015,  excluding  $7  million  of  net   receivables,  payables  and  accrued  income.  A  hypothetical  10%  decrease  in  prices  quoted  by  stock  exchanges  would  result  in  a  $58   million  reduction  in  fair  value  as  of  December  31,  2015.  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  2015,  FirstEnergy  contributed  approximately  $15   On  June  24,  2014,  OE  exercised  its  irrevocable  right  to  repurchase  from  the  remaining  owner  participants  the  lessors'  interests  in   Beaver  Valley  Unit  2  at  the  end  of  the  lease  term  (June  1,  2017),  which  right  to  repurchase  was  assigned  to  NG.  Additionally,  on  June   24,  2014,  NG  entered  into  a  purchase  agreement  with  an  owner  participant  to  purchase  its  lessor  equity  interests  of  the  remaining   non-­affiliated  leasehold  interest  in  Perry  Unit  1  on  May  23,  2016,  which  is  just  prior  to  the  end  of  the  lease  term.     million  to  the  NDT.   Interest  Rate  Risk   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   Management   Committee   is   responsible   for   promoting   the   effective   design   and   implementation   of   sound   risk   management   programs   and   oversees   compliance   with   corporate   risk   management   policies   and   established  risk  management  practice.  FirstEnergy  uses  a  variety  of  derivative  instruments  for  risk  management  purposes  including   forward  contracts,  options,  futures  contracts  and  swaps.   Assets:   Investments  Other  Than  Cash   and  Cash  Equivalents:   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  9,  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,  2015  are  summarized  by  year  in  the  following  table:   Source  of  Information-­   Fair  Value  by  Contract  Year   2016   2017   2018   2019   2020   Thereafter   Total   Prices  actively  quoted(1)   Other  external  sources(2)   Prices  based  on  models   Total(3)   $   $   (6  )   $   18   (4  )   8   $   1   $   (1  )   2   2   $   (In  millions)   —   $   (21  )   —   (21  )   $   —   $   (26  )   —   (26  )   $   —   $   —   (7  )   (7  )   $   —   $   —   —   —   $   (5  )   (30  )   (9  )   (44  )   Liabilities:   Long-­term  Debt:   Fixed  rate   Average  interest  rate   Variable  rate   Average  interest  rate   CREDIT  RISK   credit  risk.   Wholesale  Credit  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   6,   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   2016   2017   2018   2019   2020   There-­ after   Total   Fair   Value   (In  millions)   Fixed  Income   $   5   $   2   $   Average  interest  rate   8.9  %   8.9  %   —   $   —  %   —   $   —  %   —   $   1,794   $   1,801   $   1,802   —  %   3.6  %   3.6  %   $   $   660   $   1,517   $   1,330   $   1,035   $   541   $   13,867   $   18,950   $   20,225   5.5  %   —   $   —  %   6.1  %   2   $   3.5  %   4.8  %   6.5  %   6   $   1,000   $   —  %   2.2  %   5.5  %   200   $   1.9  %   5.2  %   5.3  %   86   $   1,294   $   1,294   —  %   2.0  %   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   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.   FirstEnergy  performs  sensitivity  analyses  to  estimate  its  exposure  to  the  market  risk  of  its  commodity  positions.  Based  on  derivative   contracts  as  of  December  31,  2015,  not  subject  to  regulatory  accounting,  an  increase  in  commodity  prices  of  10%  would  decrease  net   income  by  approximately  $30  million  during  the  next  12  months.   Equity  Price  Risk   As  of  December  31,  2015,  the  FirstEnergy  pension  and  OPEB  plan  assets  were  approximately  allocated  as  follows:  41%  in  equity   securities,  35%  in  fixed  income  securities,  6%  in  absolute  return  strategies,  10%  in  real  estate  and  8%  in  cash  and  short-­term   securities.  A  decline  in  the  value  of  plan  assets  could  result  in  additional  funding  requirements.  FirstEnergy’s  funding  policy  is  based   on  actuarial  computations  using  the  projected  unit  credit  method.  During  the  year  ended  December  31,  2015,  FirstEnergy  made  a   $143  million  contribution  to  its  qualified  pension  plan.  See  Note  3,  Pension  and  Other  Postemployment  Benefits,  of  the  Combined   Notes  to  Consolidated  Financial  Statements  for  additional  details  on  FirstEnergy's  pension  plans  and  OPEB.  In  2015,  FirstEnergy's   pension  plan  and  OPEB  assets  incurred  losses  of  $(172)  million,  or  (2.7)%,  as  compared  to  an  expected  return  on  plan  assets  of   7.75%.     42   43   Includes  $(136)  million  in  non-­hedge  derivative  contracts  that  are  primarily  related  to  NUG  contracts  at  certain  of  the  Utilities.  NUG  contracts  are   subject  to  regulatory  accounting  and  do  not  impact  earnings.   (1)   (2)   Primarily  represents  contracts  based  on  broker  and  ICE  quotes.   (3)    Represents  exchange  traded  New  York  Mercantile  Exchange  futures  and  options.                                                     arrangement  expiring  in  2040.  From  time  to  time  FirstEnergy  and  these  companies  enter  into  discussions  with  certain  parties  to  the   arrangements  regarding  acquisition  of  owner  participant  and  other  interests.  However,  FirstEnergy  cannot  provide  assurance  that  any   such  acquisitions  will  occur  on  satisfactory  terms  or  at  all.   In  February  2014,  NG  purchased  lessor  equity  interests  in  OE's  existing  sale  and  leaseback  of  Beaver  Valley  Unit  2  for  approximately   $94  million.  In  November  2014,  NG  repurchased  lessor  equity  interests  in  OE's  existing  sale  and  leaseback  of  Perry  Unit  1  for   approximately  $87  million.  As  of  December  31,  2015,  FirstEnergy's  leasehold  interest  was  3.75%  of  Perry  Unit  1,  93.83%  of  Bruce   Mansfield  Unit  1  and  2.60%  of  Beaver  Valley  Unit  2.     On  June  24,  2014,  OE  exercised  its  irrevocable  right  to  repurchase  from  the  remaining  owner  participants  the  lessors'  interests  in   Beaver  Valley  Unit  2  at  the  end  of  the  lease  term  (June  1,  2017),  which  right  to  repurchase  was  assigned  to  NG.  Additionally,  on  June   24,  2014,  NG  entered  into  a  purchase  agreement  with  an  owner  participant  to  purchase  its  lessor  equity  interests  of  the  remaining   non-­affiliated  leasehold  interest  in  Perry  Unit  1  on  May  23,  2016,  which  is  just  prior  to  the  end  of  the  lease  term.     FirstEnergy  uses  various  market  risk  sensitive  instruments,  including  derivative  contracts,  primarily  to  manage  the  risk  of  price  and   interest  rate  fluctuations.  FirstEnergy’s  Risk  Policy  Committee,  comprised  of  members  of  senior  management,  provides  general   oversight  for  risk  management  activities  throughout  the  company.   MARKET  RISK  INFORMATION   Commodity  Price  Risk   FirstEnergy  is  exposed  to  financial  risks  resulting  from  fluctuating  commodity  prices,  including  prices  for  electricity,  natural  gas,  coal   and   energy   transmission.   FirstEnergy's   Risk   Management   Committee   is   responsible   for   promoting   the   effective   design   and   implementation   of   sound   risk   management   programs   and   oversees   compliance   with   corporate   risk   management   policies   and   established  risk  management  practice.  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  9,  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,  2015  are  summarized  by  year  in  the  following  table:   Source  of  Information-­   Fair  Value  by  Contract  Year   Prices  actively  quoted(1)   Other  external  sources(2)   Prices  based  on  models   Total(3)   (1)   (3)   Equity  Price  Risk   2016   2017   2018   2019   2020   Thereafter   Total   $   $   (6  )   $   18   (4  )   8   $   1   $   (1  )   2   2   $   (In  millions)   —   $   —   $   (21  )   —   (26  )   —   (21  )   $   (26  )   $   —   $   —   (7  )   (7  )   $   —   $   —   —   —   $   (5  )   (30  )   (9  )   (44  )    Represents  exchange  traded  New  York  Mercantile  Exchange  futures  and  options.   (2)   Primarily  represents  contracts  based  on  broker  and  ICE  quotes.   Includes  $(136)  million  in  non-­hedge  derivative  contracts  that  are  primarily  related  to  NUG  contracts  at  certain  of  the  Utilities.  NUG  contracts  are   subject  to  regulatory  accounting  and  do  not  impact  earnings.   FirstEnergy  performs  sensitivity  analyses  to  estimate  its  exposure  to  the  market  risk  of  its  commodity  positions.  Based  on  derivative   contracts  as  of  December  31,  2015,  not  subject  to  regulatory  accounting,  an  increase  in  commodity  prices  of  10%  would  decrease  net   income  by  approximately  $30  million  during  the  next  12  months.   As  of  December  31,  2015,  the  FirstEnergy  pension  and  OPEB  plan  assets  were  approximately  allocated  as  follows:  41%  in  equity   securities,  35%  in  fixed  income  securities,  6%  in  absolute  return  strategies,  10%  in  real  estate  and  8%  in  cash  and  short-­term   securities.  A  decline  in  the  value  of  plan  assets  could  result  in  additional  funding  requirements.  FirstEnergy’s  funding  policy  is  based   on  actuarial  computations  using  the  projected  unit  credit  method.  During  the  year  ended  December  31,  2015,  FirstEnergy  made  a   $143  million  contribution  to  its  qualified  pension  plan.  See  Note  3,  Pension  and  Other  Postemployment  Benefits,  of  the  Combined   Notes  to  Consolidated  Financial  Statements  for  additional  details  on  FirstEnergy's  pension  plans  and  OPEB.  In  2015,  FirstEnergy's   pension  plan  and  OPEB  assets  incurred  losses  of  $(172)  million,  or  (2.7)%,  as  compared  to  an  expected  return  on  plan  assets  of   7.75%.     NDT  funds  have  been  established  to  satisfy  NG’s  and  other  FirstEnergy  subsidiaries'  nuclear  decommissioning  obligations.  As  of   December  31,  2015,  approximately  68%  of  the  funds  were  invested  in  fixed  income  securities,  25%  of  the  funds  were  invested  in   equity  securities  and  7%  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  $1,552  million,  $576  million  and  $147  million  for  fixed   income  securities,  equity  securities  and  short-­term  investments,  respectively,  as  of  December  31,  2015,  excluding  $7  million  of  net   receivables,  payables  and  accrued  income.  A  hypothetical  10%  decrease  in  prices  quoted  by  stock  exchanges  would  result  in  a  $58   million  reduction  in  fair  value  as  of  December  31,  2015.  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  2015,  FirstEnergy  contributed  approximately  $15   million  to  the  NDT.   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   6,   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   2016   2017   2018   2019   2020   There-­ after   Total   Fair   Value   (In  millions)   Assets:   Investments  Other  Than  Cash   and  Cash  Equivalents:   Fixed  Income   $   Average  interest  rate   Liabilities:   Long-­term  Debt:   Fixed  rate   Average  interest  rate   Variable  rate   Average  interest  rate   CREDIT  RISK   $   $   $   5   8.9  %   $   2   8.9  %   $   —   —  %   $   —   —  %   —   —  %   $   1,794   3.6  %   $   1,801   $   3.6  %   1,802   660   5.5  %   —   —  %   $   $   1,517   $   1,330   $   1,035   $   $   13,867   $   18,950   $   20,225   6.1  %   2   3.5  %   $   4.8  %   6   —  %   $   1,000   $   6.5  %   2.2  %   5.2  %   86   —  %   $   1,294   5.3  %   $   2.0  %   1,294   541   5.5  %   200   1.9  %   $   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.   42   43                                                     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.   NEW  JERSEY   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,  Illinois,  Michigan,  New  Jersey  and   Maryland,  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.   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  by  10%   and  reduce  electricity  demand  by  15%,  in  each  case  by  2015,  and  requiring  each  electric  utility  to  file  a  plan  every  three  years.  PE's   current  plan,  covering  the  three-­year  period  2015-­2017,  was  approved  by  the  MDPSC  on  December  23,  2014.  The  costs  of  the  2015-­ 2017   plan   are   expected   to   be   approximately   $66   million   for   that   three-­year   period,   of   which   $19   million   was   incurred   through   December  2015.  On  July  16,  2015,  the  MDPSC  issued  an  order  setting  new  incremental  energy  savings  goals  for  2017  and  beyond,   beginning  with  the  level  of  savings  achieved  under  PE's  current  plan  for  2016,  and  ramping  up  0.2%  per  year  thereafter  to  reach  2%.   PE  continues  to  recover  program  costs  subject  to  a  five-­year  amortization.  Maryland  law  only  allows  for  the  utility  to  recover  lost   distribution  revenue  attributable  to  energy  efficiency  or  demand  reduction  programs  through  a  base  rate  case  proceeding,  and  to   date,  such  recovery  has  not  been  sought  or  obtained  by  PE.  On  January  28,  2016,  PE  filed  a  request  to  increase  plan  spending  by  $2   million  in  order  to  reach  the  new  goals  for  2017  set  in  the  July  16,  2015  order.     On   February   27,   2013,   the   MDPSC   issued   an   order   (the   February   27   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.  The  order  further  required  the  Staff  of  the  MDPSC  to  report  on  possible  performance-­based  rate  structures  and  to   propose  additional  rules  relating  to  feeder  performance  standards,  outage  communication  and  reporting,  and  sharing  of  special  needs   customer  information.  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  27  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  27  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.  The  Staff  of  the  MDPSC  also  recommended  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  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  yet  issued  a  ruling   on  any  of  those  matters.   On  March  3,  2014,  pursuant  to  the  MDPSC's  regulations,  PE  filed  its  recommendations  for  SAIDI  and  SAIFI  standards  to  apply  during   the  period  2016-­2019.  The  MDPSC  directed  the  Staff  of  the  MDPSC  to  file  an  analysis  and  recommendations  with  respect  to  the   proposed  2016-­2019  SAIDI  and  SAIFI  standards  and  any  related  rule  changes  which  the  Staff  of  the  MDPSC  recommended.  The   Staff   of   the   MDPSC   made   its   filing   on   July   10,   2015,   and   recommended   that   PE   be   required   to   improve   its   SAIDI   results   by   approximately  20%  by  2019.  The  MDPSC  held  a  hearing  on  the  Staff's  analysis  and  recommendations  on  September  1-­2,  2015,  and   approved  PE's  revised  proposal  for  an  improvement  of  8.6%  in  its  SAIDI  standard  by  2019  and  maintained  its  SAIFI  standard  at  2015   levels. The  proposed  regulations  incorporating  the  new  SAIDI  and  SAIFI  standards  were  approved  as  final  in  December  2015.   On  April  1,  2015,  PE  filed  its  annual  report  on  its  performance  relative  to  various  service  reliability  standards  set  forth  in  the  MDPSC’s   regulations.  The  MDPSC  conducted  hearings  on  the  reports  filed  by  PE  and  the  other  electric  utilities  in  Maryland  on  August  24,  2015   and  subsequently  closed  its  2014  service  reliability  review.     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.   On  March  26,  2015,  the  NJBPU  entered  final  orders  which  together  provided  an  overall  reduction  in  JCP&L's  annual  revenues  of   approximately  $34  million,  effective  April  1,  2015.  The  final  order  in  JCP&L's  base  rate  case  proceeding  directed  an  annual  base  rate   revenue  reduction  of  approximately  $115  million,  including  recovery  of  2011  storm  costs  and  the  application  of  the  NJBPU's  modified   CTA   policy   approved   in   the   generic   CTA   proceeding   referred   to   below.  Additionally,   the   final   order   in   the   generic   proceeding   established  to  review  JCP&L's  major  storm  events  of  2011  and  2012  approved  the  recovery  of  2012  storm  costs  of  $580  million   resulting  in  an  increase  in  annual  revenues  of  approximately  $81  million.  JCP&L  is  required  to  file  another  base  rate  case  no  later   than  April  1,  2017.  The  NJBPU  also  directed  that  certain  studies  be  completed.  On  July  22,  2015,  the  NJBPU  approved  the  NJBPU   staff's  recommendation  to  implement  such  studies,  which  will  include  operational  and  financial  components  and  is  expected  to  take   approximately  one  year  to  complete.     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  (Generic  CTA  proceeding),  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  New  Jersey  Superior  Court  and  JCP&L  has  filed  to  participate  as  a  respondent  in   that  proceeding.  Briefing  has  been  completed,  and  oral  argument  has  not  yet  been  scheduled.   On  June  19,  2015,  JCP&L,  along  with  PN,  ME,  FET  and  MAIT  made  filings  with  FERC,  the  NJBPU,  and  the  PPUC  requesting   authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT,  a  new  transmission-­only  subsidiary  of  FET.  On   January  8,  2016,  the  NJBPU  President  issued  an  Order  granting  Rate  Counsel’s  Motion  on  the  legal  issue  of  whether  MAIT  can  be   designated  as  a  public  utility.  The  procedural  schedule  has  been  suspended  until  a  decision  is  made  on  this  issue.  See  Transfer  of   Transmission  Assets  to  MAIT  in  FERC  Matters  below  for  further  discussion  of  this  transaction.   OHIO   prior  ESP;;   The  Ohio  Companies  operate  under  their  ESP  3  plan  which  expires  on  May  31,  2016.  The  material  terms  of  ESP  3  include:   •     A  base  distribution  rate  freeze  through  May  31,  2016;;   •     Collection  of  lost  distribution  revenues  associated  with  energy  efficiency  and  peak  demand  reduction  programs;;   •     Economic  development  and  assistance  to  low-­income  customers  for  the  two-­year  plan  period  at  levels  established  in  the   •     A   6%   generation   rate   discount   to   certain   low   income   customers   provided   by   the   Ohio   Companies   through   a   bilateral   wholesale  contract  with  FES  (FES  is  one  of  the  wholesale  suppliers  to  the  Ohio  Companies);;   •     A  requirement  to  provide  power  to  non-­shopping  customers  at  a  market-­based  price  set  through  an  auction  process;;   •     Rider  DCR  that  allows  continued  investment  in  the  distribution  system  for  the  benefit  of  customers;;   •     A  commitment  not  to  recover  from  retail  customers  certain  costs  related  to  transmission  cost  allocations  for  the  longer  of  the   five-­year  period  from  June  1,  2011  through  May  31,  2016  or  when  the  amount  of  costs  avoided  by  customers  for  certain   types  of  products  totals  $360  million,  subject  to  the  outcome  of  certain  FERC  proceedings;;   •     Securing  generation  supply  for  a  longer  period  of  time  by  conducting  an  auction  for  a  three-­year  period  rather  than  a  one-­ year  period,  in  each  of  October  2012  and  January  2013,  to  mitigate  any  potential  price  spikes  for  the  Ohio  Companies'  utility   customers  who  do  not  switch  to  a  competitive  generation  supplier;;  and   •     Extending  the  recovery  period  for  costs  associated  with  purchasing  RECs  mandated  by  SB221,  Ohio's  renewable  energy   and  energy  efficiency  standard,  through  the  end  of  the  new  ESP  3  period.  This  is  expected  to  initially  reduce  the  monthly   renewable  energy  charge  for  all  non-­shopping  utility  customers  of  the  Ohio  Companies  by  spreading  out  the  costs  over  the   entire  ESP  period.   Notices  of  appeal  of  the  Ohio  Companies'  ESP  3  plan  to  the  Supreme  Court  of  Ohio  were  filed  by  the  Northeast  Ohio  Public  Energy   Council  and  the  ELPC.  The  oral  argument  in  this  matter  occurred  on  January  6,  2016.     The  Ohio  Companies  filed  an  application  with  the  PUCO  on  August  4,  2014  seeking  approval  of  their  ESP  IV  entitled  Powering  Ohio's   Progress.  The  Ohio  Companies  filed  a  Stipulation  and  Recommendation  on  December  22,  2014,  and  supplemental  stipulations  and   recommendations  on  May  28,  2015,  and  June  4,  2015.The  evidentiary  hearing  on  the  ESP  IV  commenced  on  August  31,  2015  and   concluded   on   October   29,   2015.   On   December   1,   2015,   the   Ohio   Companies   filed   a   Third   Supplemental   Stipulation   and   Recommendation,  which  included  PUCO  Staff  as  a  signatory  party  in  addition  to  other  signatories.    The  PUCO  completed  a  hearing   44   45                                                 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   NEW  JERSEY   conditions,  FirstEnergy's  retail  credit  risk  may  be  adversely  impacted.   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,  Illinois,  Michigan,  New  Jersey  and   Maryland,  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.   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  by  10%   and  reduce  electricity  demand  by  15%,  in  each  case  by  2015,  and  requiring  each  electric  utility  to  file  a  plan  every  three  years.  PE's   current  plan,  covering  the  three-­year  period  2015-­2017,  was  approved  by  the  MDPSC  on  December  23,  2014.  The  costs  of  the  2015-­ 2017   plan   are   expected   to   be   approximately   $66   million   for   that   three-­year   period,   of   which   $19   million   was   incurred   through   December  2015.  On  July  16,  2015,  the  MDPSC  issued  an  order  setting  new  incremental  energy  savings  goals  for  2017  and  beyond,   beginning  with  the  level  of  savings  achieved  under  PE's  current  plan  for  2016,  and  ramping  up  0.2%  per  year  thereafter  to  reach  2%.   PE  continues  to  recover  program  costs  subject  to  a  five-­year  amortization.  Maryland  law  only  allows  for  the  utility  to  recover  lost   distribution  revenue  attributable  to  energy  efficiency  or  demand  reduction  programs  through  a  base  rate  case  proceeding,  and  to   date,  such  recovery  has  not  been  sought  or  obtained  by  PE.  On  January  28,  2016,  PE  filed  a  request  to  increase  plan  spending  by  $2   million  in  order  to  reach  the  new  goals  for  2017  set  in  the  July  16,  2015  order.     On   February   27,   2013,   the   MDPSC   issued   an   order   (the   February   27   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.  The  order  further  required  the  Staff  of  the  MDPSC  to  report  on  possible  performance-­based  rate  structures  and  to   propose  additional  rules  relating  to  feeder  performance  standards,  outage  communication  and  reporting,  and  sharing  of  special  needs   customer  information.  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  27  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  27  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.  The  Staff  of  the  MDPSC  also  recommended  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  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  yet  issued  a  ruling   on  any  of  those  matters.   On  March  3,  2014,  pursuant  to  the  MDPSC's  regulations,  PE  filed  its  recommendations  for  SAIDI  and  SAIFI  standards  to  apply  during   the  period  2016-­2019.  The  MDPSC  directed  the  Staff  of  the  MDPSC  to  file  an  analysis  and  recommendations  with  respect  to  the   proposed  2016-­2019  SAIDI  and  SAIFI  standards  and  any  related  rule  changes  which  the  Staff  of  the  MDPSC  recommended.  The   Staff   of   the   MDPSC   made   its   filing   on   July   10,   2015,   and   recommended   that   PE   be   required   to   improve   its   SAIDI   results   by   approximately  20%  by  2019.  The  MDPSC  held  a  hearing  on  the  Staff's  analysis  and  recommendations  on  September  1-­2,  2015,  and   approved  PE's  revised  proposal  for  an  improvement  of  8.6%  in  its  SAIDI  standard  by  2019  and  maintained  its  SAIFI  standard  at  2015   levels. The  proposed  regulations  incorporating  the  new  SAIDI  and  SAIFI  standards  were  approved  as  final  in  December  2015.   On  April  1,  2015,  PE  filed  its  annual  report  on  its  performance  relative  to  various  service  reliability  standards  set  forth  in  the  MDPSC’s   regulations.  The  MDPSC  conducted  hearings  on  the  reports  filed  by  PE  and  the  other  electric  utilities  in  Maryland  on  August  24,  2015   and  subsequently  closed  its  2014  service  reliability  review.     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.   On  March  26,  2015,  the  NJBPU  entered  final  orders  which  together  provided  an  overall  reduction  in  JCP&L's  annual  revenues  of   approximately  $34  million,  effective  April  1,  2015.  The  final  order  in  JCP&L's  base  rate  case  proceeding  directed  an  annual  base  rate   revenue  reduction  of  approximately  $115  million,  including  recovery  of  2011  storm  costs  and  the  application  of  the  NJBPU's  modified   CTA   policy   approved   in   the   generic   CTA   proceeding   referred   to   below.  Additionally,   the   final   order   in   the   generic   proceeding   established  to  review  JCP&L's  major  storm  events  of  2011  and  2012  approved  the  recovery  of  2012  storm  costs  of  $580  million   resulting  in  an  increase  in  annual  revenues  of  approximately  $81  million.  JCP&L  is  required  to  file  another  base  rate  case  no  later   than  April  1,  2017.  The  NJBPU  also  directed  that  certain  studies  be  completed.  On  July  22,  2015,  the  NJBPU  approved  the  NJBPU   staff's  recommendation  to  implement  such  studies,  which  will  include  operational  and  financial  components  and  is  expected  to  take   approximately  one  year  to  complete.     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  (Generic  CTA  proceeding),  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  New  Jersey  Superior  Court  and  JCP&L  has  filed  to  participate  as  a  respondent  in   that  proceeding.  Briefing  has  been  completed,  and  oral  argument  has  not  yet  been  scheduled.   On  June  19,  2015,  JCP&L,  along  with  PN,  ME,  FET  and  MAIT  made  filings  with  FERC,  the  NJBPU,  and  the  PPUC  requesting   authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT,  a  new  transmission-­only  subsidiary  of  FET.  On   January  8,  2016,  the  NJBPU  President  issued  an  Order  granting  Rate  Counsel’s  Motion  on  the  legal  issue  of  whether  MAIT  can  be   designated  as  a  public  utility.  The  procedural  schedule  has  been  suspended  until  a  decision  is  made  on  this  issue.  See  Transfer  of   Transmission  Assets  to  MAIT  in  FERC  Matters  below  for  further  discussion  of  this  transaction.   OHIO   The  Ohio  Companies  operate  under  their  ESP  3  plan  which  expires  on  May  31,  2016.  The  material  terms  of  ESP  3  include:   •     A  base  distribution  rate  freeze  through  May  31,  2016;;   •     Collection  of  lost  distribution  revenues  associated  with  energy  efficiency  and  peak  demand  reduction  programs;;   •     Economic  development  and  assistance  to  low-­income  customers  for  the  two-­year  plan  period  at  levels  established  in  the   prior  ESP;;   •     A   6%   generation   rate   discount   to   certain   low   income   customers   provided   by   the   Ohio   Companies   through   a   bilateral   wholesale  contract  with  FES  (FES  is  one  of  the  wholesale  suppliers  to  the  Ohio  Companies);;   •     A  requirement  to  provide  power  to  non-­shopping  customers  at  a  market-­based  price  set  through  an  auction  process;;   •     Rider  DCR  that  allows  continued  investment  in  the  distribution  system  for  the  benefit  of  customers;;   •     A  commitment  not  to  recover  from  retail  customers  certain  costs  related  to  transmission  cost  allocations  for  the  longer  of  the   five-­year  period  from  June  1,  2011  through  May  31,  2016  or  when  the  amount  of  costs  avoided  by  customers  for  certain   types  of  products  totals  $360  million,  subject  to  the  outcome  of  certain  FERC  proceedings;;   •     Securing  generation  supply  for  a  longer  period  of  time  by  conducting  an  auction  for  a  three-­year  period  rather  than  a  one-­ year  period,  in  each  of  October  2012  and  January  2013,  to  mitigate  any  potential  price  spikes  for  the  Ohio  Companies'  utility   customers  who  do  not  switch  to  a  competitive  generation  supplier;;  and   •     Extending  the  recovery  period  for  costs  associated  with  purchasing  RECs  mandated  by  SB221,  Ohio's  renewable  energy   and  energy  efficiency  standard,  through  the  end  of  the  new  ESP  3  period.  This  is  expected  to  initially  reduce  the  monthly   renewable  energy  charge  for  all  non-­shopping  utility  customers  of  the  Ohio  Companies  by  spreading  out  the  costs  over  the   entire  ESP  period.   Notices  of  appeal  of  the  Ohio  Companies'  ESP  3  plan  to  the  Supreme  Court  of  Ohio  were  filed  by  the  Northeast  Ohio  Public  Energy   Council  and  the  ELPC.  The  oral  argument  in  this  matter  occurred  on  January  6,  2016.     The  Ohio  Companies  filed  an  application  with  the  PUCO  on  August  4,  2014  seeking  approval  of  their  ESP  IV  entitled  Powering  Ohio's   Progress.  The  Ohio  Companies  filed  a  Stipulation  and  Recommendation  on  December  22,  2014,  and  supplemental  stipulations  and   recommendations  on  May  28,  2015,  and  June  4,  2015.The  evidentiary  hearing  on  the  ESP  IV  commenced  on  August  31,  2015  and   concluded   on   October   29,   2015.   On   December   1,   2015,   the   Ohio   Companies   filed   a   Third   Supplemental   Stipulation   and   Recommendation,  which  included  PUCO  Staff  as  a  signatory  party  in  addition  to  other  signatories.    The  PUCO  completed  a  hearing   44   45                                                 on  the  Third  Supplemental  Stipulation  and  Recommendation  in  January  2016.  Initial  briefs  are  due  on  February  16,  2016  and  reply   briefs  are  due  on  February  26,  2016.    A  final  PUCO  decision  is  expected  in  March  2016.       specified  in  those  applications.   plan.  Several  applications  for  rehearing  were  filed,  and  the  PUCO  granted  those  applications  for  further  consideration  of  the  matters   The  proposed  ESP  IV  supports  FirstEnergy's  strategic  focus  on  regulated  operations  and  better  positions  the  Ohio  Companies  to   deliver  on  their  ongoing  commitment  to  upgrade,  modernize  and  maintain  reliable  electric  service  for  customers  while  preserving   electric  security  in  Ohio.  The  material  terms  of  the  proposed  ESP  IV,  as  modified  by  the  stipulations  include:     On  September  16,  2013,  the  Ohio  Companies  filed  with  the  Supreme  Court  of  Ohio  a  notice  of  appeal  of  the  PUCO's  July  17,  2013   Entry  on  Rehearing  related  to  energy  efficiency,  alternative  energy,  and  long-­term  forecast  rules  stating  that  the  rules  issued  by  the   PUCO  are  inconsistent  with,  and  are  not  supported  by,  statutory  authority.  On  October  23,  2013,  the  PUCO  filed  a  motion  to  dismiss   •   An  eight-­year  term  (June  1,  2016  -­  May  31,  2024);;   •     Contemplates  continuing  a  base  distribution  rate  freeze  through  May  31,  2024;;   •     An  Economic  Stability  Program  that  flows  through  charges  or  credits  through  Rider  RRS  representing  the  net  result  of  the   price  paid  to  FES  through  a  proposed  eight-­year  FERC-­jurisdictional  PPA  for  the  output  of  the  Sammis  and  Davis-­Besse   plants  and  FES’  share  of  OVEC  against  the  revenues  received  from  selling  such  output  into  the  PJM  markets  over  the  same   period,  subject  to  the  PUCO’s  termination  of  Rider  RRS  charges/credits  associated  with  any  plants  or  units  that  may  be  sold   or  transferred;;     •     Continuing  to  provide  power  to  non-­shopping  customers  at  a  market-­based  price  set  through  an  auction  process;;   •     Continuing  Rider  DCR  with  increased  revenue  caps  of  approximately  $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  that  supports  continued  investment  related  to  the  distribution  system  for  the  benefit  of  customers;;     •     Collection  of  lost  distribution  revenues  associated  with  energy  efficiency  and  peak  demand  reduction  programs;;     •     A  risk-­sharing  mechanism  that  would  provide  guaranteed  credits  under  Rider  RRS  in  years  five  through  eight  to  customers     as  follows:  $10  million  in  year  five,  $20  million  in  year  six,  $30  million  in  year  seven  and  $40  million  in  year  eight;;   •     A  continuing  commitment  not  to  recover  from  retail  customers  certain  costs  related  to  transmission  cost  allocations  for   the  longer  of  the  five-­year  period  from  June  1,  2011  through  May  31,  2016  or  when  the  amount  of  such  costs  avoided   by  customers  for  certain  types  of  products  totals  $360  million,  including  such  costs  from  MISO  along  with  such  costs   from  PJM,  subject  to  the  outcome  of  certain  FERC  proceedings;;   •     Potential  procurement  of  100  MW  of  new  Ohio  wind  or  solar  resources  subject  to  a  demonstrated  need  to  procure  new   renewable  energy  resources  as  part  of  a  strategy  to  further  diversify  Ohio's  energy  portfolio;;     •     An  agreement  to  file  a  case  with  the  PUCO  by  April  3,  2017,  seeking  to  transition  to  decoupled  base  rates  for  residential   the  appeal,  which  is  still  pending.  The  matter  has  not  been  scheduled  for  oral  argument.   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,  subject  to  legislative  amendments  discussed  above,  except   2015  and  2016  that  remain  at  the  2014  level.  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.  On  February  18,   2014,  the  OCC  and  the  ELPC  also  filed  appeals  of  the  PUCO's  order.  The  Ohio  Companies  timely  filed  their  merit  brief  with  the   Supreme  Court  of  Ohio  and  the  briefing  process  has  concluded.  The  matter  is  not  yet  scheduled  for  oral  argument.   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.     customers;;     PENNSYLVANIA   •     An  agreement  to  file  by  February  29,  2016,  a  Grid  Modernization  Business  Plan  for  PUCO  consideration  and  approval;;   •   A  contribution  of  $3  million  per  year  ($24  million  over  the  eight  year  term)  to  fund  energy  conservation  programs,   economic  development  and  job  retention  in  the  Ohio  Companies  service  territory;;   •     Contributions  of  $2.4  million  per  year  ($19  million  over  the  eight  year  term)  to  fund  a  fuel-­fund  in  each  of  the  Ohio   Companies  service  territories  to  assist  low-­income  customers;;  and     The   Pennsylvania   Companies   currently   operate   under   DSPs   that   expire   on   May   31,   2017,   and   provide   for   the   competitive   procurement  of  generation  supply  for  customers  that  do  not  choose  an  alternative  EGS  or  for  customers  of  alternative  EGSs  that  fail   to  provide  the  contracted  service.  The  default  service  supply  is  currently  provided  by  wholesale  suppliers  through  a  mix  of  long-­term   and  short-­term  contracts  procured  through  spot  market  purchases,  quarterly  descending  clock  auctions  for  3,  12-­  and  24-­month   •     A  contribution  of  $1  million  per  year  ($8  million  over  the  eight  year  term)  to  establish  a  Customary  Advisory  Council  to   energy  contracts,  and  one  RFP  seeking  2-­year  contracts  to  serve  SRECs  for  ME,  PN  and  Penn.   ensure  preservation  and  growth  of  the  competitive  market  in  Ohio.     On  January  27,  2016,  certain  parties  filed  a  complaint  at  FERC  against  FES,  OE,  CEI,  and  TE  that  requests  FERC  review  of  the  ESP   IV  PPA  under  Section  205  of  the  FPA.  In  addition  to  such  proceeding,  parties  have  expressed  an  intention  to  challenge  in  the  courts   and/or  before  FERC,  the  PPA  or  PUCO  approval  of  the  ESP  IV,  if  approved.  Management  intends  to  vigorously  defend  against  such   challenges.     Under  Ohio's  energy  efficiency  standards  (SB221  and  SB310),  and  based  on  the  Ohio  Companies'  amended  energy  efficiency  plans,   the  Ohio  Companies  are  required  to  implement  energy  efficiency  programs  that  achieve  a  total  annual  energy  savings  equivalent  of   2,266   GWHs   in   2015   and   2,288   GWHs   in   2016,   and   then   begin   to   increase   by   1%   each   year   in   2017,   subject   to   legislative   amendments  to  the  energy  efficiency  standards  discussed  below.    The  Ohio  Companies  are  also  required  to  retain  the  2014  peak   demand  reduction  level  for  2015  and  2016  and  then  increase  the  benchmark  by  an  additional 0.75%  thereafter  through  2020,  subject   to  legislative  amendments  to  the  peak  demand  reduction  standards  discussed  below.   On  September  30,  2015,  the  Energy  Mandates  Study  Committee  issued  its  report  related  to  energy  efficiency  and  renewable  energy   mandates,  recommending  that  the  current  level  of  mandates  remain  in  place  indefinitely.  The  report  also  recommended:  (i)  an   expedited   process   for   review   of   utility   proposed   energy   efficiency   plans;;   (ii)   ensuring   maximum   credit   for   all   of   Ohio's   Energy   Initiatives;;  (iii)  a  switch  from  energy  mandates  to  energy  incentives;;  and  (iv)  a  declaration  be  made  that  the  General  Assembly  may   determine  energy  policy  of  the  state.  No  legislation  has  yet  been  introduced  to  change  the  standards  described  above.   On  March  20,  2013,  the  PUCO  approved  the  three-­year  energy  efficiency  portfolio  plans  for  2013-­2015,  originally  estimated  to  cost   the  Ohio  Companies  approximately  $250  million  over  the  three-­year  period,  which  is  expected  to  be  recovered  in  rates.  Actual  costs   may  be  lower  for  a  number  of  reasons  including  the  approval  of  the  amended  portfolio  plan  under  SB310.  On  July  17,  2013,  the   PUCO  modified  the  plan  to  authorize  the  Ohio  Companies  to  receive  20%  of  any  revenues  obtained  from  offering  energy  efficiency   and  DR  reserves  into  the  PJM  auction.  The  PUCO  also  confirmed  that  the  Ohio  Companies  can  recover  PJM  costs  and  applicable   penalties  associated  with  PJM  auctions,  including  the  costs  of  purchasing  replacement  capacity  from  PJM  incremental  auctions,  to   the  extent  that  such  costs  or  penalties  are  prudently  incurred.  ELPC  and  OCC  filed  applications  for  rehearing,  which  were  granted  for   the  sole  purpose  of  further  consideration  of  the  issue.  On  September  24,  2014,  the  Ohio  Companies  filed  an  amendment  to  their   portfolio  plan  as  contemplated  by  SB310,  seeking  to  suspend  certain  programs  for  the  2015-­2016  period  in  order  to  better  align  the   plan  with  the  new  benchmarks  under  SB310.  On  November  20,  2014,  the  PUCO  approved  the  Ohio  Companies'  amended  portfolio   On  November  3,  2015,  the  Pennsylvania  Companies  filed  their  proposed  DSPs  for  the  June  1,  2017  through  May  31,  2019  delivery   period,  which  would  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  proposed  programs,  the  supply  would   be  provided  by  wholesale  suppliers  though  a  mix  of  12  and  24-­month  energy  contracts,  as  well  as  one  RFP  for  2-­year  SREC   contracts  for  ME,  PN  and  Penn.  In  addition,  the  proposal  includes  modifications  to  the  Pennsylvania  Companies’  existing  POR   programs  in  order  to  reduce  the  level  of  uncollectibles  the  Pennsylvania  Companies  experience  associated  with  alternative  EGS   charges.     Pursuant  to  Pennsylvania's  EE&C  legislation  (Act  129  of  2008)  and  PPUC  orders,  Pennsylvania  EDCs  implement  energy  efficiency   and  peak  demand  reduction  programs.  The  Pennsylvania  Companies'  Phase  II  EE&C  Plans  are  effective  through  May  31,  2016.  Total   costs   of   these   plans   are   expected   to   be   approximately   $234   million   and   recoverable   through   the   Pennsylvania   Companies'   reconcilable  EE&C  riders.  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  filed  their  Phase  III  EE&C   plans  for  the  June  2016  through  May  2021  period  on  November  23,  2015,  which  are  designed  to  achieve  the  targets  established  in   the  PPUC's  Phase  III  Final  Implementation  Order.  EDCs  are  permitted  to  recover  costs  for  implementing  their  EE&C  plans.  On   February   10,   2016,   the   Pennsylvania   Companies   and   the   parties   intervening   in   the   PPUC's   Phase   III   proceeding   filed   a   joint   settlement  that  resolves  all  issues  in  the  proceeding  and  is  subject  to  PPUC  approval.       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  October  19,  2015,  each  of  the  Pennsylvania  Companies  filed   LTIIPs  with  the  PPUC  for  infrastructure  improvement  over  the  five-­year  period  of  2016  to  2020  for  the  following  costs:  WP  $88.34   million;;  PN  $56.74  million;;  Penn  $56.35  million;;  and  ME  $43.44  million.  These  amounts  include  all  qualifying  distribution  capital   additions  identified  in  the  revised  implementation  plan  for  the  recent  focused  management  and  operations  audit  of  the  Pennsylvania   Companies  as  discussed  below.  On  February  11,  2016,  the  PPUC  approved  the  Pennsylvania  Companies'  LTIIPs.  On  February  16,   2016,  the  Pennsylvania  Companies  filed  DSIC  riders  for  PPUC  approval  for  quarterly  cost  recovery  associated  with  the  capital   projects  approved  in  the  LTIIPs.  The  DSIC  riders  are  expected  to  be  effective  July  1,  2016.       46   47                                     The  proposed  ESP  IV  supports  FirstEnergy's  strategic  focus  on  regulated  operations  and  better  positions  the  Ohio  Companies  to   deliver  on  their  ongoing  commitment  to  upgrade,  modernize  and  maintain  reliable  electric  service  for  customers  while  preserving   electric  security  in  Ohio.  The  material  terms  of  the  proposed  ESP  IV,  as  modified  by  the  stipulations  include:     •   An  eight-­year  term  (June  1,  2016  -­  May  31,  2024);;   •     Contemplates  continuing  a  base  distribution  rate  freeze  through  May  31,  2024;;   •     An  Economic  Stability  Program  that  flows  through  charges  or  credits  through  Rider  RRS  representing  the  net  result  of  the   price  paid  to  FES  through  a  proposed  eight-­year  FERC-­jurisdictional  PPA  for  the  output  of  the  Sammis  and  Davis-­Besse   plants  and  FES’  share  of  OVEC  against  the  revenues  received  from  selling  such  output  into  the  PJM  markets  over  the  same   period,  subject  to  the  PUCO’s  termination  of  Rider  RRS  charges/credits  associated  with  any  plants  or  units  that  may  be  sold   or  transferred;;     •     Continuing  to  provide  power  to  non-­shopping  customers  at  a  market-­based  price  set  through  an  auction  process;;   •     Continuing  Rider  DCR  with  increased  revenue  caps  of  approximately  $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  that  supports  continued  investment  related  to  the  distribution  system  for  the  benefit  of  customers;;     •     Collection  of  lost  distribution  revenues  associated  with  energy  efficiency  and  peak  demand  reduction  programs;;     •     A  risk-­sharing  mechanism  that  would  provide  guaranteed  credits  under  Rider  RRS  in  years  five  through  eight  to  customers     as  follows:  $10  million  in  year  five,  $20  million  in  year  six,  $30  million  in  year  seven  and  $40  million  in  year  eight;;   •     A  continuing  commitment  not  to  recover  from  retail  customers  certain  costs  related  to  transmission  cost  allocations  for   the  longer  of  the  five-­year  period  from  June  1,  2011  through  May  31,  2016  or  when  the  amount  of  such  costs  avoided   by  customers  for  certain  types  of  products  totals  $360  million,  including  such  costs  from  MISO  along  with  such  costs   from  PJM,  subject  to  the  outcome  of  certain  FERC  proceedings;;   •     Potential  procurement  of  100  MW  of  new  Ohio  wind  or  solar  resources  subject  to  a  demonstrated  need  to  procure  new   renewable  energy  resources  as  part  of  a  strategy  to  further  diversify  Ohio's  energy  portfolio;;     •     An  agreement  to  file  a  case  with  the  PUCO  by  April  3,  2017,  seeking  to  transition  to  decoupled  base  rates  for  residential   •     An  agreement  to  file  by  February  29,  2016,  a  Grid  Modernization  Business  Plan  for  PUCO  consideration  and  approval;;   •   A  contribution  of  $3  million  per  year  ($24  million  over  the  eight  year  term)  to  fund  energy  conservation  programs,   economic  development  and  job  retention  in  the  Ohio  Companies  service  territory;;   •     Contributions  of  $2.4  million  per  year  ($19  million  over  the  eight  year  term)  to  fund  a  fuel-­fund  in  each  of  the  Ohio   Companies  service  territories  to  assist  low-­income  customers;;  and     •     A  contribution  of  $1  million  per  year  ($8  million  over  the  eight  year  term)  to  establish  a  Customary  Advisory  Council  to   ensure  preservation  and  growth  of  the  competitive  market  in  Ohio.     On  January  27,  2016,  certain  parties  filed  a  complaint  at  FERC  against  FES,  OE,  CEI,  and  TE  that  requests  FERC  review  of  the  ESP   IV  PPA  under  Section  205  of  the  FPA.  In  addition  to  such  proceeding,  parties  have  expressed  an  intention  to  challenge  in  the  courts   and/or  before  FERC,  the  PPA  or  PUCO  approval  of  the  ESP  IV,  if  approved.  Management  intends  to  vigorously  defend  against  such   challenges.     Under  Ohio's  energy  efficiency  standards  (SB221  and  SB310),  and  based  on  the  Ohio  Companies'  amended  energy  efficiency  plans,   the  Ohio  Companies  are  required  to  implement  energy  efficiency  programs  that  achieve  a  total  annual  energy  savings  equivalent  of   2,266   GWHs   in   2015   and   2,288   GWHs   in   2016,   and   then   begin   to   increase   by   1%   each   year   in   2017,   subject   to   legislative   amendments  to  the  energy  efficiency  standards  discussed  below.    The  Ohio  Companies  are  also  required  to  retain  the  2014  peak   demand  reduction  level  for  2015  and  2016  and  then  increase  the  benchmark  by  an  additional 0.75%  thereafter  through  2020,  subject   to  legislative  amendments  to  the  peak  demand  reduction  standards  discussed  below.   On  September  30,  2015,  the  Energy  Mandates  Study  Committee  issued  its  report  related  to  energy  efficiency  and  renewable  energy   mandates,  recommending  that  the  current  level  of  mandates  remain  in  place  indefinitely.  The  report  also  recommended:  (i)  an   expedited   process   for   review   of   utility   proposed   energy   efficiency   plans;;   (ii)   ensuring   maximum   credit   for   all   of   Ohio's   Energy   Initiatives;;  (iii)  a  switch  from  energy  mandates  to  energy  incentives;;  and  (iv)  a  declaration  be  made  that  the  General  Assembly  may   determine  energy  policy  of  the  state.  No  legislation  has  yet  been  introduced  to  change  the  standards  described  above.   On  March  20,  2013,  the  PUCO  approved  the  three-­year  energy  efficiency  portfolio  plans  for  2013-­2015,  originally  estimated  to  cost   the  Ohio  Companies  approximately  $250  million  over  the  three-­year  period,  which  is  expected  to  be  recovered  in  rates.  Actual  costs   may  be  lower  for  a  number  of  reasons  including  the  approval  of  the  amended  portfolio  plan  under  SB310.  On  July  17,  2013,  the   PUCO  modified  the  plan  to  authorize  the  Ohio  Companies  to  receive  20%  of  any  revenues  obtained  from  offering  energy  efficiency   and  DR  reserves  into  the  PJM  auction.  The  PUCO  also  confirmed  that  the  Ohio  Companies  can  recover  PJM  costs  and  applicable   penalties  associated  with  PJM  auctions,  including  the  costs  of  purchasing  replacement  capacity  from  PJM  incremental  auctions,  to   the  extent  that  such  costs  or  penalties  are  prudently  incurred.  ELPC  and  OCC  filed  applications  for  rehearing,  which  were  granted  for   the  sole  purpose  of  further  consideration  of  the  issue.  On  September  24,  2014,  the  Ohio  Companies  filed  an  amendment  to  their   portfolio  plan  as  contemplated  by  SB310,  seeking  to  suspend  certain  programs  for  the  2015-­2016  period  in  order  to  better  align  the   plan  with  the  new  benchmarks  under  SB310.  On  November  20,  2014,  the  PUCO  approved  the  Ohio  Companies'  amended  portfolio   on  the  Third  Supplemental  Stipulation  and  Recommendation  in  January  2016.  Initial  briefs  are  due  on  February  16,  2016  and  reply   briefs  are  due  on  February  26,  2016.    A  final  PUCO  decision  is  expected  in  March  2016.       plan.  Several  applications  for  rehearing  were  filed,  and  the  PUCO  granted  those  applications  for  further  consideration  of  the  matters   specified  in  those  applications.   On  September  16,  2013,  the  Ohio  Companies  filed  with  the  Supreme  Court  of  Ohio  a  notice  of  appeal  of  the  PUCO's  July  17,  2013   Entry  on  Rehearing  related  to  energy  efficiency,  alternative  energy,  and  long-­term  forecast  rules  stating  that  the  rules  issued  by  the   PUCO  are  inconsistent  with,  and  are  not  supported  by,  statutory  authority.  On  October  23,  2013,  the  PUCO  filed  a  motion  to  dismiss   the  appeal,  which  is  still  pending.  The  matter  has  not  been  scheduled  for  oral  argument.   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,  subject  to  legislative  amendments  discussed  above,  except   2015  and  2016  that  remain  at  the  2014  level.  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.  On  February  18,   2014,  the  OCC  and  the  ELPC  also  filed  appeals  of  the  PUCO's  order.  The  Ohio  Companies  timely  filed  their  merit  brief  with  the   Supreme  Court  of  Ohio  and  the  briefing  process  has  concluded.  The  matter  is  not  yet  scheduled  for  oral  argument.   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.     customers;;     PENNSYLVANIA   The   Pennsylvania   Companies   currently   operate   under   DSPs   that   expire   on   May   31,   2017,   and   provide   for   the   competitive   procurement  of  generation  supply  for  customers  that  do  not  choose  an  alternative  EGS  or  for  customers  of  alternative  EGSs  that  fail   to  provide  the  contracted  service.  The  default  service  supply  is  currently  provided  by  wholesale  suppliers  through  a  mix  of  long-­term   and  short-­term  contracts  procured  through  spot  market  purchases,  quarterly  descending  clock  auctions  for  3,  12-­  and  24-­month   energy  contracts,  and  one  RFP  seeking  2-­year  contracts  to  serve  SRECs  for  ME,  PN  and  Penn.   On  November  3,  2015,  the  Pennsylvania  Companies  filed  their  proposed  DSPs  for  the  June  1,  2017  through  May  31,  2019  delivery   period,  which  would  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  proposed  programs,  the  supply  would   be  provided  by  wholesale  suppliers  though  a  mix  of  12  and  24-­month  energy  contracts,  as  well  as  one  RFP  for  2-­year  SREC   contracts  for  ME,  PN  and  Penn.  In  addition,  the  proposal  includes  modifications  to  the  Pennsylvania  Companies’  existing  POR   programs  in  order  to  reduce  the  level  of  uncollectibles  the  Pennsylvania  Companies  experience  associated  with  alternative  EGS   charges.     Pursuant  to  Pennsylvania's  EE&C  legislation  (Act  129  of  2008)  and  PPUC  orders,  Pennsylvania  EDCs  implement  energy  efficiency   and  peak  demand  reduction  programs.  The  Pennsylvania  Companies'  Phase  II  EE&C  Plans  are  effective  through  May  31,  2016.  Total   costs   of   these   plans   are   expected   to   be   approximately   $234   million   and   recoverable   through   the   Pennsylvania   Companies'   reconcilable  EE&C  riders.  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  filed  their  Phase  III  EE&C   plans  for  the  June  2016  through  May  2021  period  on  November  23,  2015,  which  are  designed  to  achieve  the  targets  established  in   the  PPUC's  Phase  III  Final  Implementation  Order.  EDCs  are  permitted  to  recover  costs  for  implementing  their  EE&C  plans.  On   February   10,   2016,   the   Pennsylvania   Companies   and   the   parties   intervening   in   the   PPUC's   Phase   III   proceeding   filed   a   joint   settlement  that  resolves  all  issues  in  the  proceeding  and  is  subject  to  PPUC  approval.       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  October  19,  2015,  each  of  the  Pennsylvania  Companies  filed   LTIIPs  with  the  PPUC  for  infrastructure  improvement  over  the  five-­year  period  of  2016  to  2020  for  the  following  costs:  WP  $88.34   million;;  PN  $56.74  million;;  Penn  $56.35  million;;  and  ME  $43.44  million.  These  amounts  include  all  qualifying  distribution  capital   additions  identified  in  the  revised  implementation  plan  for  the  recent  focused  management  and  operations  audit  of  the  Pennsylvania   Companies  as  discussed  below.  On  February  11,  2016,  the  PPUC  approved  the  Pennsylvania  Companies'  LTIIPs.  On  February  16,   2016,  the  Pennsylvania  Companies  filed  DSIC  riders  for  PPUC  approval  for  quarterly  cost  recovery  associated  with  the  capital   projects  approved  in  the  LTIIPs.  The  DSIC  riders  are  expected  to  be  effective  July  1,  2016.       46   47                                     Each  of  the  Pennsylvania  Companies  currently  offer  distribution  rates  under  their  respective  Joint  Petitions  for  Settlement  approved   on  April  9,  2015  by  the  PPUC,  which,  among  other  things,  provided  for  a  total  increase  in  annual  revenues  for  all  Pennsylvania   Companies  of  $292.8  million,  ($89.3  million  for  ME,  $90.8  million  for  PN,  $15.9  million  for  Penn  and  $96.8  million  for  WP),  including   the   recovery   of   $87.7   million   of   additional   annual   operating   expenses,   including   costs   associated   with   service   reliability   enhancements  to  the  distribution  system,  amortization  of  deferred  storm  costs  and  the  remaining  net  book  value  of  legacy  meters,   assistance  for  providing  service  to  low-­income  customers,  and  the  creation  of  a  storm  reserve  for  each  utility.  Additionally,  the   approved  settlements  include  commitments  to  meet  certain  wait  times  for  call  centers  and  service  reliability  standards.  The  new  rates   were  effective  May  3,  2015.     On  July  16,  2013,  the  PPUC's  Bureau  of  Audits  initiated  a  focused  management  and  operations  audit  of  the  Pennsylvania  Companies   as  required  every  eight  years  by  statute.  The  PPUC  issued  a  report  on  its  findings  and  recommendations  on  February  12,  2015,  at   which  time  the  Pennsylvania  Companies'  associated  implementation  plan  was  also  made  public.  In  an  order  issued  on  March  30,   2015,  the  Pennsylvania  Companies  were  directed  to  develop  and  file  by  May  29,  2015  a  revised  implementation  plan  regarding   certain  of  the  operational  topics  addressed  in  the  report,  including  addressing  certain  reliability  matters.  The  Pennsylvania  Companies   filed  their  revised  implementation  plan  in  compliance  with  this  order.  A  final  order  adopting  the  plan,  as  revised,  was  entered  on   November  5,  2015.  The  cost  of  compliance  for  the  Pennsylvania  Companies  is  currently  expected  to  range  from  approximately  $200   million  to  $230  million.     On  June  19,  2015,  ME  and  PN,  along  with  JCP&L,  FET  and  MAIT  made  filings  with  FERC,  the  NJBPU,  and  the  PPUC  requesting   authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT,  a  new  transmission-­only  subsidiary  of  FET.   Evidentiary  hearings  are  scheduled  to  commence  before  the  PPUC  on  February  29,  2016.  A  final  decision  from  the  PPUC  is  expected   by  mid-­2016.  See  Transfer  of  Transmission  Assets  to  MAIT  in  FERC  Matters  below  for  further  discussion  of  this  transaction.   WEST  VIRGINIA   MP  and  PE  currently  operate  under  a  Joint  Stipulation  and  Agreement  of  Settlement  approved  by  the  WVPSC  on  February  3,  2015,   that  provided  for:  a  $15  million  increase  in  annual  base  rate  revenues  effective  February  25,  2015;;  the  implementation  of  a  Vegetation   Management  Surcharge  to  recover  all  costs  related  to  both  new  and  existing  vegetation  maintenance  programs;;  authority  to  establish   a  regulatory  asset  for  MATS  investments  placed  into  service  in  2016  and  2017;;  authority  to  defer,  amortize  and  recover  over  a  five-­ year  period  through  base  rates  approximately  $46  million  of  storm  restoration  costs;;  and  elimination  of  the  TTS  for  costs  associated   with  MP's  acquisition  of  the  Harrison  plant  in  October  2013  and  movement  of  those  costs  into  base  rates.     On  August  14,  2015,  MP  and  PE  filed  their  annual  ENEC  case  with  the  WVPSC  proposing  an  approximate  $165.1  million  annual   increase  in  rates  effective  January  1,  2016  or  before,  which  would  be  a  12.5%  overall  increase  over  existing  rates.  The  original   proposed  increase  was  comprised  of  a  $97  million  under-­recovered  balance  as  of  June  30,  2015,  a  projected  $23.7  million  under-­ recovery  for  the  2016  calendar  year,  and  an  actual  under-­recovered  balance  from  MP  and  PE's  TTS  for  Harrison  Power  Station  of   $44.4   million.   On   September   10,   2015,   MP   and   PE   filed   an   amendment   addressing   the   results   of   the   recent   PJM  Transitional   Auctions  for  Capacity  Performance,  which  resulted  in  a  net  decrease  of  $20.6  million  from  the  initial  requested  increase  to  $144.5   million.  A  settlement  was  reached  among  all  the  parties  increasing  revenues  $96.9  million  and  deferring  other  costs  for  recovery  into   2017.    The  settlement  was  presented  to  the  WVPSC  on  November  19,  2015  and  a  final  order  approving  the  settlement  without   changes  was  issued  on  December  22,  2015,  with  rates  effective  on  January  1,  2016.     On  August  31,  2015,  MP  and  PE  filed  with  the  WVPSC  their  biennial  petition  for  reconciliation  of  the  Vegetation  Management   Program  Surcharge  and  regular  review  of  the  program  proposing  an  approximate  $37.7  million  annual  increase  in  rates  over  a  two   year  period,  which  is  a  2.8%  overall  increase  over  existing  rates.  The  proposed  increase  was  comprised  of  a  $2.1  million  under-­ recovered  balance  as  of  June  30,  2015,  a  projected  $23.9  million  in  under-­recovery  for  the  2016/2017  rate  effective  period,  and   recovery  of  previously  authorized  deferred  vegetation  management  costs  from  April  14,  2014  through  February  24,  2015  in  the   amount  of  $49.9  million. A  settlement  was  reached  among  all  the  parties  increasing  revenues  $36.7  million  annually  for  the  2016-­ 2017  two  year  rate  recovery  period,  and  was  presented  to  the  WVPSC  on  November  19,  2015.  A  final  order  approving  the  settlement   without  changes  was  issued  on  December  21,  2015,  with  rates  effective  on  January  1,  2016.     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,  AE  Supply,  FG,  FENOC,  NG,  ATSI  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  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   occasionally   learns   of   isolated   facts   or   circumstances   that   could   be   interpreted   as   excursions   from   the   reliability   standards.   If   and   when   such   occurrences   are   found,   FirstEnergy  develops  information  about  the  occurrence  and  develops  a  remedial  response  to  the  specific  circumstances,  including  in   appropriate  cases  “self-­reporting”  an  occurrence  to  RFC.  Moreover,  it  is  clear  that  NERC,  RFC  and  FERC  will  continue  to  refine   existing  reliability  standards  as  well  as  to  develop  and  adopt  new  reliability  standards.  Any  inability  on  FirstEnergy's  part  to  comply   with  the  reliability  standards  for  its  bulk  electric  system  could  result  in  the  imposition  of  financial  penalties,  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   PJM  Transmission  Rates   PJM  and  its  stakeholders  have  been  debating  the  proper  method  to  allocate  costs  for  new  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.  Settlement  discussions   under  a  FERC-­appointed  settlement  judge  are  ongoing.   In  a  series  of  orders  in  certain  Order  No.  1000  dockets,  FERC  asserted  that  the  PJM  transmission  owners  do  not  hold  an  incumbent   “right  of  first  refusal”  to  construct,  own  and  operate  transmission  projects  within  their  respective  footprints  that  are  approved  as  part  of   PJM’s  RTEP  process.  FirstEnergy  and  other  PJM  transmission  owners  have  appealed  these  rulings,  and  the  question  of  whether   FirstEnergy  and  the  PJM  transmission  owners  have  a  "right  of  first  refusal"  is  now  pending  before  the  U.S.  Court  of  Appeals  for  the   D.C.  Circuit  in  an  appeal  of  FERC's  order  approving  PJM's  Order  No.  1000  compliance  filing.   The  outcome  of  these  proceedings  and  their  impact,  if  any,  on  FirstEnergy  cannot  be  predicted  at  this  time.   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.  FirstEnergy's  request  for  rehearing  of  FERC's  order  rejecting  the  settlement  agreement  remains   pending.   Separately,  the  question  of  ATSI's  responsibility  for  certain  costs  for  the  “Michigan  Thumb”  transmission  project  continues  to  be   disputed.  Potential  responsibility  arises  under  the  MISO  MVP  tariff,  which  has  been  litigated  in  complex  proceedings  before  FERC   and  certain  United  States  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  is  pending  at  FERC.  In  the  event  of  a  final  non-­appealable  order  that  rules  that  ATSI  must  pay  these  charges,  ATSI  will  seek   recovery  of  these  charges  through  its  formula  rate.  On  a  related  issue,  FirstEnergy  joined  certain  other  PJM  transmission  owners  in  a   protest  of  MISO's  proposal  to  allocate  MVP  costs  to  energy  transactions  that  cross  MISO's  borders  into  the  PJM  Region.  On  January   22,  2015,  FERC  issued  an  order  establishing  a  paper  hearing  on  remand  from  the  Seventh  Circuit  of  the  issue  of  whether  any   limitation  on  "export  pricing"  for  sales  of  energy  from  MISO  into  PJM  is  justified  in  light  of  applicable  FERC  precedent.  Certain  PJM   transmission  owners,  including  FirstEnergy,  filed  an  initial  brief  asserting  that  FERC’s  prior  ruling  rejecting  MISO’s  proposed  MVP   export  charge  on  transactions  into  PJM  was  correct  and  should  be  re-­affirmed  on  remand.  The  briefs  and  replies  thereto  are  now   before  FERC  for  consideration.     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  costs  for  the  "Michigan  Thumb"  transmission   project  and  "legacy  RTEP"  transmission  projects  cannot  be  predicted  at  this  time.   48   49                                                     Each  of  the  Pennsylvania  Companies  currently  offer  distribution  rates  under  their  respective  Joint  Petitions  for  Settlement  approved   on  April  9,  2015  by  the  PPUC,  which,  among  other  things,  provided  for  a  total  increase  in  annual  revenues  for  all  Pennsylvania   Companies  of  $292.8  million,  ($89.3  million  for  ME,  $90.8  million  for  PN,  $15.9  million  for  Penn  and  $96.8  million  for  WP),  including   the   recovery   of   $87.7   million   of   additional   annual   operating   expenses,   including   costs   associated   with   service   reliability   enhancements  to  the  distribution  system,  amortization  of  deferred  storm  costs  and  the  remaining  net  book  value  of  legacy  meters,   assistance  for  providing  service  to  low-­income  customers,  and  the  creation  of  a  storm  reserve  for  each  utility.  Additionally,  the   approved  settlements  include  commitments  to  meet  certain  wait  times  for  call  centers  and  service  reliability  standards.  The  new  rates   were  effective  May  3,  2015.     On  July  16,  2013,  the  PPUC's  Bureau  of  Audits  initiated  a  focused  management  and  operations  audit  of  the  Pennsylvania  Companies   as  required  every  eight  years  by  statute.  The  PPUC  issued  a  report  on  its  findings  and  recommendations  on  February  12,  2015,  at   which  time  the  Pennsylvania  Companies'  associated  implementation  plan  was  also  made  public.  In  an  order  issued  on  March  30,   2015,  the  Pennsylvania  Companies  were  directed  to  develop  and  file  by  May  29,  2015  a  revised  implementation  plan  regarding   certain  of  the  operational  topics  addressed  in  the  report,  including  addressing  certain  reliability  matters.  The  Pennsylvania  Companies   filed  their  revised  implementation  plan  in  compliance  with  this  order.  A  final  order  adopting  the  plan,  as  revised,  was  entered  on   November  5,  2015.  The  cost  of  compliance  for  the  Pennsylvania  Companies  is  currently  expected  to  range  from  approximately  $200   million  to  $230  million.     On  June  19,  2015,  ME  and  PN,  along  with  JCP&L,  FET  and  MAIT  made  filings  with  FERC,  the  NJBPU,  and  the  PPUC  requesting   authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT,  a  new  transmission-­only  subsidiary  of  FET.   Evidentiary  hearings  are  scheduled  to  commence  before  the  PPUC  on  February  29,  2016.  A  final  decision  from  the  PPUC  is  expected   by  mid-­2016.  See  Transfer  of  Transmission  Assets  to  MAIT  in  FERC  Matters  below  for  further  discussion  of  this  transaction.   WEST  VIRGINIA   MP  and  PE  currently  operate  under  a  Joint  Stipulation  and  Agreement  of  Settlement  approved  by  the  WVPSC  on  February  3,  2015,   that  provided  for:  a  $15  million  increase  in  annual  base  rate  revenues  effective  February  25,  2015;;  the  implementation  of  a  Vegetation   Management  Surcharge  to  recover  all  costs  related  to  both  new  and  existing  vegetation  maintenance  programs;;  authority  to  establish   a  regulatory  asset  for  MATS  investments  placed  into  service  in  2016  and  2017;;  authority  to  defer,  amortize  and  recover  over  a  five-­ year  period  through  base  rates  approximately  $46  million  of  storm  restoration  costs;;  and  elimination  of  the  TTS  for  costs  associated   with  MP's  acquisition  of  the  Harrison  plant  in  October  2013  and  movement  of  those  costs  into  base  rates.     On  August  14,  2015,  MP  and  PE  filed  their  annual  ENEC  case  with  the  WVPSC  proposing  an  approximate  $165.1  million  annual   increase  in  rates  effective  January  1,  2016  or  before,  which  would  be  a  12.5%  overall  increase  over  existing  rates.  The  original   proposed  increase  was  comprised  of  a  $97  million  under-­recovered  balance  as  of  June  30,  2015,  a  projected  $23.7  million  under-­ recovery  for  the  2016  calendar  year,  and  an  actual  under-­recovered  balance  from  MP  and  PE's  TTS  for  Harrison  Power  Station  of   $44.4   million.   On   September   10,   2015,   MP   and   PE   filed   an   amendment   addressing   the   results   of   the   recent   PJM  Transitional   Auctions  for  Capacity  Performance,  which  resulted  in  a  net  decrease  of  $20.6  million  from  the  initial  requested  increase  to  $144.5   million.  A  settlement  was  reached  among  all  the  parties  increasing  revenues  $96.9  million  and  deferring  other  costs  for  recovery  into   2017.    The  settlement  was  presented  to  the  WVPSC  on  November  19,  2015  and  a  final  order  approving  the  settlement  without   changes  was  issued  on  December  22,  2015,  with  rates  effective  on  January  1,  2016.     On  August  31,  2015,  MP  and  PE  filed  with  the  WVPSC  their  biennial  petition  for  reconciliation  of  the  Vegetation  Management   Program  Surcharge  and  regular  review  of  the  program  proposing  an  approximate  $37.7  million  annual  increase  in  rates  over  a  two   year  period,  which  is  a  2.8%  overall  increase  over  existing  rates.  The  proposed  increase  was  comprised  of  a  $2.1  million  under-­ recovered  balance  as  of  June  30,  2015,  a  projected  $23.9  million  in  under-­recovery  for  the  2016/2017  rate  effective  period,  and   recovery  of  previously  authorized  deferred  vegetation  management  costs  from  April  14,  2014  through  February  24,  2015  in  the   amount  of  $49.9  million. A  settlement  was  reached  among  all  the  parties  increasing  revenues  $36.7  million  annually  for  the  2016-­ 2017  two  year  rate  recovery  period,  and  was  presented  to  the  WVPSC  on  November  19,  2015.  A  final  order  approving  the  settlement   without  changes  was  issued  on  December  21,  2015,  with  rates  effective  on  January  1,  2016.     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,  AE  Supply,  FG,  FENOC,  NG,  ATSI  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  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   occasionally   learns   of   isolated   facts   or   circumstances   that   could   be   interpreted   as   excursions   from   the   reliability   standards.   If   and   when   such   occurrences   are   found,   FirstEnergy  develops  information  about  the  occurrence  and  develops  a  remedial  response  to  the  specific  circumstances,  including  in   appropriate  cases  “self-­reporting”  an  occurrence  to  RFC.  Moreover,  it  is  clear  that  NERC,  RFC  and  FERC  will  continue  to  refine   existing  reliability  standards  as  well  as  to  develop  and  adopt  new  reliability  standards.  Any  inability  on  FirstEnergy's  part  to  comply   with  the  reliability  standards  for  its  bulk  electric  system  could  result  in  the  imposition  of  financial  penalties,  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   PJM  Transmission  Rates   PJM  and  its  stakeholders  have  been  debating  the  proper  method  to  allocate  costs  for  new  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.  Settlement  discussions   under  a  FERC-­appointed  settlement  judge  are  ongoing.   In  a  series  of  orders  in  certain  Order  No.  1000  dockets,  FERC  asserted  that  the  PJM  transmission  owners  do  not  hold  an  incumbent   “right  of  first  refusal”  to  construct,  own  and  operate  transmission  projects  within  their  respective  footprints  that  are  approved  as  part  of   PJM’s  RTEP  process.  FirstEnergy  and  other  PJM  transmission  owners  have  appealed  these  rulings,  and  the  question  of  whether   FirstEnergy  and  the  PJM  transmission  owners  have  a  "right  of  first  refusal"  is  now  pending  before  the  U.S.  Court  of  Appeals  for  the   D.C.  Circuit  in  an  appeal  of  FERC's  order  approving  PJM's  Order  No.  1000  compliance  filing.   The  outcome  of  these  proceedings  and  their  impact,  if  any,  on  FirstEnergy  cannot  be  predicted  at  this  time.   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.  FirstEnergy's  request  for  rehearing  of  FERC's  order  rejecting  the  settlement  agreement  remains   pending.   Separately,  the  question  of  ATSI's  responsibility  for  certain  costs  for  the  “Michigan  Thumb”  transmission  project  continues  to  be   disputed.  Potential  responsibility  arises  under  the  MISO  MVP  tariff,  which  has  been  litigated  in  complex  proceedings  before  FERC   and  certain  United  States  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  is  pending  at  FERC.  In  the  event  of  a  final  non-­appealable  order  that  rules  that  ATSI  must  pay  these  charges,  ATSI  will  seek   recovery  of  these  charges  through  its  formula  rate.  On  a  related  issue,  FirstEnergy  joined  certain  other  PJM  transmission  owners  in  a   protest  of  MISO's  proposal  to  allocate  MVP  costs  to  energy  transactions  that  cross  MISO's  borders  into  the  PJM  Region.  On  January   22,  2015,  FERC  issued  an  order  establishing  a  paper  hearing  on  remand  from  the  Seventh  Circuit  of  the  issue  of  whether  any   limitation  on  "export  pricing"  for  sales  of  energy  from  MISO  into  PJM  is  justified  in  light  of  applicable  FERC  precedent.  Certain  PJM   transmission  owners,  including  FirstEnergy,  filed  an  initial  brief  asserting  that  FERC’s  prior  ruling  rejecting  MISO’s  proposed  MVP   export  charge  on  transactions  into  PJM  was  correct  and  should  be  re-­affirmed  on  remand.  The  briefs  and  replies  thereto  are  now   before  FERC  for  consideration.     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  costs  for  the  "Michigan  Thumb"  transmission   project  and  "legacy  RTEP"  transmission  projects  cannot  be  predicted  at  this  time.   48   49                                                     2014  ATSI  Formula  Rate  Filing     On   October   31,   2014,  ATSI   filed   a   proposal   with   FERC   to   change   the   structure   of   its   formula   rate   from   an   “historical   looking”   approach,  where  transmission  rates  reflect  actual  costs  for  the  prior  year,  to  a  “forward  looking”  approach,  where  transmission  rates   would  be  based  on  the  estimated  costs  for  the  coming  year,  with  an  annual  true  up.  On  December  31,  2014,  FERC  issued  an  order   accepting  ATSI's  filing  effective  January  1,  2015,  subject  to  refund  and  the  outcome  of  hearing  and  settlement  proceedings.  FERC   subsequently  issued  an  order  on  October  29,  2015,  accepting  a  settlement  agreement  on  the  forward-­looking  formula  rate,  subject  to   minor   compliance   requirements.   The   settlement   agreement   provides   for   certain   changes   to  ATSI's   formula   rate   template   and   protocols,  and  also  changes  ATSI's  ROE  from  12.38%  to  the  following  values:  (i)  12.38%  from  January  1,  2015  through  June  30,   2015;;  (ii)  11.06%  from  July  1,  2015  through  December  31,  2015;;  and  (iii)  10.38%  from  January  1,  2016,  unless  changed  pursuant  to   section  205  or  206  of  the  FPA,  provided  the  effective  date  for  any  change  cannot  be  earlier  than  January  1,  2018.     Transfer  of  Transmission  Assets  to  MAIT     On  June  10,  2015,  MAIT,  a  Delaware  limited  liability  company,  was  formed  as  a  new  transmission-­only  subsidiary  of  FET  for  the   purposes  of  owning  and  operating  all  FERC-­jurisdictional  transmission  assets  of  JCP&L,  ME  and  PN  following  the  receipt  of  all   necessary  state  and  federal  regulatory  approvals.  On  June  19,  2015,  JCP&L,  PN,  ME,  FET,  and  MAIT  made  filings  with  FERC,  the   NJBPU,  and  the  PPUC  requesting  authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT.  Additionally,   the  filings  requested  approval  from  the  NJBPU  and  PPUC,  as  applicable,  of:  (i)  a  lease  to  MAIT  of  real  property  and  rights-­of-­way   associated  with  the  utilities'  transmission  assets;;  (ii)  a  Mutual  Assistance  Agreement;;  (iii)  MAIT  being  deemed  a  public  utility  under   state   law;;   (iv)   MAIT's   participation   in   FE's   regulated   companies'   money   pool;;   and   (v)   certain   affiliated   interest   agreements.   If   approved,  JCP&L,  ME,  and  PN  will  contribute  their  transmission  assets  at  net  book  value  and  an  allocated  portion  of  goodwill  in  a  tax-­ free  exchange  to  MAIT,  which  will  operate  similar  to  FET's  two  existing  stand-­alone  transmission  subsidiaries,  ATSI  and  TrAIL.  MAIT's   transmission  facilities  will  remain  under  the  functional  control  of  PJM,  and  PJM  will  provide  transmission  service  using  these  facilities   under  the  PJM  Tariff.  During  the  third  quarter  of  2015,  FirstEnergy  responded  to  FERC  Staff's  request  for  additional  information   regarding  the  application.  FERC  approval  is  expected  during  the  first  quarter  of  2016  with  final  decisions  expected  from  the  NJBPU   and  PPUC  by  mid-­2016.  Following  FERC  approval  of  the  transfer,  MAIT  expects  to  file  a  Section  204  application  with  FERC,  and   other  necessary  filings  with  the  PPUC  and  the  NJBPU,  seeking  authorization  to  issue  equity  to  FET,  JCP&L,  PN  and  ME  for  their   respective  contributions,  and  to  issue  debt.  MAIT  will  also  make  a  Section  205  formula  rate  application  with  FERC  to  establish  its   transmission  rate.  See  New  Jersey  and  Pennsylvania  in  State  Regulation  above  for  further  discussion  of  this  transaction.     California  Claims  Matters   In  October  2006,  several  California  governmental  and  utility  parties  presented  AE  Supply  with  a  settlement  proposal  to  resolve   alleged  overcharges  for  power  sales  by  AE  Supply  to  the  California  Energy  Resource  Scheduling  division  of  the  CDWR  during  2001.   The  settlement  proposal  claims  that  CDWR  is  owed  approximately  $190  million  for  these  alleged  overcharges.  This  proposal  was   made  in  the  context  of  mediation  efforts  by  FERC  and  the  Ninth  Circuit  in  several  pending  proceedings  to  resolve  all  outstanding   refund  and  other  claims,  including  claims  of  alleged  price  manipulation  in  the  California  energy  markets  during  2000  and  2001.  The   Ninth  Circuit  had  previously  remanded  one  of  those  proceedings  to  FERC,  which  dismissed  the  claims  of  the  California  parties  in  May   2011.  The  California  parties  appealed  FERC's  decision  back  to  the  Ninth  Circuit.  AE  Supply  joined  with  other  intervenors  in  the  case   and  filed  a  brief  in  support  of  FERC's  dismissal  of  the  case.  On  April  29,  2015,  the  Ninth  Circuit  remanded  the  case  to  FERC  for   further  proceedings.  On  November  3,  2015,  FERC  set  for  hearing  and  settlement  procedures  the  remanded  issue  of  whether  any   individual   public   utility   seller’s   violation   of   FERC’s   market-­based   rate   quarterly   reporting   requirement   led   to   an   unjust   and   unreasonable  rate  for  that  particular  seller  in  California  during  the  2000-­2001  period.  Settlement  discussions  under  a  FERC-­appointed   settlement  judge  are  ongoing.  Requests  for  rehearing  or  clarification  of  FERC’s  November  3,  2015  order  by  various  parties,  including   AE  Supply,  remain  pending.     In  another  proceeding,  in  May  2009,  the  California  Attorney  General,  on  behalf  of  certain  California  parties,  filed  a  complaint  with   FERC  against  various  sellers,  including  AE  Supply,  again  seeking  refunds  for  transactions  in  the  California  energy  markets  during   2000  and  2001.  The  above-­noted  transactions  with  CDWR  are  the  basis  for  including  AE  Supply  in  this  complaint.  AE  Supply  and   other  parties  filed  motions  to  dismiss,  which  FERC  granted.  The  California  Attorney  General  appealed  FERC's  dismissal  of  its   complaint  to  the  Ninth  Circuit,  which  has  consolidated  the  case  with  other  pending  appeals  related  to  California  refund  claims,  and   stayed  the  proceedings  pending  further  order.   The  outcome  of  either  of  the  above  matters  or  estimate  of  loss  or  range  of  loss  cannot  be  predicted  at  this  time.   PATH  Transmission  Project   On  August  24,  2012,  the  PJM  Board  of  Managers  canceled  the  PATH  project,  a  proposed  transmission  line  from  West  Virginia   through  Virginia  and  into  Maryland  which  PJM  had  previously  suspended  in  February  2011.  As  a  result  of  PJM  canceling  the  project,   approximately  $62  million  and  approximately  $59  million  in  costs  incurred  by  PATH-­Allegheny  and  PATH-­WV  (an  equity  method   investment  for  FE),  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   50                         2014  ATSI  Formula  Rate  Filing     On   October   31,   2014,  ATSI   filed   a   proposal   with   FERC   to   change   the   structure   of   its   formula   rate   from   an   “historical   looking”   approach,  where  transmission  rates  reflect  actual  costs  for  the  prior  year,  to  a  “forward  looking”  approach,  where  transmission  rates   would  be  based  on  the  estimated  costs  for  the  coming  year,  with  an  annual  true  up.  On  December  31,  2014,  FERC  issued  an  order   accepting  ATSI's  filing  effective  January  1,  2015,  subject  to  refund  and  the  outcome  of  hearing  and  settlement  proceedings.  FERC   subsequently  issued  an  order  on  October  29,  2015,  accepting  a  settlement  agreement  on  the  forward-­looking  formula  rate,  subject  to   minor   compliance   requirements.   The   settlement   agreement   provides   for   certain   changes   to  ATSI's   formula   rate   template   and   protocols,  and  also  changes  ATSI's  ROE  from  12.38%  to  the  following  values:  (i)  12.38%  from  January  1,  2015  through  June  30,   2015;;  (ii)  11.06%  from  July  1,  2015  through  December  31,  2015;;  and  (iii)  10.38%  from  January  1,  2016,  unless  changed  pursuant  to   section  205  or  206  of  the  FPA,  provided  the  effective  date  for  any  change  cannot  be  earlier  than  January  1,  2018.     Transfer  of  Transmission  Assets  to  MAIT     On  June  10,  2015,  MAIT,  a  Delaware  limited  liability  company,  was  formed  as  a  new  transmission-­only  subsidiary  of  FET  for  the   purposes  of  owning  and  operating  all  FERC-­jurisdictional  transmission  assets  of  JCP&L,  ME  and  PN  following  the  receipt  of  all   necessary  state  and  federal  regulatory  approvals.  On  June  19,  2015,  JCP&L,  PN,  ME,  FET,  and  MAIT  made  filings  with  FERC,  the   NJBPU,  and  the  PPUC  requesting  authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT.  Additionally,   the  filings  requested  approval  from  the  NJBPU  and  PPUC,  as  applicable,  of:  (i)  a  lease  to  MAIT  of  real  property  and  rights-­of-­way   associated  with  the  utilities'  transmission  assets;;  (ii)  a  Mutual  Assistance  Agreement;;  (iii)  MAIT  being  deemed  a  public  utility  under   state   law;;   (iv)   MAIT's   participation   in   FE's   regulated   companies'   money   pool;;   and   (v)   certain   affiliated   interest   agreements.   If   approved,  JCP&L,  ME,  and  PN  will  contribute  their  transmission  assets  at  net  book  value  and  an  allocated  portion  of  goodwill  in  a  tax-­ free  exchange  to  MAIT,  which  will  operate  similar  to  FET's  two  existing  stand-­alone  transmission  subsidiaries,  ATSI  and  TrAIL.  MAIT's   transmission  facilities  will  remain  under  the  functional  control  of  PJM,  and  PJM  will  provide  transmission  service  using  these  facilities   under  the  PJM  Tariff.  During  the  third  quarter  of  2015,  FirstEnergy  responded  to  FERC  Staff's  request  for  additional  information   regarding  the  application.  FERC  approval  is  expected  during  the  first  quarter  of  2016  with  final  decisions  expected  from  the  NJBPU   and  PPUC  by  mid-­2016.  Following  FERC  approval  of  the  transfer,  MAIT  expects  to  file  a  Section  204  application  with  FERC,  and   other  necessary  filings  with  the  PPUC  and  the  NJBPU,  seeking  authorization  to  issue  equity  to  FET,  JCP&L,  PN  and  ME  for  their   respective  contributions,  and  to  issue  debt.  MAIT  will  also  make  a  Section  205  formula  rate  application  with  FERC  to  establish  its   transmission  rate.  See  New  Jersey  and  Pennsylvania  in  State  Regulation  above  for  further  discussion  of  this  transaction.     California  Claims  Matters   In  October  2006,  several  California  governmental  and  utility  parties  presented  AE  Supply  with  a  settlement  proposal  to  resolve   alleged  overcharges  for  power  sales  by  AE  Supply  to  the  California  Energy  Resource  Scheduling  division  of  the  CDWR  during  2001.   The  settlement  proposal  claims  that  CDWR  is  owed  approximately  $190  million  for  these  alleged  overcharges.  This  proposal  was   refund  and  other  claims,  including  claims  of  alleged  price  manipulation  in  the  California  energy  markets  during  2000  and  2001.  The   Ninth  Circuit  had  previously  remanded  one  of  those  proceedings  to  FERC,  which  dismissed  the  claims  of  the  California  parties  in  May   2011.  The  California  parties  appealed  FERC's  decision  back  to  the  Ninth  Circuit.  AE  Supply  joined  with  other  intervenors  in  the  case   and  filed  a  brief  in  support  of  FERC's  dismissal  of  the  case.  On  April  29,  2015,  the  Ninth  Circuit  remanded  the  case  to  FERC  for   further  proceedings.  On  November  3,  2015,  FERC  set  for  hearing  and  settlement  procedures  the  remanded  issue  of  whether  any   individual   public   utility   seller’s   violation   of   FERC’s   market-­based   rate   quarterly   reporting   requirement   led   to   an   unjust   and   unreasonable  rate  for  that  particular  seller  in  California  during  the  2000-­2001  period.  Settlement  discussions  under  a  FERC-­appointed   settlement  judge  are  ongoing.  Requests  for  rehearing  or  clarification  of  FERC’s  November  3,  2015  order  by  various  parties,  including   AE  Supply,  remain  pending.     In  another  proceeding,  in  May  2009,  the  California  Attorney  General,  on  behalf  of  certain  California  parties,  filed  a  complaint  with   FERC  against  various  sellers,  including  AE  Supply,  again  seeking  refunds  for  transactions  in  the  California  energy  markets  during   2000  and  2001.  The  above-­noted  transactions  with  CDWR  are  the  basis  for  including  AE  Supply  in  this  complaint.  AE  Supply  and   other  parties  filed  motions  to  dismiss,  which  FERC  granted.  The  California  Attorney  General  appealed  FERC's  dismissal  of  its   complaint  to  the  Ninth  Circuit,  which  has  consolidated  the  case  with  other  pending  appeals  related  to  California  refund  claims,  and   stayed  the  proceedings  pending  further  order.   The  outcome  of  either  of  the  above  matters  or  estimate  of  loss  or  range  of  loss  cannot  be  predicted  at  this  time.   PATH  Transmission  Project   On  August  24,  2012,  the  PJM  Board  of  Managers  canceled  the  PATH  project,  a  proposed  transmission  line  from  West  Virginia   through  Virginia  and  into  Maryland  which  PJM  had  previously  suspended  in  February  2011.  As  a  result  of  PJM  canceling  the  project,   approximately  $62  million  and  approximately  $59  million  in  costs  incurred  by  PATH-­Allegheny  and  PATH-­WV  (an  equity  method   investment  for  FE),  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   settlement   proceedings   and   hearing   if   the   parties   could   not   agree   to   a   settlement.   On   March   24,   2014,   the   FERC   Chief  ALJ   terminated  settlement  proceedings  and  appointed  an  ALJ  to  preside  over  the  hearing  phase  of  the  case,  including  discovery  and   additional  pleadings  leading  up  to  hearing,  which  subsequently  included  the  parties  addressing  the  application  of  FERC's  Opinion  No.   531,  discussed  below,  to  the  PATH  proceeding.  On  September  14,  2015,  the  ALJ  issued  his  initial  decision,  disallowing  recovery  of   certain  costs.  The  initial  decision  and  exceptions  thereto  are  now  before  FERC  for  review  and  a  final  order.  FirstEnergy  continues  to   believe  the  costs  are  recoverable,  subject  to  final  ruling  from  FERC.     FERC  Opinion  No.  531     On  June  19,  2014,  FERC  issued  Opinion  No.  531,  in  which  FERC  revised  its  approach  for  calculating  the  discounted  cash  flow   element  of  FERC’s  ROE  methodology,  and  announced  the  potential  for  a  qualitative  adjustment  to  the  ROE  methodology  results.   Under  the  old  methodology,  FERC  used  a  five-­year  forecast  for  the  dividend  growth  variable,  whereas  going  forward  the  growth   variable  will  consist  of  two  parts:  (a)  a  five-­year  forecast  for  dividend  growth  (2/3  weight);;  and  (b)  a  long-­term  dividend  growth  forecast   based  on  a  forecast  for  the  U.S.  economy  (1/3  weight).  Regarding  the  qualitative  adjustment,  for  single-­utility  rate  cases  FERC   formerly  pegged  ROE  at  the  median  of  the  “zone  of  reasonableness”  that  came  out  of  the  ROE  formula,  whereas  going  forward,   FERC  may  rely  on  record  evidence  to  make  qualitative  adjustments  to  the  outcome  of  the  ROE  methodology  in  order  to  reach  a  level   sufficient   to   attract   future   investment.   On   October   16,   2014,   FERC   issued   its   Opinion   No.   531-­A,   applying   the   revised   ROE   methodology  to  certain  ISO  New  England  transmission  owners,  and  on  March  3,  2015,  FERC  issued  Opinion  No.  531-­B  affirming  its   prior  rulings.  Appeals  of  Opinion  Nos.  531,  532-­A  and  531-­B  are  pending  before  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit.   FirstEnergy  is  evaluating  the  potential  impact  of  Opinion  No.  531  on  the  authorized  ROE  of  our  FERC-­regulated  transmission  utilities   and  the  cost-­of-­service  wholesale  power  generation  transactions  of  MP.     MISO  Capacity  Portability   On  June  11,  2012,  in  response  to  certain  arguments  advanced  by  MISO,  FERC  requested  comments  regarding  whether  existing   rules  on  transfer  capability  act  as  barriers  to  the  delivery  of  capacity  between  MISO  and  PJM.  FirstEnergy  and  other  parties  submitted   filings   arguing   that   MISO's   concerns   largely   are   without   foundation,   FERC   did   not   mandate   a   solution   in   response   to   MISO's   concerns.  At  FERC's  direction,  in  May,  2015,  PJM,  MISO,  and  their  respective  independent  market  monitors  provided  additional   information  on  their  various  joint  issues  surrounding  the  PJM/MISO  seam  to  assist  FERC's  understanding  of  the  issues  and  what,  if   any,  additional  steps  FERC  should  take  to  improve  the  efficiency  of  operations  at  the  PJM/MISO  seam.  Stakeholders,  including  FESC   on  behalf  of  certain  of  its  affiliates  and  as  part  of  a  coalition  of  certain  other  PJM  utilities,  filed  responses  to  the  RTO  submissions.  The   various  submissions  and  responses  are  now  before  FERC  for  consideration.     Changes  to  the  criteria  and  qualifications  for  participation  in  the  PJM  RPM  capacity  auctions  could  have  a  significant  impact  on  the   outcome  of  those  auctions,  including  a  negative  impact  on  the  prices  at  which  those  auctions  would  clear.     made  in  the  context  of  mediation  efforts  by  FERC  and  the  Ninth  Circuit  in  several  pending  proceedings  to  resolve  all  outstanding   FTR  Underfunding  Complaint   In  PJM,  FTRs  are  a  mechanism  to  hedge  congestion  and  operate  as  a  financial  replacement  for  physical  firm  transmission  service.   FTRs   are   financially-­settled   instruments   that   entitle   the   holder   to   a   stream   of   revenues   based   on   the   hourly   congestion   price   differences  across  a  specific  transmission  path  in  the  PJM  Day-­ahead  Energy  Market.  Due  to  certain  language  in  the  PJM  Tariff,  the   funds  that  are  set  aside  to  pay  FTRs  can  be  diverted  to  other  uses,  which  may  result  in  “underfunding”  of  FTR  payments.  On   February  15,  2013,  FES  and  AE  Supply  filed  a  renewed  complaint  with  FERC  for  the  purpose  of  changing  the  PJM  Tariff  to  eliminate   FTR  underfunding.  On  June  5,  2013,  FERC  issued  an  order  denying  the  complaint,  and  on  June  8,  2015,  denied  a  request  for   rehearing  of  the  June  5,  2013  order.     PJM  Market  Reform:  PJM  Capacity  Performance  Proposal     In  December  2014,  PJM  submitted  proposed  “Capacity  Performance”  reforms  of  its  RPM  capacity  and  energy  markets.  On  June  9,   2015,  FERC  issued  an  order  conditionally  approving  the  bulk  of  the  proposed  Capacity  Performance  reforms  with  an  effective  date  of   April  1,  2015,  and  directed  PJM  to  make  a  compliance  filing  reflecting  the  mandate  of  FERC’s  order.  On  July  9,  2015,  several  parties,   including  FESC  on  behalf  of  certain  of  its  affiliates,  submitted  requests  for  rehearing  for  FERC's  June  9,  2015  order,  and  PJM   submitted  its  compliance  filing  as  directed  by  the  order.  The  requests  for  rehearing  and  PJM's  compliance  filing  are  pending  before   FERC.     In  August  and  September  2015,  PJM  conducted  RPM  auctions  pursuant  to  the  new  Capacity  Performance  rules.  FirstEnergy’s  net   competitive  capacity  position  as  a  result  of  the  BRA  and  Capacity  Performance  transition  auctions  is  as  follows:     50   51                                                 **   35   20   ($/MWD)   ($/MWD)   (MW)   ($/MWD)   ($/MWD)   $164.77   $164.77   **   (MW)   ($/MWD)   (MW)   2,765   $114.23   4,210   $59.37   3,675   875   $119.13   —   135   ($/MWD)   $134.00   $134.00   $134.00   ATSI   RTO   All  Other   Zones   (MW)   (MW)   (MW)   375   $120.00   6,245   $151.50   —   $149.98   6,245   985   $120.00   3,565   $151.50   240   $149.98   3,930   $151.50   150   $120.00   —   2016  -­  2017   2017  -­  2018   2018  -­  2019*   Legacy   Obligation   Capacity   Performance   Legacy   Obligation   Capacity   Performance   Base   Generation   Capacity   Performance   3,775   7,885   1,510   9,810   275   10,195   *Approximately  885  MWs  remain  uncommitted  for  the  2018/2019  delivery  year.       **Base   Generation:   10   MWs   cleared   at   $200.21/MWD   and   25   MWs   cleared   at   $149.98/MWD.   Capacity   Performance:   5   MWs   cleared   at   $215.00/MWD  and  15  MWs  cleared  at  $164.77/MWD.     PJM  Market  Reform:  FERC  Order  No.  745  -­  DR   On  May  23,  2014,  a  divided  three-­judge  panel  of  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  issued  an  opinion  vacating  FERC   Order   No.   745,   which   required   that,   under   certain   parameters,   DR   participating   in   organized   wholesale   energy   markets   be   compensated  at  LMP.  The  majority  concluded  that  DR  is  a  retail  service,  and  therefore  falls  under  state,  and  not  federal,  jurisdiction,   and  that  FERC,  therefore,  lacks  jurisdiction  to  regulate  DR.  The  majority  also  found  that  even  if  FERC  had  jurisdiction  over  DR,  Order   No.  745  would  be  arbitrary  and  capricious  because,  under  its  requirements,  DR  was  inappropriately  receiving  a  double  payment  (LMP   plus  the  savings  of  foregone  energy  purchases).  On  January  25,  2016,  the  United  States  Supreme  Court  reversed  the  opinion  of  the   U.S.  Court  of  Appeals  for  the  D.C.  Circuit  and  remanded  for  further  action,  finding  FERC  has  statutory  authority  under  the  FPA  to   regulate  compensation  of  demand  response  resources  in  FERC-­jurisdictional  wholesale  power  markets.  The  United  States  Supreme   Court  also  reversed  the  holding  that  FERC's  Order  No.  745  was  arbitrary  and  capricious,  finding  that  the  order  included  detailed   support  of  the  chosen  compensation  method.     On  May  23,  2014,  as  amended  September  22,  2014,  FESC,  on  behalf  of  its  affiliates  with  market-­based  rate  authorization,  filed  a   complaint  asking  FERC  to  issue  an  order  requiring  the  removal  of  all  portions  of  the  PJM  Tariff  allowing  or  requiring  DR  to  be  included   in  the  PJM  capacity  market,  with  a  refund  effective  date  of  May  23,  2014.  FESC  also  requested  that  the  results  of  the  May  2014  PJM   BRA  be  considered  void  and  legally  invalid  to  the  extent  that  DR  cleared  that  auction  because  the  participation  of  DR  in  that  auction   was  unlawful.  However,  in  light  of  the  United  States  Supreme  Court's  January  25,  2016  decision  discussed  above,  on  January  29,   2016,  FESC  withdrew  the  complaint.     ENVIRONMENTAL  MATTERS   Various  federal,  state  and  local  authorities  regulate  FirstEnergy  with  regard  to  air  and  water  quality  and  other  environmental  matters.   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  U.S.  Court  of  Appeals  for  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  EPA’s  regulatory  approach  under  CSAPR,  but  questioning  whether  EPA  required  upwind   states  to  reduce  emissions  by  more  than  their  contribution  to  air  pollution  in  downwind  states.  EPA  proposed  a  CSAPR  update  rule  on   November  16,  2015,  that  would  reduce  summertime  NOx  emissions  from  power  plants  in  23  states  in  the  eastern  U.S.,  including   Ohio,  Pennsylvania  and  West  Virginia,  beginning  in  2017.  Depending  on  how  the  EPA  and  the  states  implement  CSAPR,  the  future   cost  of  compliance  may  be  substantial  and  changes  to  FirstEnergy's  and  FES'  operations  may  result.     EPA  tightened  the  primary  and  secondary  NAAQS  for  ozone  from  the  2008  standard  levels  of  75  PPB  to  70  PPB  on  October  1,  2015.   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  EPA  will  designate  those  counties  that  fail  to  attain  the  new  2015  ozone  NAAQS  by  October  1,  2017.  States  will  then   have  roughly  three  years  to  develop  implementation  plans  to  attain  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  substantial  and  changes  to  FirstEnergy’s  and   FES’  operations  may  result.     52   53   MATS  imposes  emission  limits  for  mercury,  PM,  and  HCl  for  all  existing  and  new  fossil  fuel  fired  electric  generating  units  effective  in   April  2015  with  averaging  of  emissions  from  multiple  units  located  at  a  single  plant.  Under  the  CAA,  state  permitting  authorities  can   grant  an  additional  compliance  year  through  April  2016,  as  needed,  including  instances  when  necessary  to  maintain  reliability  where   electric  generating  units  are  being  closed.  On  December  28,  2012,  the  WVDEP  granted  a  conditional  extension  through  April  16,   2016  for  MATS  compliance  at  the  Fort  Martin,  Harrison  and  Pleasants  plants.  On  March  20,  2013,  the  PA  DEP  granted  an  extension   through  April  16,  2016  for  MATS  compliance  at  the  Hatfield's  Ferry  and  Bruce  Mansfield  plants.  On  February  5,  2015,  the  OEPA   granted  an  extension  through  April  16,  2016  for  MATS  compliance  at  the  Bay  Shore  and  Sammis  plants.  Nearly  all  spending  for   MATS  compliance  at  Bay  Shore  and  Sammis  has  been  completed  through  2014.  In  addition,  an  EPA  enforcement  policy  document   contemplates  up  to  an  additional  year  to  achieve  compliance,  through  April  2017,  under  certain  circumstances  for  reliability  critical   units.  On  June  29,  2015,  the  United  States  Supreme  Court  reversed  a  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  decision  that  upheld   MATS,  rejecting  EPA’s  regulatory  approach  that  costs  are  not  relevant  to  the  decision  of  whether  or  not  to  regulate  power  plant   emissions  under  Section  112  of  the  Clean  Air  Act  and  remanded  the  case  back  to  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  for   further  proceedings.  The  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  later  remanded  MATS  back  to  EPA,  who  represented  to  such  court   that  the  EPA  is  on  track  to  issue  a  finalized  MATS  by  April  15,  2016.  Subject  to  the  outcome  of  any  further  proceedings  before  the   U.S.   Court   of  Appeals   for   the   D.C.   Circuit   and   how   the   MATS   are   ultimately   implemented,   FirstEnergy's   total   capital   cost   for   compliance  (over  the  2012  to  2018  time  period)  is  currently  expected  to  be  approximately  $345  million  (CES  segment  of  $168  million   and  Regulated  Distribution  segment  of  $177  million),  of  which  $202  million  has  been  spent  through  December  31,  2015  ($80  million   at  CES  and  $122  million  at  Regulated  Distribution).     As  a  result  of  MATS,  Eastlake  Units  1-­3,  Ashtabula  Unit  5  and  Lake  Shore  Unit  18  were  deactivated  in  April  2015,  which  completes   the  deactivation  of  5,429  MW  of  coal-­fired  plants  since  2012.       On  August  3,  2015,  FG,  a  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  that  excuses  FG’s  performance  under  its   coal  transportation  contract  with  these  parties.  Specifically,  the  dispute  arises  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,  those  plants  were  deactivated  by  April  16,  2015.  In  January  2012,  FG  notified   BNSF  and  CSX  that  MATS  constituted  a  force  majeure  event  under  the  contract  that  excused  FG’s  further  performance.  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  including,  but  not  limited  to,  lost  profits  under  the  contract  through  2025.  As  part  of  its  statement  of  claim,  a  right  to   liquidated  damages  is  alleged.  The  arbitration  panel  has  determined  to  consolidate  the  claims  with  a  liability  hearing  expected  to   begin   in   November   2016,   and,   if   necessary,   a   damages   hearing   is   expected   to   begin   in   May   2017.  The   decision   on   liability   is   expected  to  be  issued  within  sixty  days  from  the  end  of  the  liability  hearings.    FirstEnergy  and  FES  continue  to  believe  that  MATS   constitutes  a  force  majeure  event  under  the  contract  as  it  relates  to  the  deactivated  plants  and  that  FG’s  performance  under  the   contract   is   therefore   excused.   FirstEnergy   and   FES   intend   to   vigorously   assert   their   position   in   the   arbitration   proceedings.   If,   however,  the  arbitration  panel  rules  in  favor  of  BNSF  and  CSX,  the  results  of  operations  and  financial  condition  of  both  FirstEnergy   and  FES  could  be  materially  adversely  impacted.  FirstEnergy  and  FES  are  unable  to  estimate  the  loss  or  range  of  loss.       FG  is  also  a  party  to  another  coal  transportation  contract  covering  the  delivery  of  2.5  million  tons  annually  through  2025,  a  portion  of   which  is  to  be  delivered  to  another  coal-­fired  plant  owned  by  FG  that  was  deactivated  as  a  result  of  MATS.  FG  has  asserted  a   defense  of  force  majeure  in  response  to  delivery  shortfalls  to  such  plant  under  this  contract  as  well.  If  FirstEnergy  and  FES  fail  to   reach  a  resolution  with  the  applicable  counterparties  to  the  contract,  and  if  it  were  ultimately  determined  that,  contrary  to  FirstEnergy’s   and  FES’  belief,  the  force  majeure  provisions  of  that  contract  do  not  excuse  the  delivery  shortfalls  to  the  deactivated  plant,  the  results   of  operations  and  financial  condition  of  both  FirstEnergy  and  FES  could  be  materially  adversely  impacted.  FirstEnergy  and  FES  are   unable  to  estimate  the  loss  or  range  of  loss.     As  to  both  coal  transportation  agreements  referenced  above,  FES  paid  in  settlement  approximately  $70  million  in  liquidated  damages   for  delivery  shortfalls  in  2014  related  to  its  deactivated  plants.   As  to  a  specific  coal  supply  agreement,  FirstEnergy  and  AE  Supply  have  asserted  termination  rights  effective  in  2015.  In  response  to   notification  of  the  termination,  the  coal  supplier  commenced  litigation  alleging  FirstEnergy  and  AE  Supply  do  not  have  sufficient   justification   to   terminate   the   agreement.   FirstEnergy   and  AE   Supply   have   filed   an   answer   denying   any   liability   related   to   the   termination.  This  matter  is  currently  in  the  discovery  phase  of  litigation  and  no  trial  date  has  been  established.  There  are  6  million  tons   remaining  under  the  contract  for  delivery.  At  this  time,  FirstEnergy  cannot  estimate  the  loss  or  range  of  loss  regarding  the  on-­going   litigation  with  respect  to  this  agreement.     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,  and  March  27,  2013,   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,  EPA  issued  a  CAA  section  114   request   for   the   Fort   Martin   coal-­fired   plant   seeking   information   and   documentation   relevant   to   its   operation   and   maintenance,                                           2016  -­  2017   2017  -­  2018   2018  -­  2019*   Legacy   Obligation   Capacity   Performance   Legacy   Obligation   Capacity   Performance   Base   Generation   Capacity   Performance   (MW)   ($/MWD)   (MW)   ($/MWD)   (MW)   (MW)   ($/MWD)   ($/MWD)   (MW)   ($/MWD)   ($/MWD)   (MW)   2,765   $114.23   4,210   $134.00   375   $120.00   6,245   $151.50   —   $149.98   6,245   $164.77   $59.37   3,675   $134.00   985   $120.00   3,565   $151.50   240   $149.98   3,930   $164.77   $119.13   —   $134.00   150   $120.00   —   $151.50   35   **   20   **   ATSI   RTO   All  Other   Zones   875   135   3,775   7,885   1,510   9,810   275   10,195   *Approximately  885  MWs  remain  uncommitted  for  the  2018/2019  delivery  year.       **Base   Generation:   10   MWs   cleared   at   $200.21/MWD   and   25   MWs   cleared   at   $149.98/MWD.   Capacity   Performance:   5   MWs   cleared   at   $215.00/MWD  and  15  MWs  cleared  at  $164.77/MWD.     PJM  Market  Reform:  FERC  Order  No.  745  -­  DR   On  May  23,  2014,  a  divided  three-­judge  panel  of  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  issued  an  opinion  vacating  FERC   Order   No.   745,   which   required   that,   under   certain   parameters,   DR   participating   in   organized   wholesale   energy   markets   be   compensated  at  LMP.  The  majority  concluded  that  DR  is  a  retail  service,  and  therefore  falls  under  state,  and  not  federal,  jurisdiction,   and  that  FERC,  therefore,  lacks  jurisdiction  to  regulate  DR.  The  majority  also  found  that  even  if  FERC  had  jurisdiction  over  DR,  Order   No.  745  would  be  arbitrary  and  capricious  because,  under  its  requirements,  DR  was  inappropriately  receiving  a  double  payment  (LMP   plus  the  savings  of  foregone  energy  purchases).  On  January  25,  2016,  the  United  States  Supreme  Court  reversed  the  opinion  of  the   U.S.  Court  of  Appeals  for  the  D.C.  Circuit  and  remanded  for  further  action,  finding  FERC  has  statutory  authority  under  the  FPA  to   regulate  compensation  of  demand  response  resources  in  FERC-­jurisdictional  wholesale  power  markets.  The  United  States  Supreme   Court  also  reversed  the  holding  that  FERC's  Order  No.  745  was  arbitrary  and  capricious,  finding  that  the  order  included  detailed   support  of  the  chosen  compensation  method.     On  May  23,  2014,  as  amended  September  22,  2014,  FESC,  on  behalf  of  its  affiliates  with  market-­based  rate  authorization,  filed  a   complaint  asking  FERC  to  issue  an  order  requiring  the  removal  of  all  portions  of  the  PJM  Tariff  allowing  or  requiring  DR  to  be  included   in  the  PJM  capacity  market,  with  a  refund  effective  date  of  May  23,  2014.  FESC  also  requested  that  the  results  of  the  May  2014  PJM   BRA  be  considered  void  and  legally  invalid  to  the  extent  that  DR  cleared  that  auction  because  the  participation  of  DR  in  that  auction   was  unlawful.  However,  in  light  of  the  United  States  Supreme  Court's  January  25,  2016  decision  discussed  above,  on  January  29,   2016,  FESC  withdrew  the  complaint.     ENVIRONMENTAL  MATTERS   Various  federal,  state  and  local  authorities  regulate  FirstEnergy  with  regard  to  air  and  water  quality  and  other  environmental  matters.   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   emission  allowances.     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   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  U.S.  Court  of  Appeals  for  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  EPA’s  regulatory  approach  under  CSAPR,  but  questioning  whether  EPA  required  upwind   states  to  reduce  emissions  by  more  than  their  contribution  to  air  pollution  in  downwind  states.  EPA  proposed  a  CSAPR  update  rule  on   November  16,  2015,  that  would  reduce  summertime  NOx  emissions  from  power  plants  in  23  states  in  the  eastern  U.S.,  including   Ohio,  Pennsylvania  and  West  Virginia,  beginning  in  2017.  Depending  on  how  the  EPA  and  the  states  implement  CSAPR,  the  future   cost  of  compliance  may  be  substantial  and  changes  to  FirstEnergy's  and  FES'  operations  may  result.     EPA  tightened  the  primary  and  secondary  NAAQS  for  ozone  from  the  2008  standard  levels  of  75  PPB  to  70  PPB  on  October  1,  2015.   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  EPA  will  designate  those  counties  that  fail  to  attain  the  new  2015  ozone  NAAQS  by  October  1,  2017.  States  will  then   have  roughly  three  years  to  develop  implementation  plans  to  attain  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  substantial  and  changes  to  FirstEnergy’s  and   FES’  operations  may  result.     MATS  imposes  emission  limits  for  mercury,  PM,  and  HCl  for  all  existing  and  new  fossil  fuel  fired  electric  generating  units  effective  in   April  2015  with  averaging  of  emissions  from  multiple  units  located  at  a  single  plant.  Under  the  CAA,  state  permitting  authorities  can   grant  an  additional  compliance  year  through  April  2016,  as  needed,  including  instances  when  necessary  to  maintain  reliability  where   electric  generating  units  are  being  closed.  On  December  28,  2012,  the  WVDEP  granted  a  conditional  extension  through  April  16,   2016  for  MATS  compliance  at  the  Fort  Martin,  Harrison  and  Pleasants  plants.  On  March  20,  2013,  the  PA  DEP  granted  an  extension   through  April  16,  2016  for  MATS  compliance  at  the  Hatfield's  Ferry  and  Bruce  Mansfield  plants.  On  February  5,  2015,  the  OEPA   granted  an  extension  through  April  16,  2016  for  MATS  compliance  at  the  Bay  Shore  and  Sammis  plants.  Nearly  all  spending  for   MATS  compliance  at  Bay  Shore  and  Sammis  has  been  completed  through  2014.  In  addition,  an  EPA  enforcement  policy  document   contemplates  up  to  an  additional  year  to  achieve  compliance,  through  April  2017,  under  certain  circumstances  for  reliability  critical   units.  On  June  29,  2015,  the  United  States  Supreme  Court  reversed  a  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  decision  that  upheld   MATS,  rejecting  EPA’s  regulatory  approach  that  costs  are  not  relevant  to  the  decision  of  whether  or  not  to  regulate  power  plant   emissions  under  Section  112  of  the  Clean  Air  Act  and  remanded  the  case  back  to  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  for   further  proceedings.  The  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  later  remanded  MATS  back  to  EPA,  who  represented  to  such  court   that  the  EPA  is  on  track  to  issue  a  finalized  MATS  by  April  15,  2016.  Subject  to  the  outcome  of  any  further  proceedings  before  the   U.S.   Court   of  Appeals   for   the   D.C.   Circuit   and   how   the   MATS   are   ultimately   implemented,   FirstEnergy's   total   capital   cost   for   compliance  (over  the  2012  to  2018  time  period)  is  currently  expected  to  be  approximately  $345  million  (CES  segment  of  $168  million   and  Regulated  Distribution  segment  of  $177  million),  of  which  $202  million  has  been  spent  through  December  31,  2015  ($80  million   at  CES  and  $122  million  at  Regulated  Distribution).     As  a  result  of  MATS,  Eastlake  Units  1-­3,  Ashtabula  Unit  5  and  Lake  Shore  Unit  18  were  deactivated  in  April  2015,  which  completes   the  deactivation  of  5,429  MW  of  coal-­fired  plants  since  2012.       On  August  3,  2015,  FG,  a  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  that  excuses  FG’s  performance  under  its   coal  transportation  contract  with  these  parties.  Specifically,  the  dispute  arises  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,  those  plants  were  deactivated  by  April  16,  2015.  In  January  2012,  FG  notified   BNSF  and  CSX  that  MATS  constituted  a  force  majeure  event  under  the  contract  that  excused  FG’s  further  performance.  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  including,  but  not  limited  to,  lost  profits  under  the  contract  through  2025.  As  part  of  its  statement  of  claim,  a  right  to   liquidated  damages  is  alleged.  The  arbitration  panel  has  determined  to  consolidate  the  claims  with  a  liability  hearing  expected  to   begin   in   November   2016,   and,   if   necessary,   a   damages   hearing   is   expected   to   begin   in   May   2017.  The   decision   on   liability   is   expected  to  be  issued  within  sixty  days  from  the  end  of  the  liability  hearings.    FirstEnergy  and  FES  continue  to  believe  that  MATS   constitutes  a  force  majeure  event  under  the  contract  as  it  relates  to  the  deactivated  plants  and  that  FG’s  performance  under  the   contract   is   therefore   excused.   FirstEnergy   and   FES   intend   to   vigorously   assert   their   position   in   the   arbitration   proceedings.   If,   however,  the  arbitration  panel  rules  in  favor  of  BNSF  and  CSX,  the  results  of  operations  and  financial  condition  of  both  FirstEnergy   and  FES  could  be  materially  adversely  impacted.  FirstEnergy  and  FES  are  unable  to  estimate  the  loss  or  range  of  loss.       FG  is  also  a  party  to  another  coal  transportation  contract  covering  the  delivery  of  2.5  million  tons  annually  through  2025,  a  portion  of   which  is  to  be  delivered  to  another  coal-­fired  plant  owned  by  FG  that  was  deactivated  as  a  result  of  MATS.  FG  has  asserted  a   defense  of  force  majeure  in  response  to  delivery  shortfalls  to  such  plant  under  this  contract  as  well.  If  FirstEnergy  and  FES  fail  to   reach  a  resolution  with  the  applicable  counterparties  to  the  contract,  and  if  it  were  ultimately  determined  that,  contrary  to  FirstEnergy’s   and  FES’  belief,  the  force  majeure  provisions  of  that  contract  do  not  excuse  the  delivery  shortfalls  to  the  deactivated  plant,  the  results   of  operations  and  financial  condition  of  both  FirstEnergy  and  FES  could  be  materially  adversely  impacted.  FirstEnergy  and  FES  are   unable  to  estimate  the  loss  or  range  of  loss.     As  to  both  coal  transportation  agreements  referenced  above,  FES  paid  in  settlement  approximately  $70  million  in  liquidated  damages   for  delivery  shortfalls  in  2014  related  to  its  deactivated  plants.   As  to  a  specific  coal  supply  agreement,  FirstEnergy  and  AE  Supply  have  asserted  termination  rights  effective  in  2015.  In  response  to   notification  of  the  termination,  the  coal  supplier  commenced  litigation  alleging  FirstEnergy  and  AE  Supply  do  not  have  sufficient   justification   to   terminate   the   agreement.   FirstEnergy   and  AE   Supply   have   filed   an   answer   denying   any   liability   related   to   the   termination.  This  matter  is  currently  in  the  discovery  phase  of  litigation  and  no  trial  date  has  been  established.  There  are  6  million  tons   remaining  under  the  contract  for  delivery.  At  this  time,  FirstEnergy  cannot  estimate  the  loss  or  range  of  loss  regarding  the  on-­going   litigation  with  respect  to  this  agreement.     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,  and  March  27,  2013,   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,  EPA  issued  a  CAA  section  114   request   for   the   Fort   Martin   coal-­fired   plant   seeking   information   and   documentation   relevant   to   its   operation   and   maintenance,   52   53                                           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.     operations  may  result.     implemented,   the   future   costs   of   compliance   with   these   standards   may   be   substantial   and   changes   to   FirstEnergy's   and   FES'   Climate  Change   There  are  a  number  of  initiatives  to  reduce  GHG  emissions  at  the  state,  federal  and  international  level.  Certain  northeastern  states   are  participating  in  the  RGGI  and  western  states  led  by  California,  have  implemented  programs,  primarily  cap  and  trade  mechanisms,   to  control  emissions  of  certain  GHGs.  Additional  policies  reducing  GHG  emissions,  such  as  demand  reduction  programs,  renewable   portfolio  standards  and  renewable  subsidies  have  been  implemented  across  the  nation.  A  June  2013,  Presidential  Climate  Action   Plan  outlined  goals  to:  (i)  cut  carbon  pollution  in  America  by  17%  by  2020  (from  2005  levels);;  (ii)  prepare  the  United  States  for  the   impacts  of  climate  change;;  and  (iii)  lead  international  efforts  to  combat  global  climate  change  and  prepare  for  its  impacts.  GHG   emissions   have   already   been   reduced   by   10%   between   2005   and   2012   according   to   an  April,   2014   EPA   Report.   Due   to   plant   deactivations  and  increased  efficiencies,  FirstEnergy  anticipates  its  CO2  emissions  will  be  reduced  25%  below  2005  levels  by  2015,   exceeding  the  President’s  Climate  Action  Plan  goals  both  in  terms  of  timing  and  reduction  levels.   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.  The  EPA  released  its  final  regulations  in  August  2015,  to  reduce  CO2  emissions  from  existing  fossil  fuel  fired   electric  generating  units  that  would  require  each  state  to  develop  SIPs  by  September  6,  2016,  to  meet  the  EPA’s  state  specific  CO2   emission  rate  goals.  The  EPA’s  CPP  allows  states  to  request  a  two-­year  extension  to  finalize  SIPs  by  September  6,  2018.  If  states  fail   to  develop  SIPs,  the  EPA  also  proposed  a  federal  implementation  plan  that  can  be  implemented  by  the  EPA  that  included  model   emissions  trading  rules  which  states  can  also  adopt  in  their  SIPs.  The  EPA  also  finalized  separate  regulations  imposing  CO2  emission   limits  for  new,  modified,  and  reconstructed  fossil  fuel  fired  electric  generating  units.  On  June  23,  2014,  the  United  States  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.   Numerous  states  and  private  parties  filed  appeals  and  motions  to  stay  the  CPP  with  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  in   October  2015.  On  January  21,  2015,  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.  Depending  on  the  outcome  of  further  appeals  and  how  any  final  rules  are  ultimately  implemented,   the  future  cost  of  compliance  may  be  substantial.     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  greenhouse  gas   emissions  by  26  to  28  percent  below  2005  levels  by  2025  and  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  must  be  ratified  by  at  least  55   countries  representing  at  least  55%  of  global  GHG  emissions  before  its  non-­binding  obligations  to  limit  global  warming  to  well  below   two  degrees  Celsius  become  effective.  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  significant  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  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.  FirstEnergy  is  studying  various  control  options  and  their  costs  and  effectiveness,  including  pilot  testing   of  reverse  louvers  in  a  portion  of  the  Bay  Shore  plant's  cooling  water  intake  channel  to  divert  fish  away  from  the  plant's  cooling  water   intake  system.  Depending  on  the  results  of  such  studies  and  any  final  action  taken  by  the  states  based  on  those  studies,  the  future   capital  costs  of  compliance  with  these  standards  may  be  substantial.   The  EPA  proposed  updates  to  the  waste  water  effluent  limitations  guidelines  and  standards  for  the  Steam  Electric  Power  Generating   category  (40  CFR  Part  423)  in  April  2013.  On  September  30,  2015,  the  EPA  finalized  new,  more  stringent  effluent  limits  for  arsenic,   mercury,  selenium  and  nitrogen  for  wastewater  from  wet  scrubber  systems  and  zero  discharge  of  pollutants  in  ash  transport  water.   The  treatment  obligations  will  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.  Depending  on  the  outcome  of  appeals  and  how  any  final  rules  are  ultimately   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  coal  combustion  residuals,  such  as  coal  ash,  were  exempted  from  hazardous  waste  disposal   requirements  pending  the  EPA's  evaluation  of  the  need  for  future  regulation.   In  December  2014,  the  EPA  finalized  regulations  for  the  disposal  of  CCRs  (non-­hazardous),  establishing  national  standards  regarding   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.   Based  on  an  assessment  of  the  finalized  regulations,  the  future  cost  of  compliance  and  expected  timing  of  spend  had  no  significant   impact  on  FirstEnergy's  or  FES'  existing  AROs  associated  with  CCRs.  Although  unexpected,  changes  in  timing  and  closure  plan   requirements  in  the  future  could  impact  our  asset  retirement  obligations  significantly.   Pursuant  to  a  2013  consent  decree,  PA  DEP  issued  a  2014  permit  requiring  FE  to  provide  bonding  for  45  years  of  closure  and  post-­ closure   activities   and   to   complete   closure   within   a   12-­year   period,   but   authorizing   FE   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  Bruce  Mansfield   plant  is  pursuing  several  options  for  disposal  of  CCRs  following  December  31,  2016  and  expects  beneficial  reuse  and  disposal   options  will  be  sufficient  for  the  ongoing  operation  of  the  plant.  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.  On   July  6,  2015  and  October  22,  2015,  the  Sierra  Club  filed  Notice  of  Appeals  with  the  Pennsylvania  Environmental  Hearing  Board   challenging  the  renewal,  reissuance  and  modification  of  the  permit  for  the  Hatfield’s  Ferry  CCR  disposal  facility.     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,  2015  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   $126  million  have  been  accrued  through  December  31,  2015.  Included  in  the  total  are  accrued  liabilities  of  approximately  $87  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,  2015,  FirstEnergy  had  approximately  $2.3  billion  invested  in  external  trusts  to  be  used  for  the  decommissioning  and   environmental  remediation  of  Davis-­Besse,  Beaver  Valley,  Perry  and  TMI-­2.  The  values  of  FirstEnergy's  NDTs  fluctuate  based  on   market  conditions.  If  the  value  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.  FE  and  FES  have  also  entered  into  a  total  of  $24.5  million  in  parental  guarantees  in  support  of  the  decommissioning  of  the   spent  fuel  storage  facilities  located  at  the  nuclear  facilities.  As  required  by  the  NRC,  FirstEnergy  annually  recalculates  and  adjusts  the   amount  of  its  parental  guaranties,  as  appropriate.     In  August  2010,  FENOC  submitted  an  application  to  the  NRC  for  renewal  of  the  Davis-­Besse  operating  license  for  an  additional   twenty  years.  On  December  8,  2015,  the  NRC  renewed  the  operating  license  for  Davis-­Besse,  which  is  now  authorized  to  continue   54   55                                                 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.     implemented,   the   future   costs   of   compliance   with   these   standards   may   be   substantial   and   changes   to   FirstEnergy's   and   FES'   operations  may  result.     Climate  Change   There  are  a  number  of  initiatives  to  reduce  GHG  emissions  at  the  state,  federal  and  international  level.  Certain  northeastern  states   are  participating  in  the  RGGI  and  western  states  led  by  California,  have  implemented  programs,  primarily  cap  and  trade  mechanisms,   to  control  emissions  of  certain  GHGs.  Additional  policies  reducing  GHG  emissions,  such  as  demand  reduction  programs,  renewable   portfolio  standards  and  renewable  subsidies  have  been  implemented  across  the  nation.  A  June  2013,  Presidential  Climate  Action   Plan  outlined  goals  to:  (i)  cut  carbon  pollution  in  America  by  17%  by  2020  (from  2005  levels);;  (ii)  prepare  the  United  States  for  the   impacts  of  climate  change;;  and  (iii)  lead  international  efforts  to  combat  global  climate  change  and  prepare  for  its  impacts.  GHG   emissions   have   already   been   reduced   by   10%   between   2005   and   2012   according   to   an  April,   2014   EPA   Report.   Due   to   plant   deactivations  and  increased  efficiencies,  FirstEnergy  anticipates  its  CO2  emissions  will  be  reduced  25%  below  2005  levels  by  2015,   exceeding  the  President’s  Climate  Action  Plan  goals  both  in  terms  of  timing  and  reduction  levels.   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.   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   Regulation  of  Waste  Disposal   pollutants"  under  the  CAA  and  mandated  measurement  and  reporting  of  GHG  emissions  from  certain  sources,  including  electric   generating  plants.  The  EPA  released  its  final  regulations  in  August  2015,  to  reduce  CO2  emissions  from  existing  fossil  fuel  fired   electric  generating  units  that  would  require  each  state  to  develop  SIPs  by  September  6,  2016,  to  meet  the  EPA’s  state  specific  CO2   emission  rate  goals.  The  EPA’s  CPP  allows  states  to  request  a  two-­year  extension  to  finalize  SIPs  by  September  6,  2018.  If  states  fail   to  develop  SIPs,  the  EPA  also  proposed  a  federal  implementation  plan  that  can  be  implemented  by  the  EPA  that  included  model   emissions  trading  rules  which  states  can  also  adopt  in  their  SIPs.  The  EPA  also  finalized  separate  regulations  imposing  CO2  emission   limits  for  new,  modified,  and  reconstructed  fossil  fuel  fired  electric  generating  units.  On  June  23,  2014,  the  United  States  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.   Numerous  states  and  private  parties  filed  appeals  and  motions  to  stay  the  CPP  with  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  in   October  2015.  On  January  21,  2015,  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.  Depending  on  the  outcome  of  further  appeals  and  how  any  final  rules  are  ultimately  implemented,   the  future  cost  of  compliance  may  be  substantial.     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  greenhouse  gas   emissions  by  26  to  28  percent  below  2005  levels  by  2025  and  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  must  be  ratified  by  at  least  55   countries  representing  at  least  55%  of  global  GHG  emissions  before  its  non-­binding  obligations  to  limit  global  warming  to  well  below   two  degrees  Celsius  become  effective.  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  significant  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.   Federal   and   state   hazardous   waste   regulations   have   been   promulgated   as   a   result   of   the   RCRA,   as   amended,   and   the  Toxic   Substances  Control  Act.  Certain  coal  combustion  residuals,  such  as  coal  ash,  were  exempted  from  hazardous  waste  disposal   requirements  pending  the  EPA's  evaluation  of  the  need  for  future  regulation.   In  December  2014,  the  EPA  finalized  regulations  for  the  disposal  of  CCRs  (non-­hazardous),  establishing  national  standards  regarding   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.   Based  on  an  assessment  of  the  finalized  regulations,  the  future  cost  of  compliance  and  expected  timing  of  spend  had  no  significant   impact  on  FirstEnergy's  or  FES'  existing  AROs  associated  with  CCRs.  Although  unexpected,  changes  in  timing  and  closure  plan   requirements  in  the  future  could  impact  our  asset  retirement  obligations  significantly.   Pursuant  to  a  2013  consent  decree,  PA  DEP  issued  a  2014  permit  requiring  FE  to  provide  bonding  for  45  years  of  closure  and  post-­ closure   activities   and   to   complete   closure   within   a   12-­year   period,   but   authorizing   FE   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  Bruce  Mansfield   plant  is  pursuing  several  options  for  disposal  of  CCRs  following  December  31,  2016  and  expects  beneficial  reuse  and  disposal   options  will  be  sufficient  for  the  ongoing  operation  of  the  plant.  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.  On   July  6,  2015  and  October  22,  2015,  the  Sierra  Club  filed  Notice  of  Appeals  with  the  Pennsylvania  Environmental  Hearing  Board   challenging  the  renewal,  reissuance  and  modification  of  the  permit  for  the  Hatfield’s  Ferry  CCR  disposal  facility.     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,  2015  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   $126  million  have  been  accrued  through  December  31,  2015.  Included  in  the  total  are  accrued  liabilities  of  approximately  $87  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.     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   OTHER  LEGAL  PROCEEDINGS   day  to  conduct  studies  to  determine  site-­specific  controls,  if  any,  to  reduce  entrainment,  which  occurs  when  aquatic  life  is  drawn  into  a   Nuclear  Plant  Matters   facility's  cooling  water  system.  FirstEnergy  is  studying  various  control  options  and  their  costs  and  effectiveness,  including  pilot  testing   of  reverse  louvers  in  a  portion  of  the  Bay  Shore  plant's  cooling  water  intake  channel  to  divert  fish  away  from  the  plant's  cooling  water   intake  system.  Depending  on  the  results  of  such  studies  and  any  final  action  taken  by  the  states  based  on  those  studies,  the  future   capital  costs  of  compliance  with  these  standards  may  be  substantial.   The  EPA  proposed  updates  to  the  waste  water  effluent  limitations  guidelines  and  standards  for  the  Steam  Electric  Power  Generating   category  (40  CFR  Part  423)  in  April  2013.  On  September  30,  2015,  the  EPA  finalized  new,  more  stringent  effluent  limits  for  arsenic,   mercury,  selenium  and  nitrogen  for  wastewater  from  wet  scrubber  systems  and  zero  discharge  of  pollutants  in  ash  transport  water.   The  treatment  obligations  will  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.  Depending  on  the  outcome  of  appeals  and  how  any  final  rules  are  ultimately   Under  NRC  regulations,  FirstEnergy  must  ensure  that  adequate  funds  will  be  available  to  decommission  its  nuclear  facilities.  As  of   December  31,  2015,  FirstEnergy  had  approximately  $2.3  billion  invested  in  external  trusts  to  be  used  for  the  decommissioning  and   environmental  remediation  of  Davis-­Besse,  Beaver  Valley,  Perry  and  TMI-­2.  The  values  of  FirstEnergy's  NDTs  fluctuate  based  on   market  conditions.  If  the  value  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.  FE  and  FES  have  also  entered  into  a  total  of  $24.5  million  in  parental  guarantees  in  support  of  the  decommissioning  of  the   spent  fuel  storage  facilities  located  at  the  nuclear  facilities.  As  required  by  the  NRC,  FirstEnergy  annually  recalculates  and  adjusts  the   amount  of  its  parental  guaranties,  as  appropriate.     In  August  2010,  FENOC  submitted  an  application  to  the  NRC  for  renewal  of  the  Davis-­Besse  operating  license  for  an  additional   twenty  years.  On  December  8,  2015,  the  NRC  renewed  the  operating  license  for  Davis-­Besse,  which  is  now  authorized  to  continue   54   55                                                 operation  through  April  22,  2037.  Prior  to  that  decision,  the  NRC  Commissioners  denied  an  intervenor's  request  to  reopen  the  record   and   admit   a   contention   on   the   NRC’s   Continued   Storage   Rule.   On  August   6,   2015,   this   intervenor   sought   review   of   the   NRC   Commissioners'  decision  before  the  U.S.  Court  of  Appeals  for  the  DC  Circuit.  FENOC  has  moved  to  intervene  in  that  proceeding.     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.   FENOC  plans  to  submit  a  license  amendment  application  related  to  the  Shield  Building  analysis  in  2016.     On  March  12,  2012,  the  NRC  issued  orders  requiring  safety  enhancements  at  U.S.  reactors  based  on  recommendations  from  the   lessons  learned  Task  Force  review  of  the  accident  at  Japan's  Fukushima  Daiichi  nuclear  power  plant.  These  orders  require  additional   mitigation  strategies  for  beyond-­design-­basis  external  events,  and  enhanced  equipment  for  monitoring  water  levels  in  spent  fuel   pools.   The   NRC   also   requested   that   licensees   including   FENOC:   re-­analyze   earthquake   and   flooding   risks   using   the   latest   information   available;;   conduct   earthquake   and   flooding   hazard   walkdowns   at   their   nuclear   plants;;   assess   the   ability   of   current   communications  systems  and  equipment  to  perform  under  a  prolonged  loss  of  onsite  and  offsite  electrical  power;;  and  assess  plant   staffing   levels   needed   to   fill   emergency   positions.   These   and   other   NRC   requirements   adopted   as   a   result   of   the   accident   at   Fukushima  Daiichi  are  likely  to  result  in  additional  material  costs  from  plant  modifications  and  upgrades  at  FirstEnergy's  nuclear   facilities.     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  14,   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   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,  ATSI,  TrAIL   and   PATH   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  14,  Regulatory  Matters  for  additional  information.   FirstEnergy  reviews  the  probability  of  recovery  of  regulatory  assets  at  each  balance  sheet  date  and  whenever  new  events  occur.   Similarly,  FirstEnergy  records  regulatory  liabilities  when  a  determination  is  made  that  a  refund  is  probable  or  when  ordered  by  a   commission.  Factors  that  may  affect  probability  include  changes  in  the  regulatory  environment,  issuance  of  a  regulatory  commission   order  or  passage  of  new  legislation.  If  recovery  of  a  regulatory  asset  is  no  longer  probable,  FirstEnergy  will  write  off  that  regulatory   asset  as  a  charge  against  earnings.   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’s  pension  and  OPEB  funding  policy  is  based  on  actuarial  computations  using  the  projected  unit  credit  method.  During  the   year  ended  December  31,  2015,  FirstEnergy  made  contributions  of  $143  million  to  its  qualified  pension  plan.  The  underfunded  status   of  FirstEnergy’s  qualified  and  non-­qualified  pension  and  OPEB  plans  as  of  December  31,  2015  was  $4.0  billion.   FirstEnergy  recognizes  as  a  pension  and  OPEB  mark-­to-­market  adjustment  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,  2015,  2014,  and  2013  were  $369  million  ($242  million  net  of  amounts  capitalized),  $1,243  million  ($835   million  net  of  amounts  capitalized),  and  $(396)  million  ($(256)  million  net  of  amounts  capitalized),  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  4.50%,  4.25%  and  5.00%  as  of  December  31,  2015,  2014  and  2013,  respectively.  The  assumed  discount  rates  for   OPEB  were  4.25%,  4.00%  and  4.75%  as  of  December  31,  2015,  2014  and  2013,  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  2015,  FirstEnergy’s  qualified  pension  and  OPEB  plan  assets  experienced  losses  of   $(172)  million  or  (2.7)%  compared  to  $387  million,  or  6.2%  in  2014  and  losses  of  $(22)  million,  or  (0.3)%  in  2013  and  assumed  a   7.75%  rate  of  return  for  both  years  on  plan  assets  which  generated  $476  million,  $496  million  and  $535  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  2016  was  lowered  to  7.50%.   During  2014,  the  Society  of  Actuaries  published  new  mortality  tables  and  improvement  scales  reflecting  improved  life  expectancies   and  an  expectation  that  the  trend  will  continue.  An  analysis  of  FirstEnergy  pension  and  OPEB  plan  mortality  data  indicated  the  use  of   the  RP2014  mortality  table  with  blue  collar  adjustment  for  females  and  projection  scale  SS2014INT  was  most  appropriate  as  of   December  31,  2015.  As  such,  the  RP2014  mortality  table  with  projection  scale  SS2014INT  was  utilized  to  determine  the  2015  benefit   cost  and  obligation  as  of  December  31,  2015  for  the  FirstEnergy  pension  and  OPEB  plans.  The  impact  of  using  the  RP2014  mortality   table  and  projection  scale  SS2014INT  resulted  in  an  increase  in  the  projected  benefit  obligation  of  $49  million  and  $1  million  for  the   pension  and  OPEB  plans,  respectively,  and  was  included  in  the  2015  pension  and  OPEB  mark-­to-­market  adjustment.     Based  on  discount  rates  of  4.50%  for  pension,  4.25%  for  OPEB  and  an  estimated  return  on  assets  of  7.50%,  FirstEnergy  expects  its   2016  pre-­tax  net  periodic  benefit  cost  (including  amounts  capitalized)  to  be  approximately  $122  million  (excluding  any  actuarial  mark-­ to-­market  adjustments  that  would  be  recognized  in  2016).  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,   2015.     Postemployment  Benefits  Expense  (Credits)   2015   2014   2013   Pension   OPEB   Total   $   $   (In  millions)   316   $   (61  )   255   $   939   $   (101  )   838   $   (134  )   (196  )   (330  )   56   57                                           operation  through  April  22,  2037.  Prior  to  that  decision,  the  NRC  Commissioners  denied  an  intervenor's  request  to  reopen  the  record   and   admit   a   contention   on   the   NRC’s   Continued   Storage   Rule.   On  August   6,   2015,   this   intervenor   sought   review   of   the   NRC   Commissioners'  decision  before  the  U.S.  Court  of  Appeals  for  the  DC  Circuit.  FENOC  has  moved  to  intervene  in  that  proceeding.     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.   FENOC  plans  to  submit  a  license  amendment  application  related  to  the  Shield  Building  analysis  in  2016.     On  March  12,  2012,  the  NRC  issued  orders  requiring  safety  enhancements  at  U.S.  reactors  based  on  recommendations  from  the   lessons  learned  Task  Force  review  of  the  accident  at  Japan's  Fukushima  Daiichi  nuclear  power  plant.  These  orders  require  additional   mitigation  strategies  for  beyond-­design-­basis  external  events,  and  enhanced  equipment  for  monitoring  water  levels  in  spent  fuel   pools.   The   NRC   also   requested   that   licensees   including   FENOC:   re-­analyze   earthquake   and   flooding   risks   using   the   latest   information   available;;   conduct   earthquake   and   flooding   hazard   walkdowns   at   their   nuclear   plants;;   assess   the   ability   of   current   communications  systems  and  equipment  to  perform  under  a  prolonged  loss  of  onsite  and  offsite  electrical  power;;  and  assess  plant   staffing   levels   needed   to   fill   emergency   positions.   These   and   other   NRC   requirements   adopted   as   a   result   of   the   accident   at   Fukushima  Daiichi  are  likely  to  result  in  additional  material  costs  from  plant  modifications  and  upgrades  at  FirstEnergy's  nuclear   facilities.     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  14,   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   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,  ATSI,  TrAIL   and   PATH   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  14,  Regulatory  Matters  for  additional  information.   FirstEnergy  reviews  the  probability  of  recovery  of  regulatory  assets  at  each  balance  sheet  date  and  whenever  new  events  occur.   Similarly,  FirstEnergy  records  regulatory  liabilities  when  a  determination  is  made  that  a  refund  is  probable  or  when  ordered  by  a   commission.  Factors  that  may  affect  probability  include  changes  in  the  regulatory  environment,  issuance  of  a  regulatory  commission   order  or  passage  of  new  legislation.  If  recovery  of  a  regulatory  asset  is  no  longer  probable,  FirstEnergy  will  write  off  that  regulatory   asset  as  a  charge  against  earnings.   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’s  pension  and  OPEB  funding  policy  is  based  on  actuarial  computations  using  the  projected  unit  credit  method.  During  the   year  ended  December  31,  2015,  FirstEnergy  made  contributions  of  $143  million  to  its  qualified  pension  plan.  The  underfunded  status   of  FirstEnergy’s  qualified  and  non-­qualified  pension  and  OPEB  plans  as  of  December  31,  2015  was  $4.0  billion.   FirstEnergy  recognizes  as  a  pension  and  OPEB  mark-­to-­market  adjustment  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,  2015,  2014,  and  2013  were  $369  million  ($242  million  net  of  amounts  capitalized),  $1,243  million  ($835   million  net  of  amounts  capitalized),  and  $(396)  million  ($(256)  million  net  of  amounts  capitalized),  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  4.50%,  4.25%  and  5.00%  as  of  December  31,  2015,  2014  and  2013,  respectively.  The  assumed  discount  rates  for   OPEB  were  4.25%,  4.00%  and  4.75%  as  of  December  31,  2015,  2014  and  2013,  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  2015,  FirstEnergy’s  qualified  pension  and  OPEB  plan  assets  experienced  losses  of   $(172)  million  or  (2.7)%  compared  to  $387  million,  or  6.2%  in  2014  and  losses  of  $(22)  million,  or  (0.3)%  in  2013  and  assumed  a   7.75%  rate  of  return  for  both  years  on  plan  assets  which  generated  $476  million,  $496  million  and  $535  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  2016  was  lowered  to  7.50%.   During  2014,  the  Society  of  Actuaries  published  new  mortality  tables  and  improvement  scales  reflecting  improved  life  expectancies   and  an  expectation  that  the  trend  will  continue.  An  analysis  of  FirstEnergy  pension  and  OPEB  plan  mortality  data  indicated  the  use  of   the  RP2014  mortality  table  with  blue  collar  adjustment  for  females  and  projection  scale  SS2014INT  was  most  appropriate  as  of   December  31,  2015.  As  such,  the  RP2014  mortality  table  with  projection  scale  SS2014INT  was  utilized  to  determine  the  2015  benefit   cost  and  obligation  as  of  December  31,  2015  for  the  FirstEnergy  pension  and  OPEB  plans.  The  impact  of  using  the  RP2014  mortality   table  and  projection  scale  SS2014INT  resulted  in  an  increase  in  the  projected  benefit  obligation  of  $49  million  and  $1  million  for  the   pension  and  OPEB  plans,  respectively,  and  was  included  in  the  2015  pension  and  OPEB  mark-­to-­market  adjustment.     Based  on  discount  rates  of  4.50%  for  pension,  4.25%  for  OPEB  and  an  estimated  return  on  assets  of  7.50%,  FirstEnergy  expects  its   2016  pre-­tax  net  periodic  benefit  cost  (including  amounts  capitalized)  to  be  approximately  $122  million  (excluding  any  actuarial  mark-­ to-­market  adjustments  that  would  be  recognized  in  2016).  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,   2015.     Postemployment  Benefits  Expense  (Credits)   2015   2014   2013   Pension   OPEB   Total   $   $   (In  millions)   316   $   (61  )   255   $   939   $   (101  )   838   $   (134  )   (196  )   (330  )   56   57                                           Health   care   cost   trends   continue   to   increase   and   will   affect   future   OPEB   costs.   The   2015   composite   health   care   trend   rate   assumptions   were   approximately   6.0-­5.5%,   compared   to   7.5-­7.0%   in   2014,   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  2016  pension  and  OPEB  net  periodic  benefit  costs  from  changes  in  key   assumptions  are  as  follows:   Goodwill   Increase  in  Net  Periodic  Benefit  Costs  from  Adverse  Changes  in  Key  Assumptions   Assumption   Adverse  Change   Pension   OPEB   Total   Discount  rate   Long-­term  return  on  assets   Health  care  trend  rate   Decrease  by  .25%   Decrease  by  .25%   Increase  by  1.0%   (In  millions)   273   13   N/A   19   $   1   $   25   $   292   14   25   Please  see  Note  3,  Pension  and  Other  Postemployment  Benefits  for  additional  information.   analysis  was  not  necessary  for  2015.   Long-­Lived  Assets   FirstEnergy  reviews  long-­lived  assets  for  impairment  whenever  events  or  changes  in  circumstances  indicate  that  the  carrying  value  of   such  assets  may  not  be  recoverable.  The  recoverability  of  a  long-­lived  asset  is  measured  by  comparing  its  carrying  value  to  the  sum   of  undiscounted  future  cash  flows  expected  to  result  from  the  use  and  eventual  disposition  of  the  asset.  If  the  carrying  value  is  greater   than  the  undiscounted  cash  flows,  an  impairment  exists  and  a  loss  is  recognized  for  the  amount  by  which  the  carrying  value  of  the   long-­lived  asset  exceeds  its  estimated  fair  value.  FirstEnergy  utilizes  the  income  approach,  based  upon  discounted  cash  flows  to   estimate  fair  value.  See  Note  1,  Organization  and  Basis  of  Presentation.   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.  This  approach  applies   probability  weighting  to  discounted  future  cash  flow  scenarios  that  reflect  a  range  of  possible  outcomes.  The  scenarios  consider   settlement  of  the  ARO  at  the  expiration  of  the  nuclear  power  plant's  current  license,  settlement  based  on  an  extended  license  term   and  expected  remediation  dates.  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,  2015,  are  described  further  in  Note  13,  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  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  5,  Taxes  for  additional  information.   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  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.   For  2015,  FirstEnergy  performed  a  qualitative  assessment  of  the  Regulated  Distribution  and  Regulated  Transmission  reporting  units,   assessing  economic,  industry  and  market  considerations  in  addition  to  the  reporting  unit's  overall  financial  performance.  It  was   determined  that  the  fair  values  of  these  reporting  units  were,  more  likely  than  not,  greater  than  their  carrying  values  and  a  quantitative   FirstEnergy  performed  a  quantitative  assessment  of  the  CES  reporting  unit  as  of  July  31,  2015.    Key  assumptions  incorporated  into   the  CES  discounted  cash  flow  analysis  requiring  significant  management  judgment  included  the  following:   •     Future  Energy  and  Capacity  Prices:  FirstEnergy  used  observable  market  information  for  near  term  forward  power  prices,   PJM  auction  results  for  near  term  capacity  pricing,  and  a  longer-­term  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:  FirstEnergy  used  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:  FirstEnergy  used  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   •     Discount  Rate:  A  discount  rate  of  8.25%,  based  on  a  capital  structure,  return  on  debt  and  return  on  equity  of  selected   performance  reforms  in  the  PJM  market.   comparable  companies.     •     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  results  of  the  quantitative  analysis,  the  fair  value  of  the  CES  reporting  unit  exceeded  its  carrying  value  by  approximately   10%.  Continued  weak  economic  conditions,  lower  than  expected  power  and  capacity  prices,  a  higher  cost  of  capital,  and  revised   environmental  requirements  could  have  a  negative  impact  on  future  goodwill  assessments.     See  Note  1,  Organization  and  Basis  of  Presentation  for  additional  details.   NEW  ACCOUNTING  PRONOUNCEMENTS   In  May  2014,  the  FASB  issued,  ASU  2014-­09  "Revenue  from  Contracts  with  Customers",  requiring  entities  to  recognize  revenue  by   applying  a  five-­step  model  in  accordance  with  the  core  principle  to  depict  the  transfer  of  promised  goods  or  services  to  customers  in   an  amount  that  reflects  the  consideration  to  which  the  entity  expects  to  be  entitled  in  exchange  for  those  goods  or  services.  In   addition,  the  accounting  for  costs  to  obtain  or  fulfill  a  contract  with  a  customer  is  specified  and  disclosure  requirements  for  revenue   recognition  are  expanded.    In  August  2015,  the  FASB  issued  a  final  Accounting  Standards  Update  deferring  the  effective  date  until   fiscal  years  beginning  after  December  15,  2017.  Earlier  application  is  permitted  only  as  of  annual  reporting  periods  beginning  after   December  15,  2016,  (the  original  effective  date).  The  standard  shall  be  applied  retrospectively  to  each  period  presented  or  as  a   cumulative-­effect  adjustment  as  of  the  date  of  adoption.  FirstEnergy  is  currently  evaluating  the  impact  on  its  financial  statements  of   adopting  this  standard.     In  February  2015,  the  FASB  issued,  ASU  2015-­02  "Consolidations:  Amendments  to  the  Consolidation  Analysis",  which  amends   current  consolidation  guidance  including  changes  to  both  the  variable  and  voting  interest  models  used  by  companies  to  evaluate   whether  an  entity  should  be  consolidated. This  standard  is  effective  for  interim  and  annual  periods  beginning  after  December  15,   2015,  and  early  adoption  is  permitted. A  reporting  entity  must  apply  the  amendments  using  a  modified  retrospective  approach  by   recording   a   cumulative-­effect   adjustment   to   equity   as   of   the   beginning   of   the   period   of   adoption   or   apply   the   amendments   retrospectively.  FirstEnergy  does  not  expect  this  amendment  to  have  a  material  effect  on  its  financial  statements.     In  April  2015,  the  FASB  issued,  ASU  2015-­03  "Simplifying  the  Presentation  of  Debt  Issuance  Costs",  which  requires  debt  issuance   costs  to  be  presented  on  the  balance  sheet  as  a  direct  deduction  from  the  carrying  value  of  the  associated  debt  liability,  consistent   with  the  presentation  of  a  debt  discount.  The  guidance  is  effective  for  financial  statements  issued  for  fiscal  years  beginning  after   December  15,  2015,  and  interim  periods  within  those  fiscal  years.  Early  adoption  is  permitted  for  financial  statements  that  have  not   been  previously  issued.  Upon  adoption,  an  entity  must  apply  the  new  guidance  retrospectively  to  all  prior  periods  presented  in  the   58   59                                               Health   care   cost   trends   continue   to   increase   and   will   affect   future   OPEB   costs.   The   2015   composite   health   care   trend   rate   assumptions   were   approximately   6.0-­5.5%,   compared   to   7.5-­7.0%   in   2014,   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  2016  pension  and  OPEB  net  periodic  benefit  costs  from  changes  in  key   assumptions  are  as  follows:   Increase  in  Net  Periodic  Benefit  Costs  from  Adverse  Changes  in  Key  Assumptions   Assumption   Adverse  Change   Pension   OPEB   Total   Discount  rate   Decrease  by  .25%   Long-­term  return  on  assets   Decrease  by  .25%   Health  care  trend  rate   Increase  by  1.0%   (In  millions)   273   13   N/A   19   $   1   $   25   $   292   14   25   Please  see  Note  3,  Pension  and  Other  Postemployment  Benefits  for  additional  information.   Long-­Lived  Assets   FirstEnergy  reviews  long-­lived  assets  for  impairment  whenever  events  or  changes  in  circumstances  indicate  that  the  carrying  value  of   such  assets  may  not  be  recoverable.  The  recoverability  of  a  long-­lived  asset  is  measured  by  comparing  its  carrying  value  to  the  sum   of  undiscounted  future  cash  flows  expected  to  result  from  the  use  and  eventual  disposition  of  the  asset.  If  the  carrying  value  is  greater   than  the  undiscounted  cash  flows,  an  impairment  exists  and  a  loss  is  recognized  for  the  amount  by  which  the  carrying  value  of  the   long-­lived  asset  exceeds  its  estimated  fair  value.  FirstEnergy  utilizes  the  income  approach,  based  upon  discounted  cash  flows  to   estimate  fair  value.  See  Note  1,  Organization  and  Basis  of  Presentation.   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.  This  approach  applies   probability  weighting  to  discounted  future  cash  flow  scenarios  that  reflect  a  range  of  possible  outcomes.  The  scenarios  consider   settlement  of  the  ARO  at  the  expiration  of  the  nuclear  power  plant's  current  license,  settlement  based  on  an  extended  license  term   and  expected  remediation  dates.  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   Conditional  retirement  obligations  associated  with  tangible  long-­lived  assets  are  recognized  at  fair  value  in  the  period  in  which  they   are  incurred  if  a  reasonable  estimate  can  be  made,  even  though  there  may  be  uncertainty  about  timing  or  method  of  settlement.   When  settlement  is  conditional  on  a  future  event  occurring,  it  is  reflected  in  the  measurement  of  the  liability,  not  the  timing  of  the   AROs  as  of  December  31,  2015,  are  described  further  in  Note  13,  Asset  Retirement  Obligations.     asset.   liability  recognition.   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  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  5,  Taxes  for  additional  information.   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  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.   For  2015,  FirstEnergy  performed  a  qualitative  assessment  of  the  Regulated  Distribution  and  Regulated  Transmission  reporting  units,   assessing  economic,  industry  and  market  considerations  in  addition  to  the  reporting  unit's  overall  financial  performance.  It  was   determined  that  the  fair  values  of  these  reporting  units  were,  more  likely  than  not,  greater  than  their  carrying  values  and  a  quantitative   analysis  was  not  necessary  for  2015.   FirstEnergy  performed  a  quantitative  assessment  of  the  CES  reporting  unit  as  of  July  31,  2015.    Key  assumptions  incorporated  into   the  CES  discounted  cash  flow  analysis  requiring  significant  management  judgment  included  the  following:   •     Future  Energy  and  Capacity  Prices:  FirstEnergy  used  observable  market  information  for  near  term  forward  power  prices,   PJM  auction  results  for  near  term  capacity  pricing,  and  a  longer-­term  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:  FirstEnergy  used  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:  FirstEnergy  used  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  8.25%,  based  on  a  capital  structure,  return  on  debt  and  return  on  equity  of  selected   comparable  companies.     •     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  results  of  the  quantitative  analysis,  the  fair  value  of  the  CES  reporting  unit  exceeded  its  carrying  value  by  approximately   10%.  Continued  weak  economic  conditions,  lower  than  expected  power  and  capacity  prices,  a  higher  cost  of  capital,  and  revised   environmental  requirements  could  have  a  negative  impact  on  future  goodwill  assessments.     See  Note  1,  Organization  and  Basis  of  Presentation  for  additional  details.   NEW  ACCOUNTING  PRONOUNCEMENTS   In  May  2014,  the  FASB  issued,  ASU  2014-­09  "Revenue  from  Contracts  with  Customers",  requiring  entities  to  recognize  revenue  by   applying  a  five-­step  model  in  accordance  with  the  core  principle  to  depict  the  transfer  of  promised  goods  or  services  to  customers  in   an  amount  that  reflects  the  consideration  to  which  the  entity  expects  to  be  entitled  in  exchange  for  those  goods  or  services.  In   addition,  the  accounting  for  costs  to  obtain  or  fulfill  a  contract  with  a  customer  is  specified  and  disclosure  requirements  for  revenue   recognition  are  expanded.    In  August  2015,  the  FASB  issued  a  final  Accounting  Standards  Update  deferring  the  effective  date  until   fiscal  years  beginning  after  December  15,  2017.  Earlier  application  is  permitted  only  as  of  annual  reporting  periods  beginning  after   December  15,  2016,  (the  original  effective  date).  The  standard  shall  be  applied  retrospectively  to  each  period  presented  or  as  a   cumulative-­effect  adjustment  as  of  the  date  of  adoption.  FirstEnergy  is  currently  evaluating  the  impact  on  its  financial  statements  of   adopting  this  standard.     In  February  2015,  the  FASB  issued,  ASU  2015-­02  "Consolidations:  Amendments  to  the  Consolidation  Analysis",  which  amends   current  consolidation  guidance  including  changes  to  both  the  variable  and  voting  interest  models  used  by  companies  to  evaluate   whether  an  entity  should  be  consolidated. This  standard  is  effective  for  interim  and  annual  periods  beginning  after  December  15,   2015,  and  early  adoption  is  permitted. A  reporting  entity  must  apply  the  amendments  using  a  modified  retrospective  approach  by   recording   a   cumulative-­effect   adjustment   to   equity   as   of   the   beginning   of   the   period   of   adoption   or   apply   the   amendments   retrospectively.  FirstEnergy  does  not  expect  this  amendment  to  have  a  material  effect  on  its  financial  statements.     In  April  2015,  the  FASB  issued,  ASU  2015-­03  "Simplifying  the  Presentation  of  Debt  Issuance  Costs",  which  requires  debt  issuance   costs  to  be  presented  on  the  balance  sheet  as  a  direct  deduction  from  the  carrying  value  of  the  associated  debt  liability,  consistent   with  the  presentation  of  a  debt  discount.  The  guidance  is  effective  for  financial  statements  issued  for  fiscal  years  beginning  after   December  15,  2015,  and  interim  periods  within  those  fiscal  years.  Early  adoption  is  permitted  for  financial  statements  that  have  not   been  previously  issued.  Upon  adoption,  an  entity  must  apply  the  new  guidance  retrospectively  to  all  prior  periods  presented  in  the   58   59                                               financial  statements.  In  addition,  in  August  2015,  the  FASB  issued  ASU  2015-­15,  "Presentation  and  Subsequent  Measurement  of   Debt  Issuance  Costs  Associated  with  Line-­of-­Credit  Arrangements",  which  states  given  the  absence  of  authoritative  guidance  within   ASU  2015-­03  for  debt  issuance  costs  related  to  the  line-­of-­credit  arrangements,  the  SEC  staff  would  not  object  to  presenting  those   deferred  debt  issuance  costs  as  an  asset  and  subsequently  amortizing  the  costs  ratably  over  the  term  of  the  arrangement,  regardless   of   whether   there   are   any   outstanding   borrowings   on   the   line-­of-­credit.   FirstEnergy   will   adopt  ASU   2015-­15   and  ASU   2015-­03   beginning  January  1,  2016.  As  of  December  31,  2015,  FirstEnergy  and  FES  debt  issuance  costs  included  in  Deferred  Charges  and   Other  Assets  were  $93  million  and  $17  million,  respectively.  FirstEnergy  will  elect  to  continue  presenting  debt  issuance  costs  relating   to  its  revolving  credit  facilities  as  an  asset.       In  August  2015,  the  FASB  issued  ASU  2015  -­13,  "Application  of  the  NPNS  Scope  Exception  to  Certain  Electricity  Contracts  within   Nodal  Energy  Markets",  which  confirmed  that  forward  physical  contracts  for  the  sale  or  purchase  of  electricity  meet  the  physical   delivery  criterion  within  the  NPNS  scope  exception  when  the  electricity  is  transmitted  through  a  grid  managed  by  an  ISO.  As  a  result,   an  entity  can  elect  the  NPNS  exception  within  the  derivative  accounting  guidance  for  such  contracts,  provided  that  the  other  NPNS   criteria  are  also  met.  The  ASU  was  effective  on  issuance  and  requires  prospective  application.  There  was  no  material  effect  on   FirstEnergy's  financial  statements  resulting  from  the  issuance  of  ASU  2015-­13.     In  November  2015,  the  FASB  issued  ASU  2015  -­  17,  "Balance  Sheet  Classification  of  Deferred  Taxes",  which  requires  all  deferred  tax   assets  and  liabilities,  along  with  any  related  valuation  allowance,  be  classified  as  noncurrent  on  the  balance  sheet.  The  new  guidance   will  be  effective  for  fiscal  years  beginning  after  December  15,  2016,  and  interim  periods  within  those  fiscal  years.  Early  adoption  is   permitted   for   all   entities   as   of   the   beginning   of   an   interim   or   annual   reporting   period.     The   guidance   may   be   applied   either   prospectively,  for  all  deferred  tax  assets  and  liabilities,  or  retrospectively.  FirstEnergy  early  adopted  ASU  2015-­17  as  of  December   2015,  and  applied  the  new  guidance  retrospectively  to  all  prior  periods  presented  in  the  financial  statements.  There  was  no  impact   from  the  early  adoption  of  ASU  2015-­17  on  the  Consolidated  Statements  of  Income.  On  the  Consolidated  Balance  Sheet  as  of   December  31,  2014,  FirstEnergy  and  FES  reclassified  $518  million and  $27  million of  Accumulated  Deferred  Income  Taxes  from   Current  Assets  to  Noncurrent  Liabilities.     In  January  of  2016,  the  FASB  issued  ASU  2016-­01,  "Financial  Instruments-­Overall:  Recognition  and  Measurement  of  Financial   Assets  and  Financial  Liabilities".  Changes  to  the  current  GAAP  model  primarily  affect  the  accounting  for  equity  investments,  financial   liabilities  under  the  fair  value  option,  and  the  presentation  and  disclosure  requirements  for  financial  instruments.  In  addition,  the  FASB   clarified  guidance  related  to  the  valuation  allowance  assessment  when  recognizing  deferred  tax  assets  resulting  from  unrealized   losses  on  available-­for-­sale  debt  securities.  The  ASU  will  be  effective  in  fiscal  years  beginning  after  December  15,  2017,  including   interim  periods  within  those  fiscal  years.  Early  adoption  can  be  elected  for  all  financial  statements  of  fiscal  years  and  interim  periods   that  have  not  yet  been  issued  or  that  have  not  yet  been  made  available  for  issuance.  FirstEnergy  is  currently  evaluating  the  impact  on   its  financial  statements  of  adopting  this  standard.     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. firm,  as  stated  in  their  report  which  appears  herein.   FINANCIAL  STATEMENTS  AND  SUPPLEMENTARY  DATA   MANAGEMENT  REPORTS   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  2015  consolidated  financial   statements  as  stated  in  their  audit  report  included  herein.   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  2015.   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,  management  conducted  an   evaluation  of  the  effectiveness  of  the  Company’s  internal  control  over  financial  reporting  under  the  supervision  of  the  Chief  Executive   Officer  and  the  Chief  Financial  Officer.  Based  on  that  evaluation,  management  concluded  that  the  Company’s  internal  control  over   financial   reporting   was   effective   as   of   December  31,   2015.   The   effectiveness   of   the   Company’s   internal   control   over   financial   reporting,  as  of  December  31,  2015,  has  been  audited  by  PricewaterhouseCoopers  LLP,  an  independent  registered  public  accounting   60   61                             financial  statements.  In  addition,  in  August  2015,  the  FASB  issued  ASU  2015-­15,  "Presentation  and  Subsequent  Measurement  of   Debt  Issuance  Costs  Associated  with  Line-­of-­Credit  Arrangements",  which  states  given  the  absence  of  authoritative  guidance  within   ASU  2015-­03  for  debt  issuance  costs  related  to  the  line-­of-­credit  arrangements,  the  SEC  staff  would  not  object  to  presenting  those   deferred  debt  issuance  costs  as  an  asset  and  subsequently  amortizing  the  costs  ratably  over  the  term  of  the  arrangement,  regardless   of   whether   there   are   any   outstanding   borrowings   on   the   line-­of-­credit.   FirstEnergy   will   adopt  ASU   2015-­15   and  ASU   2015-­03   beginning  January  1,  2016.  As  of  December  31,  2015,  FirstEnergy  and  FES  debt  issuance  costs  included  in  Deferred  Charges  and   Other  Assets  were  $93  million  and  $17  million,  respectively.  FirstEnergy  will  elect  to  continue  presenting  debt  issuance  costs  relating   to  its  revolving  credit  facilities  as  an  asset.       In  August  2015,  the  FASB  issued  ASU  2015  -­13,  "Application  of  the  NPNS  Scope  Exception  to  Certain  Electricity  Contracts  within   Nodal  Energy  Markets",  which  confirmed  that  forward  physical  contracts  for  the  sale  or  purchase  of  electricity  meet  the  physical   delivery  criterion  within  the  NPNS  scope  exception  when  the  electricity  is  transmitted  through  a  grid  managed  by  an  ISO.  As  a  result,   an  entity  can  elect  the  NPNS  exception  within  the  derivative  accounting  guidance  for  such  contracts,  provided  that  the  other  NPNS   criteria  are  also  met.  The  ASU  was  effective  on  issuance  and  requires  prospective  application.  There  was  no  material  effect  on   FirstEnergy's  financial  statements  resulting  from  the  issuance  of  ASU  2015-­13.     In  November  2015,  the  FASB  issued  ASU  2015  -­  17,  "Balance  Sheet  Classification  of  Deferred  Taxes",  which  requires  all  deferred  tax   assets  and  liabilities,  along  with  any  related  valuation  allowance,  be  classified  as  noncurrent  on  the  balance  sheet.  The  new  guidance   will  be  effective  for  fiscal  years  beginning  after  December  15,  2016,  and  interim  periods  within  those  fiscal  years.  Early  adoption  is   permitted   for   all   entities   as   of   the   beginning   of   an   interim   or   annual   reporting   period.     The   guidance   may   be   applied   either   prospectively,  for  all  deferred  tax  assets  and  liabilities,  or  retrospectively.  FirstEnergy  early  adopted  ASU  2015-­17  as  of  December   2015,  and  applied  the  new  guidance  retrospectively  to  all  prior  periods  presented  in  the  financial  statements.  There  was  no  impact   from  the  early  adoption  of  ASU  2015-­17  on  the  Consolidated  Statements  of  Income.  On  the  Consolidated  Balance  Sheet  as  of   December  31,  2014,  FirstEnergy  and  FES  reclassified  $518  million and  $27  million of  Accumulated  Deferred  Income  Taxes  from   Current  Assets  to  Noncurrent  Liabilities.     In  January  of  2016,  the  FASB  issued  ASU  2016-­01,  "Financial  Instruments-­Overall:  Recognition  and  Measurement  of  Financial   Assets  and  Financial  Liabilities".  Changes  to  the  current  GAAP  model  primarily  affect  the  accounting  for  equity  investments,  financial   liabilities  under  the  fair  value  option,  and  the  presentation  and  disclosure  requirements  for  financial  instruments.  In  addition,  the  FASB   clarified  guidance  related  to  the  valuation  allowance  assessment  when  recognizing  deferred  tax  assets  resulting  from  unrealized   losses  on  available-­for-­sale  debt  securities.  The  ASU  will  be  effective  in  fiscal  years  beginning  after  December  15,  2017,  including   interim  periods  within  those  fiscal  years.  Early  adoption  can  be  elected  for  all  financial  statements  of  fiscal  years  and  interim  periods   that  have  not  yet  been  issued  or  that  have  not  yet  been  made  available  for  issuance.  FirstEnergy  is  currently  evaluating  the  impact  on   its  financial  statements  of  adopting  this  standard.     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. FINANCIAL  STATEMENTS  AND  SUPPLEMENTARY  DATA   MANAGEMENT  REPORTS   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  2015  consolidated  financial   statements  as  stated  in  their  audit  report  included  herein.   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  2015.   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,  management  conducted  an   evaluation  of  the  effectiveness  of  the  Company’s  internal  control  over  financial  reporting  under  the  supervision  of  the  Chief  Executive   Officer  and  the  Chief  Financial  Officer.  Based  on  that  evaluation,  management  concluded  that  the  Company’s  internal  control  over   financial   reporting   was   effective   as   of   December  31,   2015.   The   effectiveness   of   the   Company’s   internal   control   over   financial   reporting,  as  of  December  31,  2015,  has  been  audited  by  PricewaterhouseCoopers  LLP,  an  independent  registered  public  accounting   firm,  as  stated  in  their  report  which  appears  herein.   60   61                             FIRSTENERGY  CORP.   CONSOLIDATED  STATEMENTS  OF  INCOME   Report  of  Independent  Registered  Public  Accounting  Firm   To  the  Stockholders  and  Board  of  Directors  of  FirstEnergy  Corp.:   In  our  opinion,  the  accompanying  consolidated  balance  sheets  and  the  related  consolidated  statements  of  income,  comprehensive   income,  common  stockholders’  equity,  and  cash  flows,  present  fairly,  in  all  material  respects,  the  financial  position  of  FirstEnergy   Corp.  and  its  subsidiaries  at  December  31,  2015  and  2014,  and  the  results  of  their  operations  and  their  cash  flows  for  each  of  the   three  years  in  the  period  ended  December  31,  2015  in  conformity  with  accounting  principles  generally  accepted  in  the  United  States   of  America.    In  addition,  in  our  opinion,  the  financial  statement  schedule  listed  in  the  index  appearing  under  Item15(a)(2)  presents   fairly,  in  all  material  respects,  the  information  set  forth  therein  when  read  in  conjunction  with  the  related  consolidated  financial   statements.    Also  in  our  opinion,  the  Company  maintained,  in  all  material  respects,  effective  internal  control  over  financial  reporting  as   of  December  31,  2015,  based  on  criteria  established  in  Internal  Control  -­  Integrated  Framework  (2013)  issued  by  the  Committee  of   Sponsoring  Organizations  of  the  Treadway  Commission  (COSO).    The  Company's  management  is  responsible  for  these  financial   statements  and  financial  statement  schedule,  for  maintaining  effective  internal  control  over  financial  reporting  and  for  its  assessment   of  the  effectiveness  of  internal  control  over  financial  reporting,  included  in  the  accompanying  Management’s  Report  on  Internal   Control  over  Financial  Reporting.    Our  responsibility  is  to  express  opinions  on  these  financial  statements,  on  the  financial  statement   schedule,  and  on  the  Company's  internal  control  over  financial  reporting  based  on  our  integrated  audits.    We  conducted  our  audits  in   accordance  with  the  standards  of  the  Public  Company  Accounting  Oversight  Board  (United  States).    Those  standards  require  that  we   plan  and  perform  the  audits  to  obtain  reasonable  assurance  about  whether  the  financial  statements  are  free  of  material  misstatement   and  whether  effective  internal  control  over  financial  reporting  was  maintained  in  all  material  respects.    Our  audits  of  the  financial   statements  included  examining,  on  a  test   basis,   evidence   supporting   the   amounts   and   disclosures   in   the   financial   statements,   assessing  the  accounting  principles  used  and  significant  estimates  made  by  management,  and  evaluating  the  overall  financial   statement  presentation.    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.   As  discussed  in  Note  1  to  the  consolidated  financial  statements,  in  2015  the  Company  changed  the  manner  in  which  deferred  tax   assets  and  liabilities,  along  with  any  related  valuation  allowance,  are  classified  on  the  balance  sheet.   A  company’s  internal  control  over  financial  reporting  is  a  process  designed  to  provide  reasonable  assurance  regarding  the  reliability  of   financial  reporting  and  the  preparation  of  financial  statements  for  external  purposes  in  accordance  with  generally  accepted  accounting   principles.    A   company’s   internal   control   over   financial   reporting   includes   those   policies   and   procedures   that   (i)  pertain   to   the   maintenance  of  records  that,  in  reasonable  detail,  accurately  and  fairly  reflect  the  transactions  and  dispositions  of  the  assets  of  the   company;;  (ii)  provide  reasonable  assurance  that  transactions  are  recorded  as  necessary  to  permit  preparation  of  financial  statements   in  accordance  with  generally  accepted  accounting  principles,  and  that  receipts  and  expenditures  of  the  company  are  being  made  only   in  accordance  with  authorizations  of  management  and  directors  of  the  company;;  and  (iii)  provide  reasonable  assurance  regarding   prevention  or  timely  detection  of  unauthorized  acquisition,  use,  or  disposition  of  the  company’s  assets  that  could  have  a  material   effect  on  the  financial  statements.   Because  of  its  inherent  limitations,  internal  control  over  financial  reporting  may  not  prevent  or  detect  misstatements.    Also,  projections   of  any  evaluation  of  effectiveness  to  future  periods  are  subject  to  the  risk  that  controls  may  become  inadequate  because  of  changes   in  conditions,  or  that  the  degree  of  compliance  with  the  policies  or  procedures  may  deteriorate.   /s/  PricewaterhouseCoopers  LLP   PricewaterhouseCoopers  LLP   Cleveland,  Ohio   February  16,  2016   (In  millions)   REVENUES:   Electric  utilities   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  long-­lived  assets   Total  operating  expenses   OPERATING  INCOME   OTHER  INCOME  (EXPENSE):   Loss  on  debt  redemptions   Investment  income  (loss)   Impairment  of  equity  method  investment   Interest  expense   Capitalized  financing  costs   Total  other  expense   INCOME  TAXES  (BENEFITS)   INCOME  FROM  CONTINUING  OPERATIONS   NET  INCOME   EARNINGS  PER  SHARE  OF  COMMON  STOCK:   Basic  -­  Continuing  Operations   Basic  -­  Discontinued  Operations  (Note  19)   Basic  -­  Net  Income   Diluted  -­  Continuing  Operations   Diluted  -­  Discontinued  Operations  (Note  19)   Diluted  -­  Net  Income   For  the  Years  Ended  December  31,   2015   2014   2013   $   10,636   $   4,390   15,026   9,871   $   5,178   15,049   1,855   4,318   3,749   242   1,282   268   978   42   12,734   2,292   —   (22  )   (362  )   (1,132  )   117   (1,399  )   893   315   578   —   1.37   $   —   1.37   $   1.37   $   —   1.37   $   422   424   1.44   $   2,280   4,716   3,962   835   1,220   12   962   —   13,987   1,062   (8  )   72   —   (1,073  )   118   (891  )   171   (42  )   213   86   0.51   $   0.20   0.71   $   0.51   $   0.20   0.71   $   420   421   1.44   $   $   $   $   $   $   $   9,451   5,441   14,892   2,496   3,963   3,593   (256  )   1,202   539   978   795   13,310   1,582   (132  )   33   —   (1,016  )   103   (1,012  )   570   195   375   17   392   0.90   0.04   0.94   0.90   0.04   0.94   418   419   1.65   INCOME  FROM  CONTINUING  OPERATIONS  BEFORE  INCOME  TAXES  (BENEFITS)   Discontinued  operations  (net  of  income  taxes  of  $0,  $69  and  $9,  respectively)  (Note  19)   578   $   299   $   WEIGHTED  AVERAGE  NUMBER  OF  SHARES  OUTSTANDING:   Basic   Diluted   DIVIDENDS  DECLARED  PER  SHARE  OF  COMMON  STOCK   *   Includes  excise  tax  collections  of  $416  million,  $420  million  and  $458  million  in  2015,  2014  and  2013,  respectively.   The  accompanying  Combined  Notes  to  Consolidated  Financial  Statements  are  an  integral  part  of  these  financial  statements.   62   63                         Report  of  Independent  Registered  Public  Accounting  Firm   To  the  Stockholders  and  Board  of  Directors  of  FirstEnergy  Corp.:   In  our  opinion,  the  accompanying  consolidated  balance  sheets  and  the  related  consolidated  statements  of  income,  comprehensive   income,  common  stockholders’  equity,  and  cash  flows,  present  fairly,  in  all  material  respects,  the  financial  position  of  FirstEnergy   Corp.  and  its  subsidiaries  at  December  31,  2015  and  2014,  and  the  results  of  their  operations  and  their  cash  flows  for  each  of  the   three  years  in  the  period  ended  December  31,  2015  in  conformity  with  accounting  principles  generally  accepted  in  the  United  States   of  America.    In  addition,  in  our  opinion,  the  financial  statement  schedule  listed  in  the  index  appearing  under  Item15(a)(2)  presents   fairly,  in  all  material  respects,  the  information  set  forth  therein  when  read  in  conjunction  with  the  related  consolidated  financial   statements.    Also  in  our  opinion,  the  Company  maintained,  in  all  material  respects,  effective  internal  control  over  financial  reporting  as   of  December  31,  2015,  based  on  criteria  established  in  Internal  Control  -­  Integrated  Framework  (2013)  issued  by  the  Committee  of   Sponsoring  Organizations  of  the  Treadway  Commission  (COSO).    The  Company's  management  is  responsible  for  these  financial   statements  and  financial  statement  schedule,  for  maintaining  effective  internal  control  over  financial  reporting  and  for  its  assessment   of  the  effectiveness  of  internal  control  over  financial  reporting,  included  in  the  accompanying  Management’s  Report  on  Internal   Control  over  Financial  Reporting.    Our  responsibility  is  to  express  opinions  on  these  financial  statements,  on  the  financial  statement   schedule,  and  on  the  Company's  internal  control  over  financial  reporting  based  on  our  integrated  audits.    We  conducted  our  audits  in   accordance  with  the  standards  of  the  Public  Company  Accounting  Oversight  Board  (United  States).    Those  standards  require  that  we   plan  and  perform  the  audits  to  obtain  reasonable  assurance  about  whether  the  financial  statements  are  free  of  material  misstatement   and  whether  effective  internal  control  over  financial  reporting  was  maintained  in  all  material  respects.    Our  audits  of  the  financial   statements  included  examining,  on  a  test   basis,   evidence   supporting   the   amounts   and   disclosures   in   the   financial   statements,   assessing  the  accounting  principles  used  and  significant  estimates  made  by  management,  and  evaluating  the  overall  financial   statement  presentation.    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.   As  discussed  in  Note  1  to  the  consolidated  financial  statements,  in  2015  the  Company  changed  the  manner  in  which  deferred  tax   assets  and  liabilities,  along  with  any  related  valuation  allowance,  are  classified  on  the  balance  sheet.   A  company’s  internal  control  over  financial  reporting  is  a  process  designed  to  provide  reasonable  assurance  regarding  the  reliability  of   financial  reporting  and  the  preparation  of  financial  statements  for  external  purposes  in  accordance  with  generally  accepted  accounting   principles.    A   company’s   internal   control   over   financial   reporting   includes   those   policies   and   procedures   that   (i)  pertain   to   the   maintenance  of  records  that,  in  reasonable  detail,  accurately  and  fairly  reflect  the  transactions  and  dispositions  of  the  assets  of  the   company;;  (ii)  provide  reasonable  assurance  that  transactions  are  recorded  as  necessary  to  permit  preparation  of  financial  statements   in  accordance  with  generally  accepted  accounting  principles,  and  that  receipts  and  expenditures  of  the  company  are  being  made  only   in  accordance  with  authorizations  of  management  and  directors  of  the  company;;  and  (iii)  provide  reasonable  assurance  regarding   prevention  or  timely  detection  of  unauthorized  acquisition,  use,  or  disposition  of  the  company’s  assets  that  could  have  a  material   effect  on  the  financial  statements.   Because  of  its  inherent  limitations,  internal  control  over  financial  reporting  may  not  prevent  or  detect  misstatements.    Also,  projections   of  any  evaluation  of  effectiveness  to  future  periods  are  subject  to  the  risk  that  controls  may  become  inadequate  because  of  changes   in  conditions,  or  that  the  degree  of  compliance  with  the  policies  or  procedures  may  deteriorate.   /s/  PricewaterhouseCoopers  LLP   PricewaterhouseCoopers  LLP   Cleveland,  Ohio   February  16,  2016   FIRSTENERGY  CORP.   CONSOLIDATED  STATEMENTS  OF  INCOME   For  the  Years  Ended  December  31,   2015   2014   2013   $   10,636   $   4,390   15,026   9,871   $   5,178   15,049   (In  millions)   REVENUES:   Electric  utilities   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  long-­lived  assets   Total  operating  expenses   OPERATING  INCOME   OTHER  INCOME  (EXPENSE):   Loss  on  debt  redemptions   Investment  income  (loss)   Impairment  of  equity  method  investment   Interest  expense   Capitalized  financing  costs   Total  other  expense   1,855   4,318   3,749   242   1,282   268   978   42   12,734   2,292   —   (22  )   (362  )   (1,132  )   117   (1,399  )   893   315   578   —   2,280   4,716   3,962   835   1,220   12   962   —   13,987   1,062   (8  )   72   —   (1,073  )   118   (891  )   171   (42  )   213   86   9,451   5,441   14,892   2,496   3,963   3,593   (256  )   1,202   539   978   795   13,310   1,582   (132  )   33   —   (1,016  )   103   (1,012  )   570   195   375   17   392   0.90   0.04   0.94   0.90   0.04   0.94   418   419   1.65   INCOME  FROM  CONTINUING  OPERATIONS  BEFORE  INCOME  TAXES  (BENEFITS)   INCOME  TAXES  (BENEFITS)   INCOME  FROM  CONTINUING  OPERATIONS   Discontinued  operations  (net  of  income  taxes  of  $0,  $69  and  $9,  respectively)  (Note  19)   NET  INCOME   EARNINGS  PER  SHARE  OF  COMMON  STOCK:   Basic  -­  Continuing  Operations   Basic  -­  Discontinued  Operations  (Note  19)   Basic  -­  Net  Income   Diluted  -­  Continuing  Operations   Diluted  -­  Discontinued  Operations  (Note  19)   Diluted  -­  Net  Income   WEIGHTED  AVERAGE  NUMBER  OF  SHARES  OUTSTANDING:   Basic   Diluted   DIVIDENDS  DECLARED  PER  SHARE  OF  COMMON  STOCK   $   $   $   $   $   $   578   $   299   $   1.37   $   —   1.37   $   1.37   $   —   1.37   $   422   424   1.44   $   0.51   $   0.20   0.71   $   0.51   $   0.20   0.71   $   420   421   1.44   $   *   Includes  excise  tax  collections  of  $416  million,  $420  million  and  $458  million  in  2015,  2014  and  2013,  respectively.   The  accompanying  Combined  Notes  to  Consolidated  Financial  Statements  are  an  integral  part  of  these  financial  statements.   62   63                         FIRSTENERGY  CORP.   CONSOLIDATED  STATEMENTS  OF  COMPREHENSIVE  INCOME   (In  millions)   NET  INCOME   OTHER  COMPREHENSIVE  INCOME  (LOSS):   Pension  and  OPEB  prior  service  costs   Amortized  gains  (losses)  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   For  the  Years  Ended  December  31,   2015   2014   2013   $   578   $   299   $   392   (116  )   5   (11  )   (122  )   (47  )   (75  )   (76  )   (2  )   26   (52  )   (14  )   (38  )   (160  )   3   (10  )   (167  )   (66  )   (101  )   COMPREHENSIVE  INCOME  AVAILABLE  TO  FIRSTENERGY   CORP.   $   503   $   261   $   291   The  accompanying  Combined  Notes  to  Consolidated  Financial  Statements  are  an  integral  part  of  these  financial  statements.   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 $69  in  2015  and  $59  in  2014 Other, net of allowance  for uncollectible  accounts of $5  in  2015  and  2014 Materials  and  supplies, at average  cost December 31, December 31, 2015 2014 $ 131 $ Prepaid  taxes Derivatives Collateral Other PROPERTY, PLANT AND  EQUIPMENT: In  service Less  — Accumulated  provision  for depreciation Construction  work  in  progress INVESTMENTS: Nuclear plant decommissioning  trusts Other DEFERRED  CHARGES AND  OTHER  ASSETS: Goodwill Regulatory  assets Other CURRENT LIABILITIES: Currently  payable  long-­term debt Short-­term borrowings Accounts payable Accrued  taxes Accrued  compensation  and  benefits Derivatives Other CAPITALIZATION: Common  stockholders’ equity-­ Other paid-­in capital Retained  earnings Accumulated  other comprehensive  income Total common  stockholders’ equity Noncontrolling  interest Total equity Long-­term debt and  other long-­term obligations NONCURRENT LIABILITIES: Accumulated  deferred  income  taxes Retirement benefits Asset retirement obligations Deferred  gain  on  sale  and  leaseback  transaction Adverse  power  contract  liability Other LIABILITIES AND  CAPITALIZATION 52,187 $ 51,648 $ $ Common  stock, $0.10  par value, authorized  490,000,000  shares  -­ 423,560,397  and  421,102,570   shares outstanding  as of December 31, 2015  and  December 31, 2014, respectively COMMITMENTS, GUARANTEES AND  CONTINGENCIES (Note 15) $ 52,187 $ 51,648 The  accompanying  Combined  Notes to  Consolidated  Financial Statements are  an  integral part of these  financial statements. 1,415 180 785 135 157 70 167 3,040 49,952 15,160 34,792 2,422 37,214 2,282 506 2,788 6,418 1,348 1,379 9,145 1,166 $ 1,708 1,075 519 334 106 694 5,602 42 9,952 171 2,256 12,421 1 12,422 19,192 31,614 6,773 4,245 1,410 791 197 1,555 14,971 85 1,554 225 817 128 159 230 160 3,358 47,484 14,150 33,334 2,449 35,783 2,341 881 3,222 6,418 1,411 1,456 9,285 804 1,799 1,279 490 329 167 693 5,561 42 9,847 246 2,285 12,420 2 12,422 19,176 31,598 6,539 3,932 1,387 824 217 1,590 14,489 64   65 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  $69  in  2015  and  $59  in  2014   Other,  net  of  allowance  for  uncollectible  accounts  of  $5  in  2015  and  2014   Materials  and  supplies,  at  average  cost   Prepaid  taxes   Derivatives   Collateral   Other   PROPERTY,  PLANT  AND  EQUIPMENT:   In  service   Less  —  Accumulated  provision  for  depreciation   Construction  work  in  progress   INVESTMENTS:   Nuclear  plant  decommissioning  trusts   Other   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   Derivatives   Other   CAPITALIZATION:   Common  stockholders’  equity-­   Common  stock,  $0.10  par  value,  authorized  490,000,000  shares  -­  423,560,397  and  421,102,570   shares  outstanding  as  of  December  31,  2015  and  December  31,  2014,  respectively   Other  paid-­in  capital   Accumulated  other  comprehensive  income   Retained  earnings   Total  common  stockholders’  equity   Noncontrolling  interest   Total  equity   Long-­term  debt  and  other  long-­term  obligations   NONCURRENT  LIABILITIES:   Accumulated  deferred  income  taxes   Retirement  benefits   Asset  retirement  obligations   Deferred  gain  on  sale  and  leaseback  transaction   Adverse  power  contract  liability   Other   COMMITMENTS,  GUARANTEES  AND  CONTINGENCIES  (Note  15)   December  31,    2015   December  31,    2014   $   $   $   $   131   $   1,415   180   785   135   157   70   167   3,040   49,952   15,160   34,792   2,422   37,214   2,282   506   2,788   6,418   1,348   1,379   9,145   52,187   $   1,166   $   1,708   1,075   519   334   106   694   5,602   42   9,952   171   2,256   12,421   1   12,422   19,192   31,614   6,773   4,245   1,410   791   197   1,555   14,971   52,187   $   85   1,554   225   817   128   159   230   160   3,358   47,484   14,150   33,334   2,449   35,783   2,341   881   3,222   6,418   1,411   1,456   9,285   51,648   804   1,799   1,279   490   329   167   693   5,561   42   9,847   246   2,285   12,420   2   12,422   19,176   31,598   6,539   3,932   1,387   824   217   1,590   14,489   51,648   The  accompanying  Combined  Notes  to  Consolidated  Financial  Statements  are  an  integral  part  of  these  financial  statements.   65         CONSOLIDATED  STATEMENTS  OF  COMMON  STOCKHOLDERS'  EQUITY   FIRSTENERGY  CORP.    FIRSTENERGY  CORP.   CONSOLIDATED  STATEMENTS  OF  CASH  FLOWS   (In  millions,  except  share  amounts)   Net  income   Amortized  losses  on  derivative  hedges,  net  of   $1  million  of  income  taxes   Change  in  unrealized  gain  on  investments,  net   of  $4  million  of  income  tax  benefits   Pension  and  OPEB,  net  of  $63  million  of  income   tax  benefits  (Note  3)   Stock-­based  compensation   Cash  dividends  declared  on  common  stock   Stock  issuance  -­  employee  benefits   Balance,  December  31,  2013   Net  income   Amortized  gains  on  derivative  hedges,  net  of   $1  million  of  income  tax  benefits   Change  in  unrealized  gain  on  investments,  net   of  $10  million  of  income  taxes   Pension  and  OPEB,  net  of  $23  million  of  income   tax  benefits  (Note  3)   Stock-­based  compensation   Cash  dividends  declared  on  common  stock   Stock  issuance  -­  employee  benefits   Balance,  December  31,  2014   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   Pension  and  OPEB,  net  of  $44  million  of  income   tax  benefits  (Note  3)   Stock-­based  compensation   Cash  dividends  declared  on  common  stock   Common  Stock   Number  of   Shares   418,216,437   $   Par  Value   Other   Paid-­In   Capital   Accumulated   Other   Comprehensive   Income   42   $   9,769   $   385   $   Retained   Earnings   2,888   392   2   (6  )   (97  )   412,122   (4  )   11   418,628,559   42   9,776   284   (690  )   2,590   299   (604  )   2,285   578   (1  )   16   (53  )   246   4   (7  )   (72  )   20   51   9,847   45   60   9,952   $   2,474,011   421,102,570   42   Stock  issuance  -­  employee  benefits   Balance,  December  31,  2015   2,457,827   423,560,397   $   42   $   (607  )   171   $   2,256   The  accompanying  Combined  Notes  to  Consolidated  Financial  Statements  are  an  integral  part  of  these  financial  statements.   The  accompanying  Combined  Notes  to  Consolidated  Financial  Statements  are  an  integral  part  of  these  financial  statements.   66   67   Adjustments  to  reconcile  net  income  to  net  cash  from  operating  activities-­   Depreciation  and  amortization,  including  nuclear  fuel,  regulatory  assets,  net,  and  customer  intangible  amortization   (In  millions)   Net  Income   CASH  FLOWS  FROM  OPERATING  ACTIVITIES:   Impairments  of  long-­lived  assets   Investment  impairment,  including  equity  method  investment   Pension  and  OPEB  mark-­to-­market  adjustment   Deferred  income  taxes  and  investment  tax  credits,  net   Deferred  costs  on  sale  leaseback  transaction,  net   For  the  Years  Ended  December  31,   2015   2014   2013   $   578   $   299   $   Deferred  purchased  power  and  other  costs   Asset  removal  costs  charged  to  income   Retirement  benefits   Commodity  derivative  transactions,  net  (Note  10)   Pension  trust  contributions   Gain  on  sale  of  investment  securities  held  in  trusts   Loss  on  debt  redemptions   Make-­whole  premiums  paid  on  debt  redemptions   Lease  payments  on  sale  and  leaseback  transaction   Income  from  discontinued  operations  (Note  19)   Changes  in  current  assets  and  liabilities-­   Receivables   Materials  and  supplies   Prepayments  and  other  current  assets   Accounts  payable   Accrued  taxes   Accrued  interest   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   Tender  premiums  paid  on  debt  redemptions   Common  stock  dividend  payments   Other   Net  cash  (used  for)  provided  from  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   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:   Cash  paid  (received)  during  the  year  -­   Interest  (net  of  amounts  capitalized)   Income  taxes  (received),  net  of  refunds   1,836   42   464   242   284   48   (105  )   55   (20  )   (73  )   (143  )   (23  )   —   —   (131  )   —   184   (15  )   (10  )   (243  )   29   (6  )   5   75   140   234   3,447   1,311   —   (879  )   (91  )   —   (607  )   (13  )   (279  )   (2,704  )   (190  )   20   1,534   (1,648  )   (142  )   7   1   (3,122  )   1,563   —   37   835   162   48   (115  )   28   (53  )   64   —   (64  )   8   —   (137  )   (86  )   139   (65  )   126   42   (165  )   31   (22  )   23   (54  )   69   2,713   4,528   —   (1,759  )   (1,605  )   —   (604  )   (47  )   513   (3,312  )   (233  )   394   2,133   (2,236  )   35   (153  )   13   (3,359  )   46   85   131   $   (133  )   218   85   $   1,028   $   37   $   931   $   (103  )   $   $   $   $   392   2,022   795   90   (256  )   243   48   (76  )   20   (168  )   (3  )   —   (56  )   132   (187  )   (136  )   (17  )   (114  )   96   (126  )   (25  )   85   (10  )   19   (62  )   (36  )   (8  )   2,662   3,745   1,435   (3,600  )   —   (110  )   (920  )   (73  )   477   (2,638  )   (250  )   4   2,047   (2,096  )   (23  )   (146  )   9   (3,093  )   46   172   218   969   36               CONSOLIDATED  STATEMENTS  OF  COMMON  STOCKHOLDERS'  EQUITY   FIRSTENERGY  CORP.    FIRSTENERGY  CORP.   CONSOLIDATED  STATEMENTS  OF  CASH  FLOWS   (In  millions,  except  share  amounts)   Net  income   Amortized  losses  on  derivative  hedges,  net  of   $1  million  of  income  taxes   Change  in  unrealized  gain  on  investments,  net   of  $4  million  of  income  tax  benefits   Pension  and  OPEB,  net  of  $63  million  of  income   tax  benefits  (Note  3)   Stock-­based  compensation   Cash  dividends  declared  on  common  stock   Stock  issuance  -­  employee  benefits   Balance,  December  31,  2013   Net  income   Amortized  gains  on  derivative  hedges,  net  of   $1  million  of  income  tax  benefits   Change  in  unrealized  gain  on  investments,  net   of  $10  million  of  income  taxes   Pension  and  OPEB,  net  of  $23  million  of  income   tax  benefits  (Note  3)   Stock-­based  compensation   Cash  dividends  declared  on  common  stock   Stock  issuance  -­  employee  benefits   Balance,  December  31,  2014   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   Pension  and  OPEB,  net  of  $44  million  of  income   tax  benefits  (Note  3)   Stock-­based  compensation   Cash  dividends  declared  on  common  stock   Stock  issuance  -­  employee  benefits   Balance,  December  31,  2015   Common  Stock   Number  of   Shares   Par  Value   Other   Paid-­In   Capital   Accumulated   Other   Comprehensive   Income   418,216,437   $   42   $   9,769   $   385   $   Retained   Earnings   2,888   392   412,122   418,628,559   42   9,776   284   2   (6  )   (97  )   (1  )   16   (53  )   246   4   (7  )   (72  )   (690  )   2,590   299   (604  )   2,285   578   (607  )   (4  )   11   20   51   9,847   45   60   2,474,011   421,102,570   42   The  accompanying  Combined  Notes  to  Consolidated  Financial  Statements  are  an  integral  part  of  these  financial  statements.   2,457,827   423,560,397   $   42   $   9,952   $   171   $   2,256   (In  millions)   CASH  FLOWS  FROM  OPERATING  ACTIVITIES:   Net  Income   Adjustments  to  reconcile  net  income  to  net  cash  from  operating  activities-­   Depreciation  and  amortization,  including  nuclear  fuel,  regulatory  assets,  net,  and  customer  intangible  amortization   Impairments  of  long-­lived  assets   Investment  impairment,  including  equity  method  investment   Pension  and  OPEB  mark-­to-­market  adjustment   Deferred  income  taxes  and  investment  tax  credits,  net   Deferred  costs  on  sale  leaseback  transaction,  net   Deferred  purchased  power  and  other  costs   Asset  removal  costs  charged  to  income   Retirement  benefits   Commodity  derivative  transactions,  net  (Note  10)   Pension  trust  contributions   Gain  on  sale  of  investment  securities  held  in  trusts   Loss  on  debt  redemptions   Make-­whole  premiums  paid  on  debt  redemptions   Lease  payments  on  sale  and  leaseback  transaction   Income  from  discontinued  operations  (Note  19)   Changes  in  current  assets  and  liabilities-­   Receivables   Materials  and  supplies   Prepayments  and  other  current  assets   Accounts  payable   Accrued  taxes   Accrued  interest   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   Tender  premiums  paid  on  debt  redemptions   Common  stock  dividend  payments   Other   Net  cash  (used  for)  provided  from  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   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:   Cash  paid  (received)  during  the  year  -­   Interest  (net  of  amounts  capitalized)   Income  taxes  (received),  net  of  refunds   For  the  Years  Ended  December  31,   2015   2014   2013   $   578   $   299   $   1,836   42   464   242   284   48   (105  )   55   (20  )   (73  )   (143  )   (23  )   —   —   (131  )   —   184   (15  )   (10  )   (243  )   29   (6  )   5   75   140   234   3,447   1,311   —   (879  )   (91  )   —   (607  )   (13  )   (279  )   (2,704  )   (190  )   20   1,534   (1,648  )   7   (142  )   1   (3,122  )   46   85   131   $   1,563   —   37   835   162   48   (115  )   28   (53  )   64   —   (64  )   8   —   (137  )   (86  )   139   (65  )   126   42   (165  )   31   (22  )   23   (54  )   69   2,713   4,528   —   (1,759  )   (1,605  )   —   (604  )   (47  )   513   (3,312  )   (233  )   394   2,133   (2,236  )   35   (153  )   13   (3,359  )   (133  )   218   85   $   1,028   $   37   $   931   $   (103  )   $   $   $   $   392   2,022   795   90   (256  )   243   48   (76  )   20   (168  )   (3  )   —   (56  )   132   (187  )   (136  )   (17  )   (114  )   96   (126  )   (25  )   85   (10  )   19   (62  )   (36  )   (8  )   2,662   3,745   1,435   (3,600  )   —   (110  )   (920  )   (73  )   477   (2,638  )   (250  )   4   2,047   (2,096  )   (23  )   (146  )   9   (3,093  )   46   172   218   969   36   The  accompanying  Combined  Notes  to  Consolidated  Financial  Statements  are  an  integral  part  of  these  financial  statements.   66   67               FIRSTENERGY  CORP.  AND  SUBSIDIARIES   COMBINED  NOTES  TO  CONSOLIDATED  FINANCIAL  STATEMENTS   COMBINED  NOTES  TO  CONSOLIDATED  FINANCIAL  STATEMENTS   1.  ORGANIZATION  AND  BASIS  OF  PRESENTATION   Note   Number   Page   Number   of  Terms.   1   2   3   4   5   6   7   8   9   Organization  and  Basis  of  Presentation ...........................................................................................   Accumulated  Other  Comprehensive  Income ....................................................................................   Pension  and  Other  Postemployment  Benefits ..................................................................................   Stock-­Based  Compensation  Plans ...................................................................................................   Taxes ................................................................................................................................................   Leases ..............................................................................................................................................   Intangible  Assets ..............................................................................................................................   Variable  Interest  Entities ...................................................................................................................   Fair  Value  Measurements .................................................................................................................   69   76   79   86   89   95   96   96   99   10   Derivative  Instruments ......................................................................................................................   104   11   Capitalization ....................................................................................................................................   109   12   Short-­Term  Borrowings  and  Bank  Lines  of  Credit ............................................................................   114   13   Asset  Retirement  Obligations ...........................................................................................................   115   14   Regulatory  Matters ...........................................................................................................................   116   15   Commitments,  Guarantees  and  Contingencies ................................................................................   124   16   Transactions  with  Affiliated  Companies ............................................................................................   130   liabilities  based  on  federal  and  state  jurisdictions.   17   Supplemental  Guarantor  Information ...............................................................................................   132   18   Segment  Information ........................................................................................................................   141   19   Discontinued  Operations ..................................................................................................................   143   20   Summary  of  Quarterly  Financial  Data  (Unaudited) ..........................................................................   144   68   69   Unless  otherwise  indicated,  defined  terms  and  abbreviations  used  herein  have  the  meanings  set  forth  in  the  accompanying  Glossary   FirstEnergy  Corp.  was  organized  under  the  laws  of  the  State  of  Ohio  in  1996.  FE’s  principal  business  is  the  holding,  directly  or   indirectly,  of  all  of  the  outstanding  common  stock  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   and  TrAIL),   and  AESC.   In   addition,   FE   holds   all   of   the   outstanding   common   stock   of   other   direct   subsidiaries   including:   FirstEnergy  Properties,  Inc.,  FEV,  FENOC,  FELHC,  Inc.,  GPU  Nuclear,  Inc.,  and  AE  Ventures,  Inc.     FirstEnergy  and  its  subsidiaries  are  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,  serving  six  million  customers  in  the   Midwest  and  Mid-­Atlantic  regions.  Its  generation  subsidiaries  control  nearly  17,000  MW  of  capacity  from  a  diverse  mix  of  non-­emitting   nuclear,  scrubbed  coal,  natural  gas,  hydroelectric  and  other  renewables.  FirstEnergy’s  transmission  operations  include  approximately   24,000  miles  of  lines  and  two  regional  transmission  operation  centers.     FirstEnergy  follows  GAAP  and  complies  with  the  related  regulations,  orders,  policies  and  practices  prescribed  by  the  SEC,  FERC,   and,  as  applicable,  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,  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  8,  Variable   Interest  Entities).  Investments  in  affiliates  over  which  FE  and  its  subsidiaries  have  the  ability  to  exercise  significant  influence,  but  with   respect  to  which  they  are  not  the  primary  beneficiary  and  do  not  exercise  control,  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  share  of   the   entity’s   earnings   is   reported   in   the   Consolidated   Statements   of   Income   and   Comprehensive   Income.   These   Notes   to   the   Consolidated  Financial  Statements  are  combined  for  FirstEnergy  and  FES.   Certain  prior  year  amounts  have  been  reclassified  to  conform  to  the  current  year  presentation.   ACCOUNTING  FOR  THE  EFFECTS  OF  REGULATION   FirstEnergy  accounts  for  the  effects  of  regulation  through  the  application  of  regulatory  accounting  to  the  Utilities,  AGC,  ATSI,  PATH   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   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                                   FIRSTENERGY  CORP.  AND  SUBSIDIARIES   COMBINED  NOTES  TO  CONSOLIDATED  FINANCIAL  STATEMENTS   COMBINED  NOTES  TO  CONSOLIDATED  FINANCIAL  STATEMENTS   1.  ORGANIZATION  AND  BASIS  OF  PRESENTATION   Note   Number   1   2   3   4   5   6   7   8   9   Organization  and  Basis  of  Presentation ...........................................................................................   Accumulated  Other  Comprehensive  Income ....................................................................................   Pension  and  Other  Postemployment  Benefits ..................................................................................   Stock-­Based  Compensation  Plans ...................................................................................................   Taxes ................................................................................................................................................   Leases ..............................................................................................................................................   Intangible  Assets ..............................................................................................................................   Variable  Interest  Entities ...................................................................................................................   Fair  Value  Measurements .................................................................................................................   Page   Number   69   76   79   86   89   95   96   96   99   10   Derivative  Instruments ......................................................................................................................   104   11   Capitalization ....................................................................................................................................   109   12   Short-­Term  Borrowings  and  Bank  Lines  of  Credit ............................................................................   114   13   Asset  Retirement  Obligations ...........................................................................................................   115   14   Regulatory  Matters ...........................................................................................................................   116   15   Commitments,  Guarantees  and  Contingencies ................................................................................   124   16   Transactions  with  Affiliated  Companies ............................................................................................   130   17   Supplemental  Guarantor  Information ...............................................................................................   132   18   Segment  Information ........................................................................................................................   141   19   Discontinued  Operations ..................................................................................................................   143   20   Summary  of  Quarterly  Financial  Data  (Unaudited) ..........................................................................   144   Unless  otherwise  indicated,  defined  terms  and  abbreviations  used  herein  have  the  meanings  set  forth  in  the  accompanying  Glossary   of  Terms.   FirstEnergy  Corp.  was  organized  under  the  laws  of  the  State  of  Ohio  in  1996.  FE’s  principal  business  is  the  holding,  directly  or   indirectly,  of  all  of  the  outstanding  common  stock  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   and  TrAIL),   and  AESC.   In   addition,   FE   holds   all   of   the   outstanding   common   stock   of   other   direct   subsidiaries   including:   FirstEnergy  Properties,  Inc.,  FEV,  FENOC,  FELHC,  Inc.,  GPU  Nuclear,  Inc.,  and  AE  Ventures,  Inc.     FirstEnergy  and  its  subsidiaries  are  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,  serving  six  million  customers  in  the   Midwest  and  Mid-­Atlantic  regions.  Its  generation  subsidiaries  control  nearly  17,000  MW  of  capacity  from  a  diverse  mix  of  non-­emitting   nuclear,  scrubbed  coal,  natural  gas,  hydroelectric  and  other  renewables.  FirstEnergy’s  transmission  operations  include  approximately   24,000  miles  of  lines  and  two  regional  transmission  operation  centers.     FirstEnergy  follows  GAAP  and  complies  with  the  related  regulations,  orders,  policies  and  practices  prescribed  by  the  SEC,  FERC,   and,  as  applicable,  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,  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  8,  Variable   Interest  Entities).  Investments  in  affiliates  over  which  FE  and  its  subsidiaries  have  the  ability  to  exercise  significant  influence,  but  with   respect  to  which  they  are  not  the  primary  beneficiary  and  do  not  exercise  control,  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  share  of   the   entity’s   earnings   is   reported   in   the   Consolidated   Statements   of   Income   and   Comprehensive   Income.   These   Notes   to   the   Consolidated  Financial  Statements  are  combined  for  FirstEnergy  and  FES.   Certain  prior  year  amounts  have  been  reclassified  to  conform  to  the  current  year  presentation.   ACCOUNTING  FOR  THE  EFFECTS  OF  REGULATION   FirstEnergy  accounts  for  the  effects  of  regulation  through  the  application  of  regulatory  accounting  to  the  Utilities,  AGC,  ATSI,  PATH   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   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.   68   69                                   The  following  table  provides  information  about  the  composition  of  net  regulatory  assets  as  of  December  31,  2015  and  December  31,   2014,  and  the  changes  during  the  year  ended  December  31,  2015:   Regulatory  Assets  by  Source   December  31,    2015   December  31,    2014   Increase   (Decrease)   (In  millions)   Regulatory  transition  costs   $   Customer  receivables  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   185   $   355   (272  )   (372  )   115   243   335   186   403   170   240   $   370   (305  )   (254  )   90   281   182   153   465   189   Net  Regulatory  Assets  included  on  the  Consolidated  Balance  Sheets   $   1,348   $   1,411   $   (55  )   (15  )   33   (118  )   25   (38  )   153   33   (62  )   (19  )   (63  )   Regulatory  assets  that  do  not  earn  a  current  return  totaled  approximately $148  million  and  $488  million  as  of  December  31,  2015  and   2014, respectively,  primarily  related  to  storm  damage  costs.  JCP&L's  regulatory  asset  related  to  2011  and  2012  storm  damage  costs   began  earning  a  return  on  April  1,  2015.  Effective  with  the  approved  settlement  on  April  9,  2015,  associated  with  their  general  base   rate  case,  the  Pennsylvania  Companies  transferred  the  net  book  value  of  legacy  meters  from  plant-­in-­service  to  regulatory  assets,   which  is  being  recovered  over  five  years.     As  of  December  31,  2015 and  December  31,  2014,  FirstEnergy  had  approximately  $116  million  and  $243  million of  net  regulatory   liabilities  that  are  primarily  related  to  asset  removal  costs.  Net  regulatory  liabilities  are  classified  within  other  noncurrent  liabilities  on   the  Consolidated  Balance  Sheets.   REVENUES  AND  RECEIVABLES   The  Utilities'  principal  business  is  providing  electric  service  to  customers  in  Ohio,  Pennsylvania,  West  Virginia,  New  Jersey  and   Maryland.  FES'  principal  business  is  supplying  electric  power  to  end-­use  customers  through  retail  and  wholesale  arrangements,   including  affiliated  company  power  sales  to  meet  a  portion  of  the  POLR  and  default  service  requirements,  and  competitive  retail  sales   to  customers  primarily  in  Ohio,  Pennsylvania,  Illinois,  Michigan,  New  Jersey  and  Maryland.  Retail  customers  are  metered  on  a  cycle   basis.   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,  2015  and  2014  with  respect  to  any  particular  segment  of  FirstEnergy’s  customers.  Billed  and  unbilled  customer   receivables  as  of  December  31,  2015  and  2014  are  included  below.   70                   Regulatory  Assets  by  Source   Regulatory  transition  costs   Customer  receivables  for  future  income  taxes   Nuclear  decommissioning  and  spent  fuel  disposal  costs   Asset  removal  costs   Deferred  transmission  costs   Deferred  generation  costs   Deferred  distribution  costs   Contract  valuations   Storm-­related  costs   Other   December  31,   December  31,    2015    2014   Increase   (Decrease)   $   185   $   240   $   (In  millions)   355   (272  )   (372  )   115   243   335   186   403   170   370   (305  )   (254  )   90   281   182   153   465   189   (55  )   (15  )   33   (118  )   25   (38  )   153   33   (62  )   (19  )   (63  )   Net  Regulatory  Assets  included  on  the  Consolidated  Balance  Sheets   $   1,348   $   1,411   $   Regulatory  assets  that  do  not  earn  a  current  return  totaled  approximately $148  million  and  $488  million  as  of  December  31,  2015  and   2014, respectively,  primarily  related  to  storm  damage  costs.  JCP&L's  regulatory  asset  related  to  2011  and  2012  storm  damage  costs   began  earning  a  return  on  April  1,  2015.  Effective  with  the  approved  settlement  on  April  9,  2015,  associated  with  their  general  base   rate  case,  the  Pennsylvania  Companies  transferred  the  net  book  value  of  legacy  meters  from  plant-­in-­service  to  regulatory  assets,   which  is  being  recovered  over  five  years.     As  of  December  31,  2015 and  December  31,  2014,  FirstEnergy  had  approximately  $116  million  and  $243  million of  net  regulatory   liabilities  that  are  primarily  related  to  asset  removal  costs.  Net  regulatory  liabilities  are  classified  within  other  noncurrent  liabilities  on   the  Consolidated  Balance  Sheets.   REVENUES  AND  RECEIVABLES   The  Utilities'  principal  business  is  providing  electric  service  to  customers  in  Ohio,  Pennsylvania,  West  Virginia,  New  Jersey  and   Maryland.  FES'  principal  business  is  supplying  electric  power  to  end-­use  customers  through  retail  and  wholesale  arrangements,   including  affiliated  company  power  sales  to  meet  a  portion  of  the  POLR  and  default  service  requirements,  and  competitive  retail  sales   to  customers  primarily  in  Ohio,  Pennsylvania,  Illinois,  Michigan,  New  Jersey  and  Maryland.  Retail  customers  are  metered  on  a  cycle   basis.   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,  2015  and  2014  with  respect  to  any  particular  segment  of  FirstEnergy’s  customers.  Billed  and  unbilled  customer   receivables  as  of  December  31,  2015  and  2014  are  included  below.   The  following  table  provides  information  about  the  composition  of  net  regulatory  assets  as  of  December  31,  2015  and  December  31,   2014,  and  the  changes  during  the  year  ended  December  31,  2015:   Customer  Receivables   Customer  Receivables   FirstEnergy   FirstEnergy   FES   FES   December  31,  2015   December  31,  2015   Billed   Billed   Unbilled   Unbilled   Total   Total   December  31,  2014   December  31,  2014   Billed   Billed   Unbilled   Unbilled   Total   Total   (In  millions)   (In  millions)   836   $   836   $   579   579   1,415   $   1,415   $   914   $   914   $   640   640   1,554   $   1,554   $   165   165   110   110   275   275   239   239   176   176   415   415   $   $   $   $   $   $   $   $   EARNINGS  PER  SHARE  OF  COMMON  STOCK   EARNINGS  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.  The  following  table  reconciles  basic  and  diluted  earnings  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.  The  following  table  reconciles  basic  and  diluted  earnings  per  share  of  common   stock:   Reconciliation  of  Basic  and  Diluted  Earnings  per  Share  of  Common  Stock   Reconciliation  of  Basic  and  Diluted  Earnings  per  Share  of  Common  Stock   Income  from  continuing  operations  available  to  common  shareholders   Income  from  continuing  operations  available  to  common  shareholders   Discontinued  operations  (Note  19)   Discontinued  operations  (Note  19)   Net  income   Net  income   2013   2013   2015   2015   2014   2014   (In  millions,  except  per  share  amounts)   (In  millions,  except  per  share  amounts)   375   375   17   17   392   392   578   $   578   $   —   —   578   $   578   $   213   $   213   $   86   86   299   $   299   $   $   $   $   $   Weighted  average  number  of  basic  shares  outstanding   Weighted  average  number  of  basic  shares  outstanding   Assumed  exercise  of  dilutive  stock  options  and  awards(1)   Assumed  exercise  of  dilutive  stock  options  and  awards(1)   Weighted  average  number  of  diluted  shares  outstanding   Weighted  average  number  of  diluted  shares  outstanding   422   422   2   2   424   424   420   420   1   1   421   421   Earnings  per  share:   Earnings  per  share:   Basic  earnings  per  share:   Basic  earnings  per  share:   Continuing  operations   Continuing  operations   Discontinued  operations  (Note  19)   Discontinued  operations  (Note  19)   Earnings  per  basic  share   Earnings  per  basic  share   Diluted  earnings  per  share:   Diluted  earnings  per  share:   Continuing  operations   Continuing  operations   Discontinued  operations  (Note  19)   Discontinued  operations  (Note  19)   Earnings  per  diluted  share   Earnings  per  diluted  share   $   $   $   $   $   $   $   $   1.37   $   1.37   $   —   —   1.37   $   1.37   $   0.51   $   0.51   $   0.20   0.20   0.71   $   0.71   $   1.37   $   1.37   $   —   —   1.37   $   1.37   $   0.51   $   0.51   $   0.20   0.20   0.71   $   0.71   $   418   418   1   1   419   419   0.90   0.90   0.04   0.04   0.94   0.94   0.90   0.90   0.04   0.04   0.94   0.94   (1)   (1)   For  the  years  ended  December  31,  2015, 2014  and  2013,  approximately  one  million,  two  million,  and  two  million  shares  were  excluded  from  the   calculation  of  diluted  shares  outstanding,  respectively,  as  their  inclusion  would  be  antidilutive.     For  the  years  ended  December  31,  2015, 2014  and  2013,  approximately  one  million,  two  million,  and  two  million  shares  were  excluded  from  the   calculation  of  diluted  shares  outstanding,  respectively,  as  their  inclusion  would  be  antidilutive.     PROPERTY,  PLANT  AND  EQUIPMENT   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.  The  cost  of  nuclear  fuel  included  in  CES'  net  plant  as   of  December  31,  2015  was  $418  million.  Net  plant  in  service  balances  by  segment  as  of  December  31,  2015  and  2014  were  as   follows:   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.  The  cost  of  nuclear  fuel  included  in  CES'  net  plant  as   of  December  31,  2015  was  $418  million.  Net  plant  in  service  balances  by  segment  as  of  December  31,  2015  and  2014  were  as   follows:   70   71   71                                       Property,  Plant  and  Equipment   December  31,  2015   In  Service(2)   Accum.  Depr.   Net  Plant   December  31,  2014   In  Service(2)   Accum.  Depr.   Net  Plant   Regulated  Distribution   Regulated  Transmission   Competitive  Energy  Services(1)   Corporate/Other   Total   $   $   24,553   $   7,703   17,214   482   49,952   $   (In  millions)   (7,058  )   $   (1,647  )   (6,213  )   (242  )   (15,160  )   $   17,495   $   6,056   11,001   240   34,792   $   23,973   $   6,634   16,442   435   47,484   $   (6,759  )   $   (1,595  )   (5,598  )   (198  )   (14,150  )   $   17,214   5,039   10,844   237   33,334   (1)  Primarily  consists  of  generating  assets  and  nuclear  fuel  as  discussed  above.   (2)Includes  capital  leases  of  $253  million  and  $281  million  at  December  31,  2015  and  2014,  respectively.     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  $2.0  billion  of  regulated  generation  net  plant  in  service.   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  2015,  2014  and  2013  are  shown  in  the   following  table:     Annual  Composite  Depreciation  Rate   2015   2014   2013   FirstEnergy   FES   2.5  %   3.2  %   2.5  %   3.1  %   2.6  %   3.1  %   For  the  years  ended  December  31,  2015,  2014  and  2013,  capitalized  financing  costs  on  FirstEnergy's  Consolidated  Statements  of   Income  include  $49  million,  $49  million  and  $28  million,  respectively,  of  allowance  for  equity  funds  used  during  construction  and  $68   million,  $69  million  and  $75  million,  respectively,  of  capitalized  interest.     million).   Goodwill   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,  Virginia  Electric  and  Power  Company,  a  non-­affiliated  utility.  Net  Property,  plant   and  equipment  includes  $666  million  representing  AGC's  share  in  this  facility  as  of  December  31,  2015  of  which  $484  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.     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.  This  approach  applies   probability  weighting  to  discounted  future  cash  flow  scenarios  that  reflect  a  range  of  possible  outcomes.  The  scenarios  consider   settlement  of  the  ARO  at  the  expiration  of  the  nuclear  power  plant's  current  license,  settlement  based  on  an  extended  license  term   and  expected  remediation  dates.  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,  2015,  are  described  further  in  Note  13,  Asset  Retirement  Obligations.     ASSET  IMPAIRMENTS   Long-­lived  Assets   FirstEnergy  reviews  long-­lived  assets  for  impairment  whenever  events  or  changes  in  circumstances  indicate  that  the  carrying  value  of   such  assets  may  not  be  recoverable.  The  recoverability  of  a  long-­lived  asset  is  measured  by  comparing  its  carrying  value  to  the  sum   of  undiscounted  future  cash  flows  expected  to  result  from  the  use  and  eventual  disposition  of  the  asset.  If  the  carrying  value  is  greater   than  the  undiscounted  cash  flows,  an  impairment  exists  and  a  loss  is  recognized  for  the  amount  by  which  the  carrying  value  of  the   long-­lived  asset  exceeds  its  estimated  fair  value.  FirstEnergy  utilizes  the  income  approach,  based  upon  discounted  cash  flows  to   estimate  fair  value.     On  October  9,  2013,  MP  sold  its  approximate  8%  share  of  Pleasants  at  its  fair  market  value  of  $73  million  to  AE  Supply,  and  AE   Supply  sold  its  approximate  80%  share  of  Harrison  to  MP  at  its  book  value  of  $1.2  billion.  The  transaction  resulted  in  AE  Supply   receiving  net  consideration  of  $1.1  billion  and  MP's  assumption  of  a  $73.5  million   pollution  control  note.  In  connection  with  the   transaction,  MP  recorded  a  pre-­tax  impairment  charge  of  approximately  $322  million  to  reduce  the  net  book  value  of  the  Harrison   Power  Station  to  the  amount  that  was  permitted  to  be  included  in  jurisdictional  rate  base.  Additionally,  MP  recognized  a  regulatory   liability  of  approximately  $23  million  in  2013  representing  refunds  to  customers  associated  with  the  excess  purchase  price  received  by   MP  above  the  net  book  value  of  MP's  minority  interest  in  the  Pleasants  Power  Station.  The  impairment  charge  recognized  in  2013  is   included  within  the  results  of  the  Regulated  Distribution  segment.   On  July  8,  2013,  officers  of  FirstEnergy  and  AE  Supply  committed  to  deactivating  the  Hatfield's  Ferry,  generating  Units  1-­3,  and   Mitchell,  generating  units  2-­3.  As  a  result  of  this  decision  FirstEnergy  recorded  a  pre-­tax  impairment  of  approximately  $473  million  to   continuing  operations,  which  also  includes  pre-­tax  impairments  of  $13  million  related  to  excessive  inventory  at  these  facilities.  The   impairment  charge  recognized  in  2013  is  included  within  the  results  of  the  CES  segment.  On  October  9,  2013,  Hatfield's  Ferry  Units   1-­3  and  Mitchell  Units  2-­3  were  deactivated.     During  2015,  FirstEnergy  recognized  impairments  totaling  $42  million  associated  with  certain  non-­core  assets,  including  equipment   and  facilities.  The  impairment  charges  are  included  within  the  Regulated  Distribution  segment  ($8  million)  and  the  CES  segment  ($34   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.   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:   Goodwill   Regulated   Distribution   Regulated   Transmission   Competitive   Energy   Services   Consolidated   Balance  as  of  December  31,  2015   526   $   800   $   6,418   (In  millions)   $   5,092   $   There  were  no  changes  in  goodwill  for  any  reporting  unit  during  2015.  As  of  December  31,  2015  and  2014,  total  goodwill  recognized   by  FES  was  $23  million.  Neither  FirstEnergy  nor  FES  has  accumulated  impairment  charges  as  of  December  31,  2015.   Annual  impairment  testing  is  conducted  as  of  July  31  of  each  year  and  for  2015,  2014  and  2013,  the  analysis  indicated  no  impairment   of  goodwill.  For  2015,  FirstEnergy  performed  a  qualitative  assessment  of  the  Regulated  Distribution  and  Regulated  Transmission   reporting   units,   assessing   economic,   industry   and   market   considerations   in   addition   to   the   reporting   unit's   overall   financial   performance.  It  was  determined  that  the  fair  value  of  these  reporting  units  were,  more  likely  than  not,  greater  than  their  carrying  value   and  a  quantitative  analysis  was  not  necessary  for  2015.   FirstEnergy  performed  a  quantitative  assessment  of  the  CES  reporting  unit  as  of  July  31,  2015.    Key  assumptions  incorporated  into   the  CES  discounted  cash  flow  analysis  requiring  significant  management  judgment  included  the  following:   •     Future  Energy  and  Capacity  Prices:  FirstEnergy  used  observable  market  information  for  near  term  forward  power  prices,   PJM  auction  results  for  near  term  capacity  pricing,  and  a  longer-­term  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:  FirstEnergy  used  CES'  current  retail  targeted  portfolio  to  estimate  future  retail  sales  volume  as   well  as  historical  financial  results  to  estimate  retail  margins.   72   73                                                 Property,  Plant  and  Equipment   In  Service(2)   Accum.  Depr.   Net  Plant   In  Service(2)   Accum.  Depr.   Net  Plant   December  31,  2015   December  31,  2014   Regulated  Distribution   $   24,553   $   (7,058  )   $   17,495   $   23,973   $   (6,759  )   $   Regulated  Transmission   Competitive  Energy  Services(1)   Corporate/Other   Total   7,703   17,214   482   (1,647  )   (6,213  )   (242  )   6,056   11,001   240   6,634   16,442   435   (1,595  )   (5,598  )   (198  )   $   49,952   $   (15,160  )   $   34,792   $   47,484   $   (14,150  )   $   17,214   5,039   10,844   237   33,334   (In  millions)   (1)  Primarily  consists  of  generating  assets  and  nuclear  fuel  as  discussed  above.   (2)Includes  capital  leases  of  $253  million  and  $281  million  at  December  31,  2015  and  2014,  respectively.     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  $2.0  billion  of  regulated  generation  net  plant  in  service.   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  2015,  2014  and  2013  are  shown  in  the   following  table:     Annual  Composite  Depreciation  Rate   2015   2014   2013   FirstEnergy   FES   2.5  %   3.2  %   2.5  %   3.1  %   2.6  %   3.1  %   For  the  years  ended  December  31,  2015,  2014  and  2013,  capitalized  financing  costs  on  FirstEnergy's  Consolidated  Statements  of   Income  include  $49  million,  $49  million  and  $28  million,  respectively,  of  allowance  for  equity  funds  used  during  construction  and  $68   million,  $69  million  and  $75  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,  Virginia  Electric  and  Power  Company,  a  non-­affiliated  utility.  Net  Property,  plant   and  equipment  includes  $666  million  representing  AGC's  share  in  this  facility  as  of  December  31,  2015  of  which  $484  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.     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.  This  approach  applies   probability  weighting  to  discounted  future  cash  flow  scenarios  that  reflect  a  range  of  possible  outcomes.  The  scenarios  consider   settlement  of  the  ARO  at  the  expiration  of  the  nuclear  power  plant's  current  license,  settlement  based  on  an  extended  license  term   and  expected  remediation  dates.  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.   liability  recognition.   Conditional  retirement  obligations  associated  with  tangible  long-­lived  assets  are  recognized  at  fair  value  in  the  period  in  which  they   are  incurred  if  a  reasonable  estimate  can  be  made,  even  though  there  may  be  uncertainty  about  timing  or  method  of  settlement.   When  settlement  is  conditional  on  a  future  event  occurring,  it  is  reflected  in  the  measurement  of  the  liability,  not  the  timing  of  the   AROs  as  of  December  31,  2015,  are  described  further  in  Note  13,  Asset  Retirement  Obligations.     ASSET  IMPAIRMENTS   Long-­lived  Assets   FirstEnergy  reviews  long-­lived  assets  for  impairment  whenever  events  or  changes  in  circumstances  indicate  that  the  carrying  value  of   such  assets  may  not  be  recoverable.  The  recoverability  of  a  long-­lived  asset  is  measured  by  comparing  its  carrying  value  to  the  sum   of  undiscounted  future  cash  flows  expected  to  result  from  the  use  and  eventual  disposition  of  the  asset.  If  the  carrying  value  is  greater   than  the  undiscounted  cash  flows,  an  impairment  exists  and  a  loss  is  recognized  for  the  amount  by  which  the  carrying  value  of  the   long-­lived  asset  exceeds  its  estimated  fair  value.  FirstEnergy  utilizes  the  income  approach,  based  upon  discounted  cash  flows  to   estimate  fair  value.     On  October  9,  2013,  MP  sold  its  approximate  8%  share  of  Pleasants  at  its  fair  market  value  of  $73  million  to  AE  Supply,  and  AE   Supply  sold  its  approximate  80%  share  of  Harrison  to  MP  at  its  book  value  of  $1.2  billion.  The  transaction  resulted  in  AE  Supply   receiving  net  consideration  of  $1.1  billion  and  MP's  assumption  of  a  $73.5  million   pollution  control  note.  In  connection  with  the   transaction,  MP  recorded  a  pre-­tax  impairment  charge  of  approximately  $322  million  to  reduce  the  net  book  value  of  the  Harrison   Power  Station  to  the  amount  that  was  permitted  to  be  included  in  jurisdictional  rate  base.  Additionally,  MP  recognized  a  regulatory   liability  of  approximately  $23  million  in  2013  representing  refunds  to  customers  associated  with  the  excess  purchase  price  received  by   MP  above  the  net  book  value  of  MP's  minority  interest  in  the  Pleasants  Power  Station.  The  impairment  charge  recognized  in  2013  is   included  within  the  results  of  the  Regulated  Distribution  segment.   On  July  8,  2013,  officers  of  FirstEnergy  and  AE  Supply  committed  to  deactivating  the  Hatfield's  Ferry,  generating  Units  1-­3,  and   Mitchell,  generating  units  2-­3.  As  a  result  of  this  decision  FirstEnergy  recorded  a  pre-­tax  impairment  of  approximately  $473  million  to   continuing  operations,  which  also  includes  pre-­tax  impairments  of  $13  million  related  to  excessive  inventory  at  these  facilities.  The   impairment  charge  recognized  in  2013  is  included  within  the  results  of  the  CES  segment.  On  October  9,  2013,  Hatfield's  Ferry  Units   1-­3  and  Mitchell  Units  2-­3  were  deactivated.     During  2015,  FirstEnergy  recognized  impairments  totaling  $42  million  associated  with  certain  non-­core  assets,  including  equipment   and  facilities.  The  impairment  charges  are  included  within  the  Regulated  Distribution  segment  ($8  million)  and  the  CES  segment  ($34   million).   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.   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:   Goodwill   Balance  as  of  December  31,  2015   Regulated   Distribution   (In  millions)   5,092   $   $   Regulated   Transmission   Competitive   Energy   Services   Consolidated   526   $   800   $   6,418   There  were  no  changes  in  goodwill  for  any  reporting  unit  during  2015.  As  of  December  31,  2015  and  2014,  total  goodwill  recognized   by  FES  was  $23  million.  Neither  FirstEnergy  nor  FES  has  accumulated  impairment  charges  as  of  December  31,  2015.   Annual  impairment  testing  is  conducted  as  of  July  31  of  each  year  and  for  2015,  2014  and  2013,  the  analysis  indicated  no  impairment   of  goodwill.  For  2015,  FirstEnergy  performed  a  qualitative  assessment  of  the  Regulated  Distribution  and  Regulated  Transmission   reporting   units,   assessing   economic,   industry   and   market   considerations   in   addition   to   the   reporting   unit's   overall   financial   performance.  It  was  determined  that  the  fair  value  of  these  reporting  units  were,  more  likely  than  not,  greater  than  their  carrying  value   and  a  quantitative  analysis  was  not  necessary  for  2015.   FirstEnergy  performed  a  quantitative  assessment  of  the  CES  reporting  unit  as  of  July  31,  2015.    Key  assumptions  incorporated  into   the  CES  discounted  cash  flow  analysis  requiring  significant  management  judgment  included  the  following:   •     Future  Energy  and  Capacity  Prices:  FirstEnergy  used  observable  market  information  for  near  term  forward  power  prices,   PJM  auction  results  for  near  term  capacity  pricing,  and  a  longer-­term  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:  FirstEnergy  used  CES'  current  retail  targeted  portfolio  to  estimate  future  retail  sales  volume  as   well  as  historical  financial  results  to  estimate  retail  margins.   72   73                                                 In  April  2015,  the  FASB  issued,  ASU  2015-­03  "Simplifying  the  Presentation  of  Debt  Issuance  Costs",  which  requires  debt  issuance   costs  to  be  presented  on  the  balance  sheet  as  a  direct  deduction  from  the  carrying  value  of  the  associated  debt  liability,  consistent   with  the  presentation  of  a  debt  discount.  The  guidance  is  effective  for  financial  statements  issued  for  fiscal  years  beginning  after   December  15,  2015,  and  interim  periods  within  those  fiscal  years.  Early  adoption  is  permitted  for  financial  statements  that  have  not   financial  statements.  In  addition,  in  August  2015,  the  FASB  issued  ASU  2015-­15,  "Presentation  and  Subsequent  Measurement  of   Debt  Issuance  Costs  Associated  with  Line-­of-­Credit  Arrangements",  which  states  given  the  absence  of  authoritative  guidance  within   ASU  2015-­03  for  debt  issuance  costs  related  to  the  line-­of-­credit  arrangements,  the  SEC  staff  would  not  object  to  presenting  those   deferred  debt  issuance  costs  as  an  asset  and  subsequently  amortizing  the  costs  ratably  over  the  term  of  the  arrangement,  regardless   of   whether   there   are   any   outstanding   borrowings   on   the   line-­of-­credit.   FirstEnergy   will   adopt  ASU   2015-­15   and  ASU   2015-­03   beginning  January  1,  2016.  As  of  December  31,  2015,  FirstEnergy  and  FES  debt  issuance  costs  included  in  Deferred  Charges  and   Other  Assets  were  $93  million  and  $17  million,  respectively.  FirstEnergy  will  elect  to  continue  presenting  debt  issuance  costs  relating   to  its  revolving  credit  facilities  as  an  asset.       In  August  2015,  the  FASB  issued  ASU  2015  -­13,  "Application  of  the  NPNS  Scope  Exception  to  Certain  Electricity  Contracts  within   Nodal  Energy  Markets",  which  confirmed  that  forward  physical  contracts  for  the  sale  or  purchase  of  electricity  meet  the  physical   delivery  criterion  within  the  NPNS  scope  exception  when  the  electricity  is  transmitted  through  a  grid  managed  by  an  ISO.  As  a  result,   an  entity  can  elect  the  NPNS  exception  within  the  derivative  accounting  guidance  for  such  contracts,  provided  that  the  other  NPNS   criteria  are  also  met.  The  ASU  was  effective  on  issuance  and  requires  prospective  application.  There  was  no  material  effect  on   FirstEnergy's  financial  statements  resulting  from  the  issuance  of  ASU  2015-­13.     In  November  2015,  the  FASB  issued  ASU  2015  -­  17,  "Balance  Sheet  Classification  of  Deferred  Taxes",  which  requires  all  deferred  tax   assets  and  liabilities,  along  with  any  related  valuation  allowance,  be  classified  as  noncurrent  on  the  balance  sheet.  The  new  guidance   will  be  effective  for  fiscal  years  beginning  after  December  15,  2016,  and  interim  periods  within  those  fiscal  years.  Early  adoption  is   permitted   for   all   entities   as   of   the   beginning   of   an   interim   or   annual   reporting   period.     The   guidance   may   be   applied   either   prospectively,  for  all  deferred  tax  assets  and  liabilities,  or  retrospectively.  FirstEnergy  early  adopted  ASU  2015-­17  as  of  December   2015,  and  applied  the  new  guidance  retrospectively  to  all  prior  periods  presented  in  the  financial  statements.  There  was  no  impact   from  the  early  adoption  of  ASU  2015-­17  on  the  Consolidated  Statements  of  Income.  On  the  Consolidated  Balance  Sheet  as  of   December  31,  2014,  FirstEnergy  and  FES  reclassified  $518  million  and  $27  million of  Accumulated  Deferred  Income  Taxes  from   Current  Assets  to  Noncurrent  Liabilities.     In  January  of  2016,  the  FASB  issued  ASU  2016-­01,  "Financial  Instruments-­Overall:  Recognition  and  Measurement  of  Financial   Assets  and  Financial  Liabilities".  Changes  to  the  current  GAAP  model  primarily  affect  the  accounting  for  equity  investments,  financial   liabilities  under  the  fair  value  option,  and  the  presentation  and  disclosure  requirements  for  financial  instruments.  In  addition,  the  FASB   clarified  guidance  related  to  the  valuation  allowance  assessment  when  recognizing  deferred  tax  assets  resulting  from  unrealized   losses  on  available-­for-­sale  debt  securities.  The  ASU  will  be  effective  in  fiscal  years  beginning  after  December  15,  2017,  including   interim  periods  within  those  fiscal  years.  Early  adoption  can  be  elected  for  all  financial  statements  of  fiscal  years  and  interim  periods   that  have  not  yet  been  issued  or  that  have  not  yet  been  made  available  for  issuance.  FirstEnergy  is  currently  evaluating  the  impact  on   its  financial  statements  of  adopting  this  standard.     •     Operating  and  Capital  Costs:  FirstEnergy  used  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  8.25%,  based  on  a  capital  structure,  return  on  debt  and  return  on  equity  of  selected   comparable  companies.     •     Terminal   Value:   A   terminal   value   of   7.0x   earnings   before   interest,   taxes,   depreciation   and   amortization   based   on   been  previously  issued.  Upon  adoption,  an  entity  must  apply  the  new  guidance  retrospectively  to  all  prior  periods  presented  in  the   consideration  of  peer  group  data  and  analyst  consensus  expectations.   Based  on  the  results  of  the  quantitative  analysis,  the  fair  value  of  the  CES  reporting  unit  exceeded  its  carrying  value  by  approximately   10%.  Continued  weak  economic  conditions,  lower  than  expected  power  and  capacity  prices,  a  higher  cost  of  capital  and  revised   environmental  requirements  could  have  a  negative  impact  on  future  goodwill  assessments.     Investments   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  first  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  in  net  regulatory  assets.  In  2015,  2014  and  2013,  FirstEnergy  recognized  $102  million,  $37  million  and  $90  million,   respectively,  of  OTTI.  During  the  same  periods,  FES  recognized  OTTI  of  $90  million,  $33  million  and  $79  million,  respectively.  The  fair   values  of  FirstEnergy’s  investments  are  disclosed  in  Note  9,  Fair  Value  Measurements.   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  current  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  an  a  pre-­tax  impairment  charge  of  $362  million.  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.  See  Note  8,  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.   NEW  ACCOUNTING  PRONOUNCEMENTS   In  May  2014,  the  FASB  issued,  ASU  2014-­09  "Revenue  from  Contracts  with  Customers",  requiring  entities  to  recognize  revenue  by   applying  a  five-­step  model  in  accordance  with  the  core  principle  to  depict  the  transfer  of  promised  goods  or  services  to  customers  in   an  amount  that  reflects  the  consideration  to  which  the  entity  expects  to  be  entitled  in  exchange  for  those  goods  or  services.  In   addition,  the  accounting  for  costs  to  obtain  or  fulfill  a  contract  with  a  customer  is  specified  and  disclosure  requirements  for  revenue   recognition  are  expanded.  In  August  2015,  the  FASB  issued  a  final  Accounting  Standards  Update  deferring  the  effective  date  until   fiscal  years  beginning  after  December  15,  2017.  Earlier  application  is  permitted  only  as  of  annual  reporting  periods  beginning  after   December  15,  2016,  (the  original  effective  date).  The  standard  shall  be  applied  retrospectively  to  each  period  presented  or  as  a   cumulative-­effect  adjustment  as  of  the  date  of  adoption.  FirstEnergy  is  currently  evaluating  the  impact  on  its  financial  statements  of   adopting  this  standard.     In  February  2015,  the  FASB  issued,  ASU  2015-­02  "Consolidations:  Amendments  to  the  Consolidation  Analysis",  which  amends   current  consolidation  guidance  including  changes  to  both  the  variable  and  voting  interest  models  used  by  companies  to  evaluate   whether  an  entity  should  be  consolidated. This  standard  is  effective  for  interim  and  annual  periods  beginning  after  December  15,   2015,  and  early  adoption  is  permitted. A  reporting  entity  must  apply  the  amendments  using  a  modified  retrospective  approach  by   recording   a   cumulative-­effect   adjustment   to   equity   as   of   the   beginning   of   the   period   of   adoption   or   apply   the   amendments   retrospectively.  FirstEnergy  does  not  expect  this  amendment  to  have  a  material  effect  on  its  financial  statements.     74   75                                     In  April  2015,  the  FASB  issued,  ASU  2015-­03  "Simplifying  the  Presentation  of  Debt  Issuance  Costs",  which  requires  debt  issuance   costs  to  be  presented  on  the  balance  sheet  as  a  direct  deduction  from  the  carrying  value  of  the  associated  debt  liability,  consistent   with  the  presentation  of  a  debt  discount.  The  guidance  is  effective  for  financial  statements  issued  for  fiscal  years  beginning  after   December  15,  2015,  and  interim  periods  within  those  fiscal  years.  Early  adoption  is  permitted  for  financial  statements  that  have  not   been  previously  issued.  Upon  adoption,  an  entity  must  apply  the  new  guidance  retrospectively  to  all  prior  periods  presented  in  the   financial  statements.  In  addition,  in  August  2015,  the  FASB  issued  ASU  2015-­15,  "Presentation  and  Subsequent  Measurement  of   Debt  Issuance  Costs  Associated  with  Line-­of-­Credit  Arrangements",  which  states  given  the  absence  of  authoritative  guidance  within   ASU  2015-­03  for  debt  issuance  costs  related  to  the  line-­of-­credit  arrangements,  the  SEC  staff  would  not  object  to  presenting  those   deferred  debt  issuance  costs  as  an  asset  and  subsequently  amortizing  the  costs  ratably  over  the  term  of  the  arrangement,  regardless   of   whether   there   are   any   outstanding   borrowings   on   the   line-­of-­credit.   FirstEnergy   will   adopt  ASU   2015-­15   and  ASU   2015-­03   beginning  January  1,  2016.  As  of  December  31,  2015,  FirstEnergy  and  FES  debt  issuance  costs  included  in  Deferred  Charges  and   Other  Assets  were  $93  million  and  $17  million,  respectively.  FirstEnergy  will  elect  to  continue  presenting  debt  issuance  costs  relating   to  its  revolving  credit  facilities  as  an  asset.       In  August  2015,  the  FASB  issued  ASU  2015  -­13,  "Application  of  the  NPNS  Scope  Exception  to  Certain  Electricity  Contracts  within   Nodal  Energy  Markets",  which  confirmed  that  forward  physical  contracts  for  the  sale  or  purchase  of  electricity  meet  the  physical   delivery  criterion  within  the  NPNS  scope  exception  when  the  electricity  is  transmitted  through  a  grid  managed  by  an  ISO.  As  a  result,   an  entity  can  elect  the  NPNS  exception  within  the  derivative  accounting  guidance  for  such  contracts,  provided  that  the  other  NPNS   criteria  are  also  met.  The  ASU  was  effective  on  issuance  and  requires  prospective  application.  There  was  no  material  effect  on   FirstEnergy's  financial  statements  resulting  from  the  issuance  of  ASU  2015-­13.     In  November  2015,  the  FASB  issued  ASU  2015  -­  17,  "Balance  Sheet  Classification  of  Deferred  Taxes",  which  requires  all  deferred  tax   assets  and  liabilities,  along  with  any  related  valuation  allowance,  be  classified  as  noncurrent  on  the  balance  sheet.  The  new  guidance   will  be  effective  for  fiscal  years  beginning  after  December  15,  2016,  and  interim  periods  within  those  fiscal  years.  Early  adoption  is   permitted   for   all   entities   as   of   the   beginning   of   an   interim   or   annual   reporting   period.     The   guidance   may   be   applied   either   prospectively,  for  all  deferred  tax  assets  and  liabilities,  or  retrospectively.  FirstEnergy  early  adopted  ASU  2015-­17  as  of  December   2015,  and  applied  the  new  guidance  retrospectively  to  all  prior  periods  presented  in  the  financial  statements.  There  was  no  impact   from  the  early  adoption  of  ASU  2015-­17  on  the  Consolidated  Statements  of  Income.  On  the  Consolidated  Balance  Sheet  as  of   December  31,  2014,  FirstEnergy  and  FES  reclassified  $518  million  and  $27  million of  Accumulated  Deferred  Income  Taxes  from   Current  Assets  to  Noncurrent  Liabilities.     In  January  of  2016,  the  FASB  issued  ASU  2016-­01,  "Financial  Instruments-­Overall:  Recognition  and  Measurement  of  Financial   Assets  and  Financial  Liabilities".  Changes  to  the  current  GAAP  model  primarily  affect  the  accounting  for  equity  investments,  financial   liabilities  under  the  fair  value  option,  and  the  presentation  and  disclosure  requirements  for  financial  instruments.  In  addition,  the  FASB   clarified  guidance  related  to  the  valuation  allowance  assessment  when  recognizing  deferred  tax  assets  resulting  from  unrealized   losses  on  available-­for-­sale  debt  securities.  The  ASU  will  be  effective  in  fiscal  years  beginning  after  December  15,  2017,  including   interim  periods  within  those  fiscal  years.  Early  adoption  can  be  elected  for  all  financial  statements  of  fiscal  years  and  interim  periods   that  have  not  yet  been  issued  or  that  have  not  yet  been  made  available  for  issuance.  FirstEnergy  is  currently  evaluating  the  impact  on   its  financial  statements  of  adopting  this  standard.     •     Operating  and  Capital  Costs:  FirstEnergy  used  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   •     Discount  Rate:  A  discount  rate  of  8.25%,  based  on  a  capital  structure,  return  on  debt  and  return  on  equity  of  selected   performance  reforms  in  the  PJM  market.   comparable  companies.     •     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  results  of  the  quantitative  analysis,  the  fair  value  of  the  CES  reporting  unit  exceeded  its  carrying  value  by  approximately   10%.  Continued  weak  economic  conditions,  lower  than  expected  power  and  capacity  prices,  a  higher  cost  of  capital  and  revised   environmental  requirements  could  have  a  negative  impact  on  future  goodwill  assessments.     Investments   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  first  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  in  net  regulatory  assets.  In  2015,  2014  and  2013,  FirstEnergy  recognized  $102  million,  $37  million  and  $90  million,   respectively,  of  OTTI.  During  the  same  periods,  FES  recognized  OTTI  of  $90  million,  $33  million  and  $79  million,  respectively.  The  fair   values  of  FirstEnergy’s  investments  are  disclosed  in  Note  9,  Fair  Value  Measurements.   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  current  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  an  a  pre-­tax  impairment  charge  of  $362  million.  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.  See  Note  8,  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.   NEW  ACCOUNTING  PRONOUNCEMENTS   In  May  2014,  the  FASB  issued,  ASU  2014-­09  "Revenue  from  Contracts  with  Customers",  requiring  entities  to  recognize  revenue  by   applying  a  five-­step  model  in  accordance  with  the  core  principle  to  depict  the  transfer  of  promised  goods  or  services  to  customers  in   an  amount  that  reflects  the  consideration  to  which  the  entity  expects  to  be  entitled  in  exchange  for  those  goods  or  services.  In   addition,  the  accounting  for  costs  to  obtain  or  fulfill  a  contract  with  a  customer  is  specified  and  disclosure  requirements  for  revenue   recognition  are  expanded.  In  August  2015,  the  FASB  issued  a  final  Accounting  Standards  Update  deferring  the  effective  date  until   fiscal  years  beginning  after  December  15,  2017.  Earlier  application  is  permitted  only  as  of  annual  reporting  periods  beginning  after   December  15,  2016,  (the  original  effective  date).  The  standard  shall  be  applied  retrospectively  to  each  period  presented  or  as  a   cumulative-­effect  adjustment  as  of  the  date  of  adoption.  FirstEnergy  is  currently  evaluating  the  impact  on  its  financial  statements  of   adopting  this  standard.     In  February  2015,  the  FASB  issued,  ASU  2015-­02  "Consolidations:  Amendments  to  the  Consolidation  Analysis",  which  amends   current  consolidation  guidance  including  changes  to  both  the  variable  and  voting  interest  models  used  by  companies  to  evaluate   whether  an  entity  should  be  consolidated. This  standard  is  effective  for  interim  and  annual  periods  beginning  after  December  15,   2015,  and  early  adoption  is  permitted. A  reporting  entity  must  apply  the  amendments  using  a  modified  retrospective  approach  by   recording   a   cumulative-­effect   adjustment   to   equity   as   of   the   beginning   of   the   period   of   adoption   or   apply   the   amendments   retrospectively.  FirstEnergy  does  not  expect  this  amendment  to  have  a  material  effect  on  its  financial  statements.     74   75                                     2.  ACCUMULATED  OTHER  COMPREHENSIVE  INCOME   The  following  amounts  were  reclassified  from  AOCI  for  FirstEnergy  in  the  years  ended  December  31,  2015,  2014  and  2013:     The  changes  in  AOCI  for  the  years  ended  December  31,  2015,  2014  and  2013  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   AOCI  Balance,  January  1,  2013   $   (38  )   $   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   —   3   3   1   2   (In  millions)   15   $   46   (56  )   (10  )   (4  )   (6  )   408   $   35   (195  )   (160  )   (63  )   (97  )   AOCI  Balance,  December  31,  2013   $   (36  )   $   9   $   311   $   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  )   89   (63  )   26   10   16   92   (168  )   (76  )   (23  )   (53  )   AOCI  Balance,  December  31,  2014   $   (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   $   385   81   (248  )   (167  )   (66  )   (101  )   284   181   (233  )   (52  )   (14  )   (38  )   246   24   (146  )   (122  )   (47  )   (75  )   171   FirstEnergy   Reclassifications  from  AOCI  (2)   2015   2014   2013   Statements  of  Income   Year  Ended  December  31,   Affected  Line  Item  in  Consolidated   Gains  &  losses  on  cash  flow  hedges   Commodity  contracts   Long-­term  debt   (In  millions)   $   (3  )   $   (10  )   $   (8  )   Other  operating  expenses   8   5   (1  )   8   (2  )   1   11   Interest  expense   3   Total  before  taxes   (1  )   Income  taxes  (benefits)   $   4   $   (1  )   $   2   Net  of  tax   Unrealized  gains  on  AFS  securities   Realized  gains  on  sales  of  securities   $   (25  )   $   (63  )   $   (56  )   Investment  income  (loss)   9   24   21   Income  taxes  (benefits)   $   (16  )   $   (39  )   $   (35  )   Net  of  tax   Defined  benefit  pension  and  OPEB  plans   Prior-­service  costs   $   (126  )   $   (168  )   $   (195  )   (1)   49   65   75   Income  taxes  (benefits)   $   (77  )   $   (103  )   $   (120  )   Net  of  tax   (1)  These  AOCI  components  are  included  in  the  computation  of  net  periodic  pension  cost.  See  Note  3,  Pension  and  Other   Postemployment  Benefits  for  additional  details.   (2)  Parenthesis  represent  credits  to  the  Consolidated  Statements  of  Income  from  AOCI.   76   77               The  changes  in  AOCI  for  the  years  ended  December  31,  2015,  2014  and  2013  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   AOCI  Balance,  January  1,  2013   $   (38  )   $   (In  millions)   15   $   AOCI  Balance,  December  31,  2013   $   (36  )   $   9   $   311   $   Other  comprehensive  income  before  reclassifications   Amounts  reclassified  from  AOCI   Other  comprehensive  income  (loss)   Income  tax  (benefits)  on  other  comprehensive  income  (loss)   Other  comprehensive  income  (loss),  net  of  tax   Other  comprehensive  income  before  reclassifications   Amounts  reclassified  from  AOCI   Other  comprehensive  income  (loss)   Income  tax  (benefits)  on  other  comprehensive  income  (loss)   Other  comprehensive  income  (loss),  net  of  tax   Other  comprehensive  income  before  reclassifications   Amounts  reclassified  from  AOCI   Other  comprehensive  income  (loss)   Income  tax  (benefits)  on  other  comprehensive  income  (loss)   Other  comprehensive  income  (loss),  net  of  tax   —   3   3   1   2   —   (2  )   (2  )   (1  )   (1  )   —   5   5   1   4   46   (56  )   (10  )   (4  )   (6  )   89   (63  )   26   10   16   14   (25  )   (11  )   (4  )   (7  )   AOCI  Balance,  December  31,  2015   $   (33  )   $   18   $   186   $   408   $   35   (195  )   (160  )   (63  )   (97  )   92   (168  )   (76  )   (23  )   (53  )   10   (126  )   (116  )   (44  )   (72  )   385   81   (248  )   (167  )   (66  )   (101  )   284   181   (233  )   (52  )   (14  )   (38  )   246   24   (146  )   (122  )   (47  )   (75  )   171   2.  ACCUMULATED  OTHER  COMPREHENSIVE  INCOME   The  following  amounts  were  reclassified  from  AOCI  for  FirstEnergy  in  the  years  ended  December  31,  2015,  2014  and  2013:     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,   2013   2014   2015   Affected  Line  Item  in  Consolidated   Statements  of  Income   (In  millions)   (3  )   $   8   5   (1  )   4   $   (10  )   $   8   (2  )   1   (1  )   $   (8  )   Other  operating  expenses   11   Interest  expense   3   Total  before  taxes   (1  )   Income  taxes  (benefits)   2   Net  of  tax   (25  )   $   9   (16  )   $   (63  )   $   24   (39  )   $   (56  )   Investment  income  (loss)   21   Income  taxes  (benefits)   (35  )   Net  of  tax   (126  )   $   49   (77  )   $   (168  )   $   65   (103  )   $   (195  )   (1)   75   Income  taxes  (benefits)   (120  )   Net  of  tax   $   $   $   $   $   $   AOCI  Balance,  December  31,  2014   $   (37  )   $   25   $   258   $   (1)  These  AOCI  components  are  included  in  the  computation  of  net  periodic  pension  cost.  See  Note  3,  Pension  and  Other   Postemployment  Benefits  for  additional  details.   (2)  Parenthesis  represent  credits  to  the  Consolidated  Statements  of  Income  from  AOCI.   76   77               The  changes  in  AOCI  for  the  years  ended  December  31,  2015,  2014  and  2013  for  FES  are  shown  in  the  following  table:     The  following  amounts  were  reclassified  from  AOCI  for  FES  in  the  years  ended  December  31,  2015,  2014  and  2013:     FES   Gains  &   Losses  on   Cash  Flow   Hedges   Unrealized   Gains  on   AFS   Securities   Defined   Benefit   Pension  &   OPEB  Plans   Total   (In  millions)   AOCI  Balance,  January  1,  2013   $   3   $   13   $   56   $   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   —   (6  )   (6  )   (2  )   (4  )   41   (49  )   (8  )   (3  )   (5  )   5   (20  )   (15  )   (6  )   (9  )   AOCI  Balance,  December  31,  2013   $   (1  )   $   8   $   47   $   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  )   80   (59  )   21   8   13   13   (19  )   (6  )   (2  )   (4  )   AOCI  Balance,  December  31,  2014   $   (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   $   72   46   (75  )   (29  )   (11  )   (18  )   54   93   (88  )   5   2   3   57   25   (43  )   (18  )   (7  )   (11  )   46   FES   Reclassifications  from  AOCI  (2)   2015   2014   2013   Statements  of  Income   Year  Ended  December  31,   Affected  Line  Item  in  Consolidated   Gains  &  losses  on  cash  flow  hedges   Commodity  contracts   Long-­term  debt   (In  millions)   $   (3  )   $   (10  )   $   (8  )   Other  operating  expenses   —   (3  )   1   —   (10  )   4   2   Interest  expense  -­  other   (6  )   Total  before  taxes   2   Income  taxes  (benefits)   $   (2  )   $   (6  )   $   (4  )   Net  of  tax   Unrealized  gains  on  AFS  securities   Realized  gains  on  sales  of  securities   $   (24  )   $   (59  )   $   (49  )   Investment  income  (loss)   9   22   18   Income  taxes  (benefits)   $   (15  )   $   (37  )   $   (31  )   Net  of  tax   Defined  benefit  pension  and  OPEB  plans   Prior-­service  costs   $   (16  )   $   (19  )   $   (20  )   (1)   6   7   8   Income  taxes  (benefits)   $   (10  )   $   (12  )   $   (12  )   Net  of  tax   (1)  These  AOCI  components  are  included  in  the  computation  of  net  periodic  pension  cost.  See  Note  3,  Pension  and  Other  Postemployment   Benefits  for  additional  details.   (2)  Parenthesis  represent  credits  to  the  Consolidated  Statements  of  Income  from  AOCI.   3.  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.  In  2014,  the   qualified  pension  plan  was  amended  authorizing  a  voluntary  cashout  window  program  for  certain  eligible  terminated  participants  with   vested  benefits.  Payment  of  benefits  for  participants  that  elected  an  immediate  lump  sum  cash  payment  or  an  annuity  resulted  in  a   $40  million  reduction  to  the  underfunded  status  of  the  pension  plan.  Additionally,  during  2015  and  2014,  certain  unions  ratified  their   labor  agreements  that  ended  subsidized  retiree  health  care  resulting  in  a  reduction  to  the  OPEB  benefit  obligation  by  approximately   $10  million  and  $97  million,  respectively.     FirstEnergy  recognizes  as  a  pension  and  OPEB  mark-­to-­market  adjustment  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,  2015,  2014,  and  2013  were  $369  million  ($242  million  net  of  amounts  capitalized),  $1,243  million  ($835   million  net  of  amounts  capitalized),  and  $(396)  million  ($(256)  million  net  of  amounts  capitalized),  respectively.  In  2015,  the  pension   and  OPEB  mark-­to-­market  adjustment  primarily  reflects  lower  than  expected  asset  returns  as  well  as  the  impact  of  other  demographic   assumptions,  including  revisions  to  mortality  assumptions,  partially  offset  by  a  25  basis  point  increase  in  the  discount  rate.   FirstEnergy’s  pension  and  OPEB  funding  policy  is  based  on  actuarial  computations  using  the  projected  unit  credit  method.  During  the   year  ended  December  31,  2015,  FirstEnergy  made  contributions  of  $143  million  to  its  qualified  pension  plan.  In  2016,  FirstEnergy  has   minimum  required  funding  obligations  of $381  million  to  its  qualified  pension  plan,  of  which  $160  million  has  been  contributed  to  date.   FirstEnergy  expects  to  make  future  contributions  to  the  qualified  pension  plan  in  2016  with  cash,  equity  or  a  combination  thereof,   depending  on,  among  other  things,  market  conditions.     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   78   79           The  changes  in  AOCI  for  the  years  ended  December  31,  2015,  2014  and  2013  for  FES  are  shown  in  the  following  table:     The  following  amounts  were  reclassified  from  AOCI  for  FES  in  the  years  ended  December  31,  2015,  2014  and  2013:     FES   Gains  &   Losses  on   Cash  Flow   Hedges   Unrealized   Gains  on   AFS   Securities   Defined   Benefit   Pension  &   OPEB  Plans   Total   (In  millions)   AOCI  Balance,  January  1,  2013   $   3   $   13   $   56   $   AOCI  Balance,  December  31,  2013   $   (1  )   $   8   $   47   $   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   Other  comprehensive  income  before  reclassifications   Amounts  reclassified  from  AOCI   Other  comprehensive  income  (loss)   Income  tax  (benefits)  on  other  comprehensive  income  (loss)   Other  comprehensive  income  (loss),  net  of  tax   Other  comprehensive  income  before  reclassifications   Amounts  reclassified  from  AOCI   Other  comprehensive  loss   Income  tax  benefits  on  other  comprehensive  loss   Other  comprehensive  loss,  net  of  tax   —   (6  )   (6  )   (2  )   (4  )   —   (10  )   (10  )   (4  )   (6  )   —   (3  )   (3  )   (1  )   (2  )   41   (49  )   (8  )   (3  )   (5  )   80   (59  )   21   8   13   15   (24  )   (9  )   (4  )   (5  )   5   (20  )   (15  )   (6  )   (9  )   13   (19  )   (6  )   (2  )   (4  )   10   (16  )   (6  )   (2  )   (4  )   AOCI  Balance,  December  31,  2014   $   (7  )   $   21   $   43   $   AOCI  Balance,  December  31,  2015   $   (9  )   $   16   $   39   $   72   46   (75  )   (29  )   (11  )   (18  )   54   93   (88  )   5   2   3   57   25   (43  )   (18  )   (7  )   (11  )   46   FES   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,   2013   2015   2014   (In  millions)   Affected  Line  Item  in  Consolidated   Statements  of  Income   $   $   $   $   $   $   (3  )   $   —   (3  )   1   (2  )   $   (10  )   $   —   (10  )   4   (6  )   $   (8  )   Other  operating  expenses   2   Interest  expense  -­  other   (6  )   Total  before  taxes   2   Income  taxes  (benefits)   (4  )   Net  of  tax   (24  )   $   9   (15  )   $   (59  )   $   22   (37  )   $   (49  )   Investment  income  (loss)   18   Income  taxes  (benefits)   (31  )   Net  of  tax   (16  )   $   6   (10  )   $   (19  )   $   7   (12  )   $   (20  )   (1)   8   Income  taxes  (benefits)   (12  )   Net  of  tax   (1)  These  AOCI  components  are  included  in  the  computation  of  net  periodic  pension  cost.  See  Note  3,  Pension  and  Other  Postemployment   Benefits  for  additional  details.   (2)  Parenthesis  represent  credits  to  the  Consolidated  Statements  of  Income  from  AOCI.   3.  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.  In  2014,  the   qualified  pension  plan  was  amended  authorizing  a  voluntary  cashout  window  program  for  certain  eligible  terminated  participants  with   vested  benefits.  Payment  of  benefits  for  participants  that  elected  an  immediate  lump  sum  cash  payment  or  an  annuity  resulted  in  a   $40  million  reduction  to  the  underfunded  status  of  the  pension  plan.  Additionally,  during  2015  and  2014,  certain  unions  ratified  their   labor  agreements  that  ended  subsidized  retiree  health  care  resulting  in  a  reduction  to  the  OPEB  benefit  obligation  by  approximately   $10  million  and  $97  million,  respectively.     FirstEnergy  recognizes  as  a  pension  and  OPEB  mark-­to-­market  adjustment  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,  2015,  2014,  and  2013  were  $369  million  ($242  million  net  of  amounts  capitalized),  $1,243  million  ($835   million  net  of  amounts  capitalized),  and  $(396)  million  ($(256)  million  net  of  amounts  capitalized),  respectively.  In  2015,  the  pension   and  OPEB  mark-­to-­market  adjustment  primarily  reflects  lower  than  expected  asset  returns  as  well  as  the  impact  of  other  demographic   assumptions,  including  revisions  to  mortality  assumptions,  partially  offset  by  a  25  basis  point  increase  in  the  discount  rate.   FirstEnergy’s  pension  and  OPEB  funding  policy  is  based  on  actuarial  computations  using  the  projected  unit  credit  method.  During  the   year  ended  December  31,  2015,  FirstEnergy  made  contributions  of  $143  million  to  its  qualified  pension  plan.  In  2016,  FirstEnergy  has   minimum  required  funding  obligations  of $381  million  to  its  qualified  pension  plan,  of  which  $160  million  has  been  contributed  to  date.   FirstEnergy  expects  to  make  future  contributions  to  the  qualified  pension  plan  in  2016  with  cash,  equity  or  a  combination  thereof,   depending  on,  among  other  things,  market  conditions.     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   78   79           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  2015,  FirstEnergy’s  qualified  pension  and  OPEB  plan  assets  experienced  losses  of   $(172)  million,  or  (2.7)%  compared  to  earnings  of  $387  million,  or  6.2%  in  2014  and  losses  of  $(22)  million,  or  (0.3)%  in  2013,  and   assumed  a  7.75%  rate  of  return  for  each  year  on  plan  assets  which  generated  $476  million,  $496  million  and  $535  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  2014,  the  Society  of  Actuaries  published  new  mortality  tables  and  improvement  scales  reflecting  improved  life  expectancies   and  an  expectation  that  the  trend  will  continue.  An  analysis  of  FirstEnergy  pension  and  OPEB  plan  mortality  data  indicated  the  use  of   the  RP2014  mortality  table  with  blue  collar  adjustment  for  females  and  projection  scale  SS2014INT  was  most  appropriate  as  of   December  31,  2015.  As  such,  the  RP2014  mortality  table  with  projection  scale  SS2014INT  was  utilized  to  determine  the  2015  benefit   cost  and  obligation  as  of  December  31,  2015  for  the  FirstEnergy  pension  and  OPEB  plans.  The  impact  of  using  the  RP2014  mortality   table  and  projection  scale  SS2014INT  resulted  in  an  increase  in  the  projected  benefit  obligation  of  $49  million  and  $1  million  for  the   pension  and  OPEB  plans,  respectively,  and  was  included  in  the  2015  pension  and  OPEB  mark-­to-­market  adjustment.     80   Obligations  and  Funded  Status   2015   2014   2015   2014   Pension   OPEB   (In  millions)   $   9,249   $   8,263   $   757   $   Change  in  benefit  obligation:   Benefit  obligation  as  of  January  1   Service  cost   Interest  cost   Plan  participants’  contributions   Plan  amendments   Medicare  retiree  drug  subsidy   Actuarial  (gain)  loss   Benefits  paid   Benefit  obligation  as  of  December  31   Change  in  fair  value  of  plan  assets:   Fair  value  of  plan  assets  as  of  January  1   Actual  return  (losses)  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:   Current  liabilities   Noncurrent  liabilities   Net  liability  as  of  December  31   Amounts  Recognized  in  AOCI:   Prior  service  cost  (credit)   (as  of  December  31)   Discount  rate   Rate  of  compensation  increase   Assumptions  Used  to  Determine  Benefit  Obligations   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   Derivatives   Total   Cash  and  short-­term  securities   $   $   $   $   $   $   $   $   $   81   193   383   —   —   —   (277  )   (469  )   9,079   $   5,824   $   (178  )   161   —   (469  )   5,338   $   167   402   —   5   —   1,123   (711  )   9,249   $   6,171   349   $   15   —   (711  )   5,824   $   (3,366  )   $   (375  )   (3,741  )   $   (3,064  )   (361  )   (3,425  )   $   8,579   $   8,744   $   (18  )   $   (3,723  )   (3,741  )   $   (17  )   $   (3,408  )   (3,425  )   $   5   29   6   (10  )   1   (2  )   (62  )   724   $   464   $   6   17   6   (62  )   431   $   (293  )   $   —   $   —   $   (293  )   (293  )   $   879   9   39   16   (97  )   —   13   (102  )   757   495   38   17   16   (102  )   464   (293  )   —   —   (293  )   (293  )   37   $   45   $   (355  )   $   (479  )   4.50  %   4.20  %   4.25  %   4.20  %   4.25  %   N/A   4.00  %   N/A   N/A   N/A   N/A   40  %   34  %   7  %   11  %   —  %   8  %   100  %   N/A   N/A   N/A   36  %   33  %   14  %   7  %   1  %   9  %   100  %   6.0-­5.5%   7.5-­7.0%   4.5  %   2026   51  %   43  %   —  %   —  %   —  %   6  %   100  %   4.5  %   2026   49  %   40  %   1  %   1  %   —  %   9  %   100  %   The  estimated  2016  amortization  of  pension  and  OPEB  prior  service  costs  (credits)  from  AOCI  into  net  periodic  pension  and   OPEB  costs  (credits)  is  approximately  $8  million  and  $(80)  million,  respectively.                       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  2015,  FirstEnergy’s  qualified  pension  and  OPEB  plan  assets  experienced  losses  of   $(172)  million,  or  (2.7)%  compared  to  earnings  of  $387  million,  or  6.2%  in  2014  and  losses  of  $(22)  million,  or  (0.3)%  in  2013,  and   assumed  a  7.75%  rate  of  return  for  each  year  on  plan  assets  which  generated  $476  million,  $496  million  and  $535  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  2014,  the  Society  of  Actuaries  published  new  mortality  tables  and  improvement  scales  reflecting  improved  life  expectancies   and  an  expectation  that  the  trend  will  continue.  An  analysis  of  FirstEnergy  pension  and  OPEB  plan  mortality  data  indicated  the  use  of   the  RP2014  mortality  table  with  blue  collar  adjustment  for  females  and  projection  scale  SS2014INT  was  most  appropriate  as  of   December  31,  2015.  As  such,  the  RP2014  mortality  table  with  projection  scale  SS2014INT  was  utilized  to  determine  the  2015  benefit   cost  and  obligation  as  of  December  31,  2015  for  the  FirstEnergy  pension  and  OPEB  plans.  The  impact  of  using  the  RP2014  mortality   table  and  projection  scale  SS2014INT  resulted  in  an  increase  in  the  projected  benefit  obligation  of  $49  million  and  $1  million  for  the   pension  and  OPEB  plans,  respectively,  and  was  included  in  the  2015  pension  and  OPEB  mark-­to-­market  adjustment.     Obligations  and  Funded  Status   2015   2014   2015   2014   Pension   OPEB   (In  millions)   $   9,249   $   8,263   $   757   $   $   $   $   $   $   $   $   $   $   Change  in  benefit  obligation:   Benefit  obligation  as  of  January  1   Service  cost   Interest  cost   Plan  participants’  contributions   Plan  amendments   Medicare  retiree  drug  subsidy   Actuarial  (gain)  loss   Benefits  paid   Benefit  obligation  as  of  December  31   Change  in  fair  value  of  plan  assets:   Fair  value  of  plan  assets  as  of  January  1   Actual  return  (losses)  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:   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   Derivatives   Cash  and  short-­term  securities   Total   193   383   —   —   —   167   402   —   5   —   (277  )   (469  )   9,079   $   1,123   (711  )   9,249   $   5   29   6   (10  )   1   (2  )   (62  )   724   $   $   5,824   (178  )   161   —   (469  )   5,338   $   $   6,171   349   15   —   (711  )   5,824   $   $   464   6   17   6   (62  )   431   $   (3,366  )   $   (375  )   (3,741  )   $   (3,064  )   (361  )   (3,425  )   $   8,579   $   8,744   $   (18  )   $   (3,723  )   (3,741  )   $   (17  )   $   (3,408  )   (3,425  )   $   (293  )   $   —   $   $   —   (293  )   (293  )   $   879   9   39   16   (97  )   —   13   (102  )   757   495   38   17   16   (102  )   464   (293  )   —   —   (293  )   (293  )   37   $   45   $   (355  )   $   (479  )   4.50  %   4.20  %   4.25  %   4.20  %   4.25  %   N/A   4.00  %   N/A   N/A   N/A   N/A   40  %   34  %   7  %   11  %   —  %   8  %   100  %   N/A   N/A   N/A   36  %   33  %   14  %   7  %   1  %   9  %   100  %   6.0-­5.5%   7.5-­7.0%   4.5  %   2026   51  %   43  %   —  %   —  %   —  %   6  %   100  %   4.5  %   2026   49  %   40  %   1  %   1  %   —  %   9  %   100  %   80   81   The  estimated  2016  amortization  of  pension  and  OPEB  prior  service  costs  (credits)  from  AOCI  into  net  periodic  pension  and   OPEB  costs  (credits)  is  approximately  $8  million  and  $(80)  million,  respectively.                       Components  of  Net  Periodic  Benefit  Costs   2015   2014   2013   2015   Pension   OPEB   2014   2013   Service  cost   Interest  cost   Expected  return  on  plan  assets   Amortization  of  prior  service  cost  (credit)   Pension  &  OPEB  mark-­to-­market  adjustment   Net  periodic  cost  (credit)   $   $   193   $   383   (443  )   8   344   485   $   167   $   402   (462  )   8   1,235   1,350   $   (In  millions)   197   $   372   (501  )   12   (267  )   (187  )   $   5   $   29   (33  )   (134  )   25   (108  )   $   9   $   39   (34  )   (176  )   8   (154  )   $   13   37   (34  )   (207  )   (129  )   (320  )   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   OPEB   2015   2014   2013   2015   2014   2013   4.25  %   7.75  %   4.20  %   5.00  %   7.75  %   4.20  %   4.25  %   7.75  %   4.70  %   4.00  %   7.75  %   N/A   4.75  %   7.75  %   N/A   4.00  %   7.75  %   N/A   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.  In  2016,  FirstEnergy  decreased   the  expected  long-­term  return  on  plan  assets  to  7.50%.   The  following  tables  set  forth  pension  financial  assets  that  are  accounted  for  at  fair  value  by  level  within  the  fair  value  hierarchy.  See   Note  9,  Fair  Value  Measurements,  for  a  description  of  each  level  of  the  fair  value  hierarchy.  There  were  no  significant  transfers   between  levels  during  2015  and  2014.   Cash  and  short-­term  securities   Equity  investments   Domestic   International   Fixed  income   Government  bonds   Corporate  bonds   High  yield  debt   Mortgage-­backed  securities  (non-­ government)   Alternatives   Hedge  funds  (Absolute  return)   Derivatives   Private  equity  funds   Real  estate  funds   Total  (1)   December  31,  2015   Level  1   Level  2   Level  3   Total   $   —   $   (In  millions)   427   $   —   $   427   869   395   —   —   —   —   —   —   —   —   1,264   $   $   75   794   232   1,115   438   31   343   15   —   —   3,470   $   —   —   —   —   —   —   —   —   24   587   611   $   944   1,189   232   1,115   438   31   343   15   24   587   5,345   Asset   Allocation   8  %   18  %   22  %   4  %   21  %   8  %   1  %   7  %   —  %   —  %   11  %   100  %   (1)   Excludes  $(7)  million  as  of  December  31,  2015  of  receivables,  payables,  taxes  and  accrued  income  associated  with  financial  instruments   reflected  within  the  fair  value  table.   December  31,  2014   Level  1   Level  2   Level  3   Total   $   —   $   —   $   517   (In  millions)   517   $   Asset   Allocation   1,266   355   —   —   —   —   —   —   —   —   8   414   159   1,386   300   37   809   35   —   —   $   1,621   $   3,665   $   —   —   —   —   —   —   —   —   25   421   446   $   1,274   769   159   1,386   300   37   809   35   25   421   5,732   9  %   22  %   14  %   3  %   24  %   5  %   1  %   14  %   1  %   —  %   7  %   100  %   Cash  and  short-­term  securities   Equity  investments   Domestic   International   Fixed  income   Government  bonds   Corporate  bonds   High  yield  debt   government)   Alternatives   Derivatives   Private  equity  funds   Real  estate  funds   Total  (1)   Mortgage-­backed  securities  (non-­ Hedge  funds  (Absolute  return)   reflected  within  the  fair  value  table.   hierarchy  during  2015  and  2014:   (1)   Excludes  $92  million  as  of  December  31,  2014  of  receivables,  payables,  taxes  and  accrued  income  associated  with  financial  instruments   The  following  table  provides  a  reconciliation  of  changes  in  the  fair  value  of  pension  investments  classified  as  Level  3  in  the  fair  value   Balance  as  of  January  1,  2014   Actual  return  on  plan  assets:   Unrealized  gains  (losses)   Realized  gains   Transfers  in  (out)   Balance  as  of  December  31,  2014   Actual  return  on  plan  assets:   Unrealized  gains   Realized  gains  (losses)   Transfers  in   Balance  as  of  December  31,  2015   $   $   $   Private  Equity   Real  Estate   Funds   Funds   (In  millions)   27   $   385   17   14   5   421   42   16   108   587   (2  )   1   (1  )   25   $   —   (1  )   —   24   $   82   83             Components  of  Net  Periodic  Benefit  Costs   2015   2014   2013   2015   2013   Pension   OPEB   2014   Service  cost   Interest  cost   Expected  return  on  plan  assets   Amortization  of  prior  service  cost  (credit)   Pension  &  OPEB  mark-­to-­market  adjustment   Net  periodic  cost  (credit)   $   193   $   167   $   197   $   5   $   9   $   (In  millions)   383   (443  )   8   344   402   (462  )   8   1,235   372   (501  )   12   (267  )   29   (33  )   (134  )   25   39   (34  )   (176  )   8   $   485   $   1,350   $   (187  )   $   (108  )   $   (154  )   $   13   37   (34  )   (207  )   (129  )   (320  )   Assumptions  Used  to  Determine  Net  Periodic   Pension   OPEB   Benefit  Cost   for  Years  Ended  December  31   Weighted-­average  discount  rate   Expected  long-­term  return  on  plan  assets   Rate  of  compensation  increase   2015   2014   2013   2015   2014   2013   4.25  %   7.75  %   4.20  %   5.00  %   7.75  %   4.20  %   4.25  %   7.75  %   4.70  %   4.00  %   7.75  %   N/A   4.75  %   7.75  %   N/A   4.00  %   7.75  %   N/A   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.  In  2016,  FirstEnergy  decreased   the  expected  long-­term  return  on  plan  assets  to  7.50%.   The  following  tables  set  forth  pension  financial  assets  that  are  accounted  for  at  fair  value  by  level  within  the  fair  value  hierarchy.  See   Note  9,  Fair  Value  Measurements,  for  a  description  of  each  level  of  the  fair  value  hierarchy.  There  were  no  significant  transfers   between  levels  during  2015  and  2014.   December  31,  2015   Level  1   Level  2   Level  3   Total   $   —   $   —   $   427   (In  millions)   427   $   Asset   Allocation   Cash  and  short-­term  securities   Equity  investments   Domestic   International   Fixed  income   Government  bonds   Corporate  bonds   High  yield  debt   government)   Alternatives   Derivatives   Private  equity  funds   Real  estate  funds   Total  (1)   Mortgage-­backed  securities  (non-­ Hedge  funds  (Absolute  return)   75   794   232   1,115   438   31   343   15   —   —   —   —   —   —   —   —   —   —   24   587   611   $   944   1,189   232   1,115   438   31   343   15   24   587   5,345   8  %   18  %   22  %   4  %   21  %   8  %   1  %   7  %   —  %   —  %   11  %   100  %   (1)   Excludes  $(7)  million  as  of  December  31,  2015  of  receivables,  payables,  taxes  and  accrued  income  associated  with  financial  instruments   reflected  within  the  fair  value  table.   $   1,264   $   3,470   $   869   395   —   —   —   —   —   —   —   —   82   Cash  and  short-­term  securities   Equity  investments   Domestic   International   Fixed  income   Government  bonds   Corporate  bonds   High  yield  debt   Mortgage-­backed  securities  (non-­ government)   Alternatives   Hedge  funds  (Absolute  return)   Derivatives   Private  equity  funds   Real  estate  funds   Total  (1)   December  31,  2014   Level  1   Level  2   Level  3   Total   $   —   $   (In  millions)   517   $   —   $   517   1,266   355   —   —   —   —   —   —   —   —   1,621   $   8   414   159   1,386   300   37   809   35   —   —   3,665   $   —   —   —   —   —   —   —   —   25   421   446   $   1,274   769   159   1,386   300   37   809   35   25   421   5,732   $   Asset   Allocation   9  %   22  %   14  %   3  %   24  %   5  %   1  %   14  %   1  %   —  %   7  %   100  %   (1)   Excludes  $92  million  as  of  December  31,  2014  of  receivables,  payables,  taxes  and  accrued  income  associated  with  financial  instruments   reflected  within  the  fair  value  table.   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  2015  and  2014:   Private  Equity   Funds   Real  Estate   Funds   Balance  as  of  January  1,  2014   Actual  return  on  plan  assets:   Unrealized  gains  (losses)   Realized  gains   Transfers  in  (out)   Balance  as  of  December  31,  2014   Actual  return  on  plan  assets:   Unrealized  gains   Realized  gains  (losses)   Transfers  in   Balance  as  of  December  31,  2015   $   $   $   (In  millions)   27   $   (2  )   1   (1  )   25   $   —   (1  )   —   24   $   385   17   14   5   421   42   16   108   587   83             As  of  December  31,  2015  and  2014,  the  OPEB  trust  investments  measured  at  fair  value  were  as  follows:   The  following  table  provides  a  reconciliation  of  changes  in  the  fair  value  of  OPEB  trust  investments  classified  as  Level  3  in  the  fair   December  31,  2015   Level  1   Level  2   Level  3   Total   Asset   Allocation   value  hierarchy  during  2015  and  2014:   Cash  and  short-­term  securities   $   —   $   (In  millions)   25   $   —   $   Equity  investment   Domestic   International   Fixed  income   U.S.  treasuries   Government  bonds   Corporate  bonds   High  yield  debt   Mortgage-­backed  securities  (non-­ government)   Alternatives   Hedge  funds   Real  estate  funds   Total  (1)   219   1   —   —   —   —   —   —   3   42   114   27   1   3   —   —   220   $   1   —   216   $   $   —   —   —   —   —   —   —   —   2   2   $   25   219   4   42   114   27   1   3   1   2   438   6  %   50  %   1  %   10  %   26  %   6  %   —  %   1  %   —  %   —  %   100  %   (1)   Excludes  $(7)  million  as  of  December  31,  2015  of  receivables,  payables,  taxes  and  accrued  income  associated  with  financial  instruments   reflected  within  the  fair  value  table. Target  Asset  Allocations   2015   2014   December  31,  2014   Level  1   Level  2   Level  3   Total   Asset   Allocation   Cash  and  short-­term  securities   $   —   $   (In  millions)   41   $   —   $   Equity  investment   Domestic   International   Fixed  income   U.S.  treasuries   Government  bonds   Corporate  bonds   High  yield  debt   Mortgage-­backed  securities  (non-­ government)   Alternatives   Hedge  funds   Real  estate  funds   Total  (1)   230   3   —   —   —   —   —   —   3   41   110   32   2   3   —   —   233   $   5   —   237   $   $   —   —   —   —   —   —   —   —   3   3   $   41   230   6   41   110   32   2   3   5   3   473   9  %   48  %   1  %   9  %   23  %   7  %   —  %   1  %   1  %   1  %   100  %   (1)   Excludes  $(9)  million  as  of  December  31,  2014,  of  receivables,  payables,  taxes  and  accrued  income  associated  with  financial  instruments   reflected  within  the  fair  value  table.   84   Real  Estate   Funds   Balance  as  of  January  1,  2014   Balance  as  of  December  31,  2014   Transfers  out   Transfers  out   Balance  as  of  December  31,  2015   $   $   $   5   (2  )   3   (1  )   2   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  2015  and  2014  are  shown  in  the  following  table:   Equities   Fixed  income   Absolute  return  strategies   Real  estate   Alternative  investments   Cash   38  %   30  %   8  %   10  %   8  %   6  %   42  %   32  %   14  %   5  %   1  %   6  %   100  %   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   $   26   $   (1  )   (23  )   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)   $   484   $   54   $   54   54   54   54   259   (3  )   (3  )   (3  )   (3  )   (3  )   (9  )   2016   2017   2018   2019   2020   Years  2021-­2025   505   522   533   551   2,946   85                 As  of  December  31,  2015  and  2014,  the  OPEB  trust  investments  measured  at  fair  value  were  as  follows:   The  following  table  provides  a  reconciliation  of  changes  in  the  fair  value  of  OPEB  trust  investments  classified  as  Level  3  in  the  fair   value  hierarchy  during  2015  and  2014:   Real  Estate   Funds   Balance  as  of  January  1,  2014   Transfers  out   Balance  as  of  December  31,  2014   Transfers  out   Balance  as  of  December  31,  2015   $   $   $   5   (2  )   3   (1  )   2   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.   (1)   Excludes  $(7)  million  as  of  December  31,  2015  of  receivables,  payables,  taxes  and  accrued  income  associated  with  financial  instruments   reflected  within  the  fair  value  table. Target  Asset  Allocations   2015   2014   $   220   $   216   $   2   $   438   FirstEnergy’s  target  asset  allocations  for  its  pension  and  OPEB  trust  portfolios  for  2015  and  2014  are  shown  in  the  following  table:   Equities   Fixed  income   Absolute  return  strategies   Real  estate   Alternative  investments   Cash   38  %   30  %   8  %   10  %   8  %   6  %   100  %   42  %   32  %   14  %   5  %   1  %   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   $   26   $   (1  )   (23  )   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)   $   2016   2017   2018   2019   2020   Years  2021-­2025   484   $   505   522   533   551   2,946   85   54   $   54   54   54   54   259   (3  )   (3  )   (3  )   (3  )   (3  )   (9  )   Cash  and  short-­term  securities   $   —   $   (In  millions)   25   $   —   $   December  31,  2015   Level  1   Level  2   Level  3   Total   Asset   Allocation   Cash  and  short-­term  securities   $   —   $   (In  millions)   41   $   —   $   December  31,  2014   Level  1   Level  2   Level  3   Total   Asset   Allocation   Equity  investment   Domestic   International   Fixed  income   U.S.  treasuries   Government  bonds   Corporate  bonds   High  yield  debt   government)   Alternatives   Hedge  funds   Real  estate  funds   Total  (1)   Mortgage-­backed  securities  (non-­ Equity  investment   Domestic   International   Fixed  income   U.S.  treasuries   Government  bonds   Corporate  bonds   High  yield  debt   government)   Alternatives   Hedge  funds   Real  estate  funds   Total  (1)   Mortgage-­backed  securities  (non-­ 25   219   4   42   114   27   1   3   1   2   41   230   6   41   110   32   2   3   5   3   6  %   50  %   1  %   10  %   26  %   6  %   —  %   1  %   —  %   —  %   100  %   9  %   48  %   1  %   9  %   23  %   7  %   —  %   1  %   1  %   1  %   —   —   —   —   —   —   —   —   2   —   —   —   —   —   —   —   —   3   —   3   42   114   27   1   3   1   —   —   3   41   110   32   2   3   5   —   219   1   —   —   —   —   —   —   —   230   3   —   —   —   —   —   —   —   84   (1)   Excludes  $(9)  million  as  of  December  31,  2014,  of  receivables,  payables,  taxes  and  accrued  income  associated  with  financial  instruments   reflected  within  the  fair  value  table.   $   233   $   237   $   3   $   473   100  %                 FES’  share  of  the  pension  and  OPEB  net  (liability)  asset  as  of  December  31,  2015  and  2014,  was  as  follows:   Pension   OPEB   2015   2014   2015   2014   Net  (Liability)  Asset   $   (303  )   $   (In  millions)   (295  )   $   25   $   10   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,  2015  was  as  follows:   Stock-­based  compensation  costs  capitalized   Pension   2015   2014   2013   2015   (In  millions)   OPEB   2014   2013   Stock  option  expense  was  not  material  for  FirstEnergy  or  FES  for  the  years  December  31,  2015,  2014  or  2013.  Income  tax  benefits   associated  with  stock  based  compensation  plan  expense  were  $12  million,  $14  million  and  $23  million  (FES  -­  $2  million,  $2  million   and  $1  million)  for  the  years  ended  2015,  2014  and  2013,  respectively.   Net  Periodic  Cost  (Credit)   $   10   $   150   $   (30  )   $   (22  )   $   (24  )   $   (40  )   Restricted  Stock  Units   4.  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,  2015,  approximately  9.9  million  shares  were   available  for  future  grants  under  the  ICP  2015  assuming  maximum  performance  metrics  are  achieved  for  the  outstanding  cycles  of   restricted  stock  units.  No  shares  are  available  for  future  grants  under  the  ICP  2007.  Any  shares  not  issued  due  to  forfeitures  or   cancellations  are  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.  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,  less   estimated  forfeitures.  FirstEnergy  adjusts  the  compensation  costs  for  stock-­based  compensation  awards  that  will  be  paid  in  cash   based  on  changes  in  the  fair  value  of  the  award  as  of  each  reporting  date.    FirstEnergy  records  the  actual  tax  benefit  realized  from  tax   deductions  when  awards  are  exercised  or  settled.  Realized  tax  benefits  during  the  years  ended  December  31,  2015,  2014  and  2013   were  $10  million,  $13  million  and  $13  million,  respectively.  The  excess  of  the  deductible  amount  over  the  recognized  compensation   cost  is  recorded  as  a  component  of  stockholders’  equity  and  reported  as  a  financing  activity  on  the  Consolidated  Statements  of  Cash   Flows.   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   Years  ended  December  31,   2015   2014   2013   FES   Stock-­based  Compensation  Plan   Restricted  Stock  Units   Performance  Shares   401(k)  Savings  Plan        Total   Years  ended  December  31,   2015   2014   2013   (In  millions)   $   $   $   6   $   —   5   11   $   1   $   4   $   1   4   9   $   1   $   (1  )   6   4   9   1   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.  Prior  to  2015,  all  performance-­based  restricted  stock  units  were  paid  in  stock.  Restricted  stock  units  paid  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.  Compensation  expense  is  recognized  for  the  grant  date   fair  value  of  awards  that  are  expected  to  vest.  Restricted  stock  units  paid  in  cash  provide  the  participant  the  right  to  receive  cash   based  on  the  numbers  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,  2015  was  $3  million.  No  cash  was  paid  to  settle  the  restricted  stock  unit  obligations  in  2015.   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.   Restricted  stock  unit  activity  for  the  year  ended  December  31,  2015,  was  as  follows:   Restricted  Stock  Unit  Activity   Shares   Nonvested  as  of  January  1,  2015   Granted  in  2015   Forfeited  in  2015   Vested  in  2015(1)   Nonvested  as  of  December  31,  2015   Weighted-­ Average  Grant   Date  Fair  Value   2,069,518   $   1,157,755   (231,271  )   (559,114  )   2,436,888   $   37.65   35.27   34.19   44.58   35.26   (1)  Excludes  dividend  equivalents  of  89,681  earned  during  vesting  period The  weighted  average  fair  value  of  awards  granted  in  2015,  2014  and  2013  were  $35.27,  $32.17  and  $39.90  respectively.  For  the   years  ended  December  31,  2015,  2014,  and  2013,  the  fair  value  of  restricted  stock  units  vested  was  $22  million,  $28  million,  and  $37   million,  respectively.  As  of  December  31,  2015,  there  was  $32  million  of  total  unrecognized  compensation  cost  related  to  non-­vested   share-­based  compensation  arrangements  granted  for  restricted  stock  units;;  that  cost  is  expected  to  be  recognized  over  a  period  of   approximately  two  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  Stock  Units   Restricted  Stock   Performance  Shares   401(k)  Savings  Plan   EDCP  &  DCPD        Total   Stock-­based  compensation  costs  capitalized   $   $   $   26   $   5   5   25   8   69   $   23   $   46   $   2   —   38   3   89   $   32   $   36   6   (10  )   25   3   60   20   (In  millions)   86   87                                               FES   Stock-­based  Compensation  Plan   Years  ended  December  31,   2015   2014   2013   (In  millions)   6   (1  )   4   9   1   4   $   1   4   9   $   1   $   6   $   —   5   11   $   1   $   FES’  share  of  the  net  periodic  benefit  cost  (credit),  including  the  pension  and  OPEB  mark-­to-­market  adjustment,  for  the  three  years   Stock-­based  compensation  costs  capitalized   ended  December  31,  2015  was  as  follows:   Restricted  Stock  Units   Performance  Shares   401(k)  Savings  Plan        Total   $   $   $   FES’  share  of  the  pension  and  OPEB  net  (liability)  asset  as  of  December  31,  2015  and  2014,  was  as  follows:   Pension   OPEB   2015   2014   2015   2014   (In  millions)   Net  (Liability)  Asset   $   (303  )   $   (295  )   $   25   $   10   4.  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,  2015,  approximately  9.9  million  shares  were   available  for  future  grants  under  the  ICP  2015  assuming  maximum  performance  metrics  are  achieved  for  the  outstanding  cycles  of   restricted  stock  units.  No  shares  are  available  for  future  grants  under  the  ICP  2007.  Any  shares  not  issued  due  to  forfeitures  or   cancellations  are  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.  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,  less   estimated  forfeitures.  FirstEnergy  adjusts  the  compensation  costs  for  stock-­based  compensation  awards  that  will  be  paid  in  cash   based  on  changes  in  the  fair  value  of  the  award  as  of  each  reporting  date.    FirstEnergy  records  the  actual  tax  benefit  realized  from  tax   deductions  when  awards  are  exercised  or  settled.  Realized  tax  benefits  during  the  years  ended  December  31,  2015,  2014  and  2013   were  $10  million,  $13  million  and  $13  million,  respectively.  The  excess  of  the  deductible  amount  over  the  recognized  compensation   cost  is  recorded  as  a  component  of  stockholders’  equity  and  reported  as  a  financing  activity  on  the  Consolidated  Statements  of  Cash   Flows.   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   Years  ended  December  31,   2015   2014   2013   (In  millions)   $   $   $   46   $   2   —   38   3   89   $   32   $   26   $   5   5   25   8   69   $   23   $   (10  )   36   6   25   3   60   20   2015   2014   2013   2015   2013   Pension   OPEB   2014   (In  millions)   Stock  option  expense  was  not  material  for  FirstEnergy  or  FES  for  the  years  December  31,  2015,  2014  or  2013.  Income  tax  benefits   associated  with  stock  based  compensation  plan  expense  were  $12  million,  $14  million  and  $23  million  (FES  -­  $2  million,  $2  million   and  $1  million)  for  the  years  ended  2015,  2014  and  2013,  respectively.   Net  Periodic  Cost  (Credit)   $   10   $   150   $   (30  )   $   (22  )   $   (24  )   $   (40  )   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.  Prior  to  2015,  all  performance-­based  restricted  stock  units  were  paid  in  stock.  Restricted  stock  units  paid  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.  Compensation  expense  is  recognized  for  the  grant  date   fair  value  of  awards  that  are  expected  to  vest.  Restricted  stock  units  paid  in  cash  provide  the  participant  the  right  to  receive  cash   based  on  the  numbers  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,  2015  was  $3  million.  No  cash  was  paid  to  settle  the  restricted  stock  unit  obligations  in  2015.   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.   Restricted  stock  unit  activity  for  the  year  ended  December  31,  2015,  was  as  follows:   Restricted  Stock  Unit  Activity   Shares   Weighted-­ Average  Grant   Date  Fair  Value   Nonvested  as  of  January  1,  2015   Granted  in  2015   Forfeited  in  2015   Vested  in  2015(1)   Nonvested  as  of  December  31,  2015   $   2,069,518   1,157,755   (231,271  )   (559,114  )   2,436,888   $   37.65   35.27   34.19   44.58   35.26   (1)  Excludes  dividend  equivalents  of  89,681  earned  during  vesting  period The  weighted  average  fair  value  of  awards  granted  in  2015,  2014  and  2013  were  $35.27,  $32.17  and  $39.90  respectively.  For  the   years  ended  December  31,  2015,  2014,  and  2013,  the  fair  value  of  restricted  stock  units  vested  was  $22  million,  $28  million,  and  $37   million,  respectively.  As  of  December  31,  2015,  there  was  $32  million  of  total  unrecognized  compensation  cost  related  to  non-­vested   share-­based  compensation  arrangements  granted  for  restricted  stock  units;;  that  cost  is  expected  to  be  recognized  over  a  period  of   approximately  two  years.   Stock-­based  compensation  costs  capitalized   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.   86   87                                               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  $9  million  and  $8  million  as  of  December  31,  2015  and  December  31,  2014,  respectively,  is  included  in  the   caption  “Retirement  benefits”  on  the  Consolidated  Balance  Sheets.   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.     FES  and  the  Utilities  are  party  to  an  intercompany  income  tax  allocation  agreement  with  FirstEnergy  and  its  other  subsidiaries  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  18,  2015,  the  President  signed  into  law  the  Protecting  Americans  from  Tax  Hikes  Act  of  2015  (the  Act).  The  Act,  among   other  things,  made  permanent  the  R&D  tax  credit,  and  also  extended  accelerated  depreciation  of  qualified  capital  investments  placed   into  service.  This  bonus  depreciation  provision  is  50%  for  qualifying  assets  placed  into  service  from  2015  through  2017,  40%  for   qualifying  assets  placed  into  service  in  2018  and  30%  for  qualifying  assets  placed  into  service  in  2019.  FirstEnergy  and  FES  recorded   the  effects  of  the  Act  that  apply  to  2015  in  the  fourth  quarter  of  2015.  The  extension  of  the  tax  benefits  did  not  have  a  significant   impact  to  the  effective  tax  rate.     Restricted  common  stock  (restricted  stock)  activity  for  the  year  ended  December  31,  2015,  was  as  follows:   EDCP   Restricted  Stock   Nonvested  as  of  January  1,  2015   Granted  in  2015   Forfeited  in  2015   Vested  in  2015(1)   Nonvested  as  of  December  31,  2015   Number  of   Shares   342,286   $   65,434   (26,079  )   (190,985  )   190,656   $   Weighted   Average   Grant-­Date   Fair  Value   45.29   32.98   57.58   43.17   40.65   (1)  Excludes  52,872  shares  for  dividends  earned  during  vesting  period The  weighted  average  vesting  period  for  restricted  stock  granted  in  2015  was  5.59  years.  The  weighted  average  fair  value  of  awards   granted  in  2015,  2014,  and  2013  were  $32.98,  $32.71  and  $42.53  respectively.    For  the  years  ended  December  31,  2015,  2014,  and   2013,  the  fair  value  of  restricted  stock  vested  was  $8  million,  $4  million,  and  $7  million,  respectively.  As  of  December  31,  2015,  there   was  $3  million  of  total  unrecognized  compensation  cost  related  to  non-­vested  restricted  stock,  which  is  expected  to  be  recognized   over  a  period  of  approximately  three  years.   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  2015.  Stock  option  activity  during  2015  was  as  follows:        5.  TAXES   Stock  Option  Activity   Balance,  January  1,  2015  (1,077,988  options  exercisable)   Options  exercised   Options  forfeited   Balance,  December  31,  2015  (1,211,358  options  exercisable)   Number  of   Shares   1,439,145   $   (18,551  )   (8,623  )   1,411,971   $   Weighted   Average   Exercise   Price   44.83   29.53   68.02   44.89   Cash  received  from  the  exercise  of  stock  options  in  2015,  2014  and  2013  was  $1  million,  $1  million  and  $19  million,  respectively.  The   total  intrinsic  value  of  options  exercised  during  2015  was  not  material.  The  weighted-­average  remaining  contractual  term  of  options   outstanding  as  of  December  31,  2015  was  3.58  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.  No  performance  shares  were  granted  in  2015.  In  2014,  $3  million  cash   was  paid  to  settle  performance  share  obligations.  During  2015  and  2013,  no  cash  was  paid  to  settle  performance  shares  due  to  the   performance  criteria  not  being  met  for  the  previous  three-­year  vesting  period.   401(k)  Savings  Plan   In  2015  and  2014,  1,072,494  and  756,412  shares  of  FE  common  stock,  respectively,  were  issued  and  contributed  to  participants'   accounts.  In  2013,  approximately  708,000  shares  of  FE  common  stock  were  purchased  on  the  market  and  contributed  to  participants’   accounts.     88   89                                                     Restricted  common  stock  (restricted  stock)  activity  for  the  year  ended  December  31,  2015,  was  as  follows:   EDCP   Restricted  Stock   Nonvested  as  of  January  1,  2015   Granted  in  2015   Forfeited  in  2015   Vested  in  2015(1)   Nonvested  as  of  December  31,  2015   Number  of   Shares   342,286   $   65,434   (26,079  )   (190,985  )   190,656   $   Weighted   Average   Grant-­Date   Fair  Value   45.29   32.98   57.58   43.17   40.65   (1)  Excludes  52,872  shares  for  dividends  earned  during  vesting  period The  weighted  average  vesting  period  for  restricted  stock  granted  in  2015  was  5.59  years.  The  weighted  average  fair  value  of  awards   granted  in  2015,  2014,  and  2013  were  $32.98,  $32.71  and  $42.53  respectively.    For  the  years  ended  December  31,  2015,  2014,  and   2013,  the  fair  value  of  restricted  stock  vested  was  $8  million,  $4  million,  and  $7  million,  respectively.  As  of  December  31,  2015,  there   was  $3  million  of  total  unrecognized  compensation  cost  related  to  non-­vested  restricted  stock,  which  is  expected  to  be  recognized   over  a  period  of  approximately  three  years.   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  2015.  Stock  option  activity  during  2015  was  as  follows:   Balance,  January  1,  2015  (1,077,988  options  exercisable)   Stock  Option  Activity   Options  exercised   Options  forfeited   Balance,  December  31,  2015  (1,211,358  options  exercisable)   Number  of   Shares   1,439,145   $   (18,551  )   (8,623  )   1,411,971   $   Weighted   Average   Exercise   Price   44.83   29.53   68.02   44.89   Cash  received  from  the  exercise  of  stock  options  in  2015,  2014  and  2013  was  $1  million,  $1  million  and  $19  million,  respectively.  The   total  intrinsic  value  of  options  exercised  during  2015  was  not  material.  The  weighted-­average  remaining  contractual  term  of  options   outstanding  as  of  December  31,  2015  was  3.58  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.  No  performance  shares  were  granted  in  2015.  In  2014,  $3  million  cash   was  paid  to  settle  performance  share  obligations.  During  2015  and  2013,  no  cash  was  paid  to  settle  performance  shares  due  to  the   performance  criteria  not  being  met  for  the  previous  three-­year  vesting  period.   401(k)  Savings  Plan   accounts.     In  2015  and  2014,  1,072,494  and  756,412  shares  of  FE  common  stock,  respectively,  were  issued  and  contributed  to  participants'   accounts.  In  2013,  approximately  708,000  shares  of  FE  common  stock  were  purchased  on  the  market  and  contributed  to  participants’   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  $9  million  and  $8  million  as  of  December  31,  2015  and  December  31,  2014,  respectively,  is  included  in  the   caption  “Retirement  benefits”  on  the  Consolidated  Balance  Sheets.        5.  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.     FES  and  the  Utilities  are  party  to  an  intercompany  income  tax  allocation  agreement  with  FirstEnergy  and  its  other  subsidiaries  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  18,  2015,  the  President  signed  into  law  the  Protecting  Americans  from  Tax  Hikes  Act  of  2015  (the  Act).  The  Act,  among   other  things,  made  permanent  the  R&D  tax  credit,  and  also  extended  accelerated  depreciation  of  qualified  capital  investments  placed   into  service.  This  bonus  depreciation  provision  is  50%  for  qualifying  assets  placed  into  service  from  2015  through  2017,  40%  for   qualifying  assets  placed  into  service  in  2018  and  30%  for  qualifying  assets  placed  into  service  in  2019.  FirstEnergy  and  FES  recorded   the  effects  of  the  Act  that  apply  to  2015  in  the  fourth  quarter  of  2015.  The  extension  of  the  tax  benefits  did  not  have  a  significant   impact  to  the  effective  tax  rate.     88   89                                                     INCOME  TAXES  (BENEFITS)(1)   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   Total  provision  for  income  taxes  (benefits)   $   2015   2014   2013   (In  millions)   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  at  the  federal  statutory  rate  to  the  total  income  taxes  on  continuing  operations  for  the   three  years  ended  December  31:   1   $   30   31   277   15   292   (8  )   315   $   (56  )   $   2   (54  )   103   18   121   (2  )   65   $   (132  )   $   (72  )   (204  )   214   (42  )   172   (10  )   (42  )   $   (222  )   $   (13  )   (235  )   25   (14  )   11   (4  )   (228  )   $   (118  )   70   (48  )   305   (54  )   251   (8  )   195   (300  )   (3  )   (303  )   317   (4  )   313   (4  )   6   (1)Provision   for   Income   Taxes   (Benefits)   on   Income   from   Continuing   Operations.   Currently   payable   (receivable)   in   2014   excludes   $106   million   and   $12   million   of   federal   and   state   taxes,   respectively,   associated   with   discontinued   operations.   Deferred,   net   in   2014   excludes   $44  million   and   $5   million   of   federal   and   state   tax   benefits,   respectively,   associated   with   discontinued  operations.   FirstEnergy   Income  from  Continuing  Operations  before  income  taxes   Federal  income  tax  expense  at  statutory  rate  (35%)   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   Tax  basis  balance  sheet  adjustments   Uncertain  tax  positions   Other,  net   Total  income  taxes  (benefits)   Effective  income  tax  rate   FES   Increases  (reductions)  in  taxes  resulting  from-­   State  income  taxes,  net  of  federal  tax  benefit   Amortization  of  investment  tax  credits   ESOP  dividend   Uncertain  tax  positions   Other,  net   Total  income  taxes  (benefits)   Effective  income  tax  rate   2015   2014   2013   (In  millions)   $   $   893   313   $   $   171   60   $   $   570   199   315   $   35.3  %   (42  )   $   (24.6  )%   195   34.2  %   34   (16  )   (8  )   (8  )   (6  )   —   1   5   16   (2  )   (1  )   5   (4  )   $   $   $   12   (13  )   (10  )   (27  )   (6  )   (25  )   (35  )   2   (14  )   (4  )   (1  )   —   (3  )   10   (7  )   (8  )   —   (9  )   —   (2  )   12   52   18   (5  )   (4  )   (2  )   —   (1  )   6   65   $   44.2  %   (228  )   $   38.8   %   11.5  %   Income  (loss)  from  Continuing  Operations  before  income  taxes  (benefits)   $   Federal  income  tax  expense  (benefit)  at  statutory  rate  (35%)   147   51   $   $   (588  )   (206  )   $   $   In  2015,  FirstEnergy’s  effective  tax  rate  was  35.3%  compared  to  (24.6)%  in  2014.  The  increase  in  the  effective  tax  rate  year-­over-­year   resulted  from  lower  tax  benefits  in  2015  as  compared  to  2014,  primarily  related  to  IRS  approved  changes  in  accounting  methods,   reduced  tax  benefits  on  uncertain  tax  positions,  partially  offset  by  lower  valuation  allowances  required  on  state  and  municipal  net   operating  loss  carryforwards  that  FirstEnergy  believes  are  no  longer  realizable.  Additionally,  during  2014,  income  tax  benefits  of  $25   million   were   recorded   that   related   to   prior   periods.  The   out-­of-­period   adjustment   primarily   related   to   the   correction   of   amounts   included  in  the  FirstEnergy’s  tax  basis  balance  sheet.  Management  determined  that  this  adjustment  was  not  material  to  2014  or  any   prior  period.  The  increase  in  the  effective  rate  was  also  impacted  by  higher  income  from  continuing  operations.   In  2015,  FES’  effective  tax  rate  on  income  from  continuing  operations  was  44.2%  compared  to  38.8%  on  a  loss  from  continuing   operations  in  2014.  The  increase  in  the  effective  tax  rate  is  primarily  due  to  an  increase  in  reserves  associated  with  uncertain  tax   positions  in  2015  and  the  absence  of  tax  benefits  recognized  in  2014  associated  with  changes  in  state  apportionment  factors,  partially   offset  by  lower  valuation  allowances  recorded  on  state  and  municipal  NOL  carryforwards  that  FirstEnergy  believes  are  no  longer   realizable.   90   91                   INCOME  TAXES  (BENEFITS)(1)   FirstEnergy   Currently  payable  (receivable)-­   Federal   State   Deferred,  net-­   Federal   State   FES   Federal   State   Deferred,  net-­   Federal   State   Investment  tax  credit  amortization   Total  provision  for  income  taxes  (benefits)   315   $   (42  )   $   Currently  payable  (receivable)-­   $   $   $   1   $   30   31   277   15   292   (8  )   (56  )   $   2   (54  )   103   18   121   (2  )   (132  )   $   (72  )   (204  )   214   (42  )   172   (10  )   (222  )   $   (13  )   (235  )   25   (14  )   11   (4  )   (118  )   70   (48  )   305   (54  )   251   (8  )   195   (300  )   (3  )   (303  )   317   (4  )   313   (4  )   6   Investment  tax  credit  amortization   Total  provision  for  income  taxes  (benefits)   $   65   $   (228  )   $   (1)Provision   for   Income   Taxes   (Benefits)   on   Income   from   Continuing   Operations.   Currently   payable   (receivable)   in   2014   excludes   $106   million   and   $12   million   of   federal   and   state   taxes,   respectively,   associated   with   discontinued   operations.   Deferred,   net   in   2014   excludes   $44   million   and   $5   million   of   federal   and   state   tax   benefits,   respectively,   associated   with   discontinued  operations.   2015   2014   2013   (In  millions)   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  at  the  federal  statutory  rate  to  the  total  income  taxes  on  continuing  operations  for  the   three  years  ended  December  31:   FirstEnergy   Income  from  Continuing  Operations  before  income  taxes   Federal  income  tax  expense  at  statutory  rate  (35%)   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   Tax  basis  balance  sheet  adjustments   Uncertain  tax  positions   Other,  net   Total  income  taxes  (benefits)   Effective  income  tax  rate   FES   Income  (loss)  from  Continuing  Operations  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   Uncertain  tax  positions   Other,  net   Total  income  taxes  (benefits)   Effective  income  tax  rate   $   2015   2014   2013   (In  millions)   $   $   893   313   $   $   171   60   $   $   34   (16  )   (8  )   (8  )   (6  )   —   1   5   315   $   12   (13  )   (10  )   (27  )   (6  )   (25  )   (35  )   2   (42  )   $   $   570   199   10   (7  )   (8  )   —   (9  )   —   (2  )   12   195   35.3  %   (24.6  )%   34.2  %   147   51   $   $   16   (2  )   (1  )   5   (4  )   65   44.2  %   $   (588  )   (206  )   $   $   (14  )   (4  )   (1  )   —   (3  )   (228  )   $   38.8   %   52   18   (5  )   (4  )   (2  )   —   (1  )   6   11.5  %   In  2015,  FirstEnergy’s  effective  tax  rate  was  35.3%  compared  to  (24.6)%  in  2014.  The  increase  in  the  effective  tax  rate  year-­over-­year   resulted  from  lower  tax  benefits  in  2015  as  compared  to  2014,  primarily  related  to  IRS  approved  changes  in  accounting  methods,   reduced  tax  benefits  on  uncertain  tax  positions,  partially  offset  by  lower  valuation  allowances  required  on  state  and  municipal  net   operating  loss  carryforwards  that  FirstEnergy  believes  are  no  longer  realizable.  Additionally,  during  2014,  income  tax  benefits  of  $25   million   were   recorded   that   related   to   prior   periods.  The   out-­of-­period   adjustment   primarily   related   to   the   correction   of   amounts   included  in  the  FirstEnergy’s  tax  basis  balance  sheet.  Management  determined  that  this  adjustment  was  not  material  to  2014  or  any   prior  period.  The  increase  in  the  effective  rate  was  also  impacted  by  higher  income  from  continuing  operations.   In  2015,  FES’  effective  tax  rate  on  income  from  continuing  operations  was  44.2%  compared  to  38.8%  on  a  loss  from  continuing   operations  in  2014.  The  increase  in  the  effective  tax  rate  is  primarily  due  to  an  increase  in  reserves  associated  with  uncertain  tax   positions  in  2015  and  the  absence  of  tax  benefits  recognized  in  2014  associated  with  changes  in  state  apportionment  factors,  partially   offset  by  lower  valuation  allowances  recorded  on  state  and  municipal  NOL  carryforwards  that  FirstEnergy  believes  are  no  longer   realizable.   90   91                   company's  tax  return.  As  of  December  31,  2015  and  2014,  FirstEnergy's  total  unrecognized  income  tax  benefits  were  approximately   $34   million.   If   ultimately   recognized   in   future   years,   approximately   $29   million   of   unrecognized   income   tax   benefits   as   of   December  31,  2015,  would  impact  the  effective  tax  rate.  As  of  December  31,  2015,  it  is  reasonably  possible  that  approximately  $9   million   of   unrecognized   tax   benefits   may   be   resolved   during   2016   as   a   result   of   the   statute   of   limitations   expiring,   of   which   approximately  $7  million  would  affect  FirstEnergy's  effective  tax  rate.   The  following  table  summarizes  the  changes  in  unrecognized  tax  positions  for  the  years  ended  2015,  2014  and  2013:   Balance,  January  1,  2013   Prior  years  increases   Prior  years  decreases   Balance,  December  31,  2013   Current  year  increases   Prior  years  increases   Prior  years  decreases   Balance,  December  31,  2014   Current  year  increases   Prior  years  increases   Prior  years  decreases   Balance,  December  31,  2015   FirstEnergy   FES   (In  millions)   $   $   $   $   43   $   10   (5  )   48   $   4   5   3   7   (23  )   34   $   (10  )   34   $   3   —   —   3   —   —   —   3   —   5   —   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  reversal  of  accrued  interest  associated  with   unrecognized  tax  benefits  reduced  FirstEnergy's  effective  tax  rate  in  2015  and  2014  by  approximately  $1  million  and  $6  million,   respectively.  There  was  an  increase  of  $1  million  of  accrued  interest  for  the  year  ended  December  31,  2013.   The  following  table  summarizes  the  net  interest  expense  (income)  for  the  three  years  ended  December  31,  2015  and  the  cumulative   net  interest  payable  as  of  December  31,  2015  and  2014  (FES  did  not  have  net  interest  expense  (income)  or  a  net  interest  payable  for   the  periods  presented):   Net  Interest  Expense  (Income)   For  the  Years  Ended  December  31,   Net  Interest  Payable   As  of  December  31,   2015   2014   2013   2015   2014   FirstEnergy   $   (1  )   $   (6  )   $   (In  millions)   1   $   (In  millions)   1   $   2   Accumulated  deferred  income  taxes  as  of  December  31,  2015  and  2014  are  as  follows:   FirstEnergy   Property  basis  differences   Deferred  sale  and  leaseback  gain   Pension  and  OPEB   Nuclear  decommissioning  activities   Asset  retirement  obligations   Regulatory  asset/liability   Loss  carryforwards  and  AMT  credits   Loss  carryforward  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   Loss  carryforwards  and  AMT  credits   Loss  carryforward  valuation  reserve   All  other   Net  deferred  income  tax  liability   2015   2014   (In  millions)   $   $   $   $   9,920   $   (360  )   (1,541  )   480   (731  )   763   (1,965  )   192   15   6,773   $   1,901   $   (342  )   (393  )   95   483   (509  )   (687  )   46   6   600   $   9,354   (381  )   (1,433  )   458   (641  )   768   (1,932  )   174   172   6,539   1,749   (356  )   (373  )   75   489   (486  )   (631  )   32   (15  )   484   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  2011-­2014.  In  January  2015,  the  IRS  completed  its  examination  of  the  2013  federal   income   tax   return   and   issued   a   Revenue  Agent   Report   and   there   were   no   material   impacts   to   FirstEnergy's   effective   tax   rate   associated  with  this  examination.  Tax  year  2014  is  currently  under  review  by  the  IRS.   FirstEnergy  has  recorded  as  deferred  income  tax  assets  the  effect  of  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,  2015,  the  deferred  income   tax   assets,   before   any   valuation   allowances,   for   loss   carryforwards   and  AMT   credits   consisted   of   $1.5   billion   of   Federal   NOL   carryforwards,  net  of  tax,  that  will  begin  to  expire  in  2030,  Federal  AMT  credits  of  $26  million,  net  of  tax,  that  have  an  indefinite   carryforward  period,  and  $398  million,  net  of  tax,  of  state  and  local  NOL  carryforwards  that  will  begin  to  expire  in  2016.     The  table  below  summarizes  pre-­tax  NOL  carryforwards  for  state  and  local  income  tax  purposes  of  approximately  $10  billion  for   FirstEnergy,  of  which  approximately  $6  billion  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.   Expiration  Period   FirstEnergy   FES   2016-­2020   2021-­2025   2026-­2030   2031-­2035   (In  millions)   State   Local   State   Local   $   $   403   $   1,323   2,205   3,245   7,176   $   2,983   $   —   —   —   2,983   $   95   $   68   259   1,128   1,550   $   1,820   —   —   —   1,820   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   92   93                             company's  tax  return.  As  of  December  31,  2015  and  2014,  FirstEnergy's  total  unrecognized  income  tax  benefits  were  approximately   $34   million.   If   ultimately   recognized   in   future   years,   approximately   $29   million   of   unrecognized   income   tax   benefits   as   of   December  31,  2015,  would  impact  the  effective  tax  rate.  As  of  December  31,  2015,  it  is  reasonably  possible  that  approximately  $9   million   of   unrecognized   tax   benefits   may   be   resolved   during   2016   as   a   result   of   the   statute   of   limitations   expiring,   of   which   approximately  $7  million  would  affect  FirstEnergy's  effective  tax  rate.   The  following  table  summarizes  the  changes  in  unrecognized  tax  positions  for  the  years  ended  2015,  2014  and  2013:   Balance,  January  1,  2013   Prior  years  increases   Prior  years  decreases   Balance,  December  31,  2013   Current  year  increases   Prior  years  increases   Prior  years  decreases   Balance,  December  31,  2014   Current  year  increases   Prior  years  increases   Prior  years  decreases   Balance,  December  31,  2015   FirstEnergy   FES   $   $   $   $   (In  millions)   43   $   10   (5  )   48   $   4   5   (23  )   34   $   3   7   (10  )   34   $   3   —   —   3   —   —   —   3   —   5   —   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  reversal  of  accrued  interest  associated  with   unrecognized  tax  benefits  reduced  FirstEnergy's  effective  tax  rate  in  2015  and  2014  by  approximately  $1  million  and  $6  million,   respectively.  There  was  an  increase  of  $1  million  of  accrued  interest  for  the  year  ended  December  31,  2013.   The  following  table  summarizes  the  net  interest  expense  (income)  for  the  three  years  ended  December  31,  2015  and  the  cumulative   net  interest  payable  as  of  December  31,  2015  and  2014  (FES  did  not  have  net  interest  expense  (income)  or  a  net  interest  payable  for   the  periods  presented):   Net  Interest  Expense  (Income)   For  the  Years  Ended  December  31,   Net  Interest  Payable   As  of  December  31,   2015   2014   2013   2015   2014   FirstEnergy   $   (1  )   $   (6  )   $   (In  millions)   1   $   (In  millions)   1   $   2   Accumulated  deferred  income  taxes  as  of  December  31,  2015  and  2014  are  as  follows:   FirstEnergy   Property  basis  differences   Deferred  sale  and  leaseback  gain   Pension  and  OPEB   Nuclear  decommissioning  activities   Asset  retirement  obligations   Regulatory  asset/liability   Loss  carryforwards  and  AMT  credits   Loss  carryforward  valuation  reserve   Net  deferred  income  tax  liability   All  other   FES   Property  basis  differences   Deferred  sale  and  leaseback  gain   Pension  and  OPEB   Lease  market  valuation  liability   Nuclear  decommissioning  activities   Asset  retirement  obligations   Loss  carryforwards  and  AMT  credits   Loss  carryforward  valuation  reserve   All  other   Net  deferred  income  tax  liability   2015   2014   (In  millions)   $   9,920   $   $   $   1,901   $   1,749   (360  )   (1,541  )   480   (731  )   763   (1,965  )   192   15   6,773   $   (342  )   (393  )   95   483   (509  )   (687  )   46   6   9,354   (381  )   (1,433  )   458   (641  )   768   (1,932  )   174   172   6,539   (356  )   (373  )   75   489   (486  )   (631  )   32   (15  )   484   $   600   $   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  2011-­2014.  In  January  2015,  the  IRS  completed  its  examination  of  the  2013  federal   income   tax   return   and   issued   a   Revenue  Agent   Report   and   there   were   no   material   impacts   to   FirstEnergy's   effective   tax   rate   associated  with  this  examination.  Tax  year  2014  is  currently  under  review  by  the  IRS.   FirstEnergy  has  recorded  as  deferred  income  tax  assets  the  effect  of  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,  2015,  the  deferred  income   tax   assets,   before   any   valuation   allowances,   for   loss   carryforwards   and  AMT   credits   consisted   of   $1.5   billion   of   Federal   NOL   carryforwards,  net  of  tax,  that  will  begin  to  expire  in  2030,  Federal  AMT  credits  of  $26  million,  net  of  tax,  that  have  an  indefinite   carryforward  period,  and  $398  million,  net  of  tax,  of  state  and  local  NOL  carryforwards  that  will  begin  to  expire  in  2016.     The  table  below  summarizes  pre-­tax  NOL  carryforwards  for  state  and  local  income  tax  purposes  of  approximately  $10  billion  for   FirstEnergy,  of  which  approximately  $6  billion  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.   Expiration  Period   FirstEnergy   FES   2016-­2020   2021-­2025   2026-­2030   2031-­2035   (In  millions)   State   Local   State   Local   403   $   2,983   $   1,323   2,205   3,245   —   —   —   7,176   $   2,983   $   95   $   68   259   1,128   1,550   $   1,820   —   —   —   1,820   $   $   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   92   93                             General  Taxes   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   2015   2014   2013   (In  millions)   $   $   $   $   193   $   224   410   119   32   978   $   44   $   36   16   2   98   $   194   $   226   393   112   37   962   $   69   $   39   17   3   128   $   219   240   368   110   41   978   77   40   19   2   138   6.  LEASES   leases.   FirstEnergy  leases  certain  generating  facilities,  office  space  and  other  property  and  equipment  under  cancelable  and  noncancelable   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,  expiring  in  2016.  In  that  same  year,  CEI  and  TE  also  sold  portions  of   their  ownership  interests  in  Beaver  Valley  Unit  2  and  Bruce  Mansfield  Units  1,  2  and  3  and  entered  into  similar  operating  leases  for   lease  terms  of  approximately  30  years  expiring  in  2017.  OE,  CEI  and  TE  have  the  right,  at  the  expiration  of  the  respective  basic  lease   terms,  to  renew  their  respective  leases.  They  also  have  the  right  to  purchase  the  facilities  at  the  expiration  of  the  basic  lease  term  or   any  renewal  term  at  a  price  equal  to  the  fair  market  value  of  the  facilities.  The  basic  rental  payments  are  adjusted  when  applicable   federal  tax  law  changes.   In  2007,  FG  completed  a  sale  and  leaseback  transaction  for  its  93.825%  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.  In  2013,  FG  acquired  the  remaining  lessor  interests  in  Bruce  Mansfield   Units  1,  2  and  3,  which  were  part  of  the  leases  entered  into  by  CEI  and  TE  in  1987.   In  February  2014,  NG  purchased 47.7  MW  of  lessor  equity  interests  in  OE's  existing  sale  and  leaseback  of  Beaver  Valley  Unit  2  for   approximately $94  million.  On  June  24,  2014,  OE  exercised  its  irrevocable  right  to  repurchase  from  the  remaining  owner  participants   the  lessors'  interests  in  Beaver  Valley  Unit  2  at  the  end  of  the  lease  term  (June  1,  2017),  which  right  to  repurchase  was  assigned  to   NG.  Additionally,  on  June  24,  2014,  NG  entered  into  a  purchase  agreement  with  an  owner  participant  to  purchase  its  lessor  equity   interests  of  the  remaining  non-­affiliated  leasehold  interest  in  Perry  Unit  1  on  May  23,  2016,  which  is  just  prior  to  the  end  of  the  lease   term.  In  November  2014,  NG  repurchased  55.3  MW  of  lessor  equity  interests  in  OE's  existing  sale  and  leaseback  of  Perry  Unit  1  for   approximately  $87  million.  OE  and  TE  continue  to  lease  these  MW  under  their  respective  sale  and  leaseback  arrangements  and  the   related  lease  debt  remains  outstanding.   Established  by  OE  in  1996,  PNBV  purchased  a  portion  of  the  lease  obligation  bonds  issued  on  behalf  of  lessors  in  OE’s  Perry  Unit  1   and  Beaver  Valley  Unit  2  sale  and  leaseback  transactions.  Similarly,  CEI  and  TE  established  Shippingport  in  1997  to  purchase  the   lease  obligation  bonds  issued  on  behalf  of  lessors  in  their  Bruce  Mansfield  Units  1,  2  and  3  sale  and  leaseback  transactions.  During   2013,  the  investments  held  at  Shippingport  were  liquidated.  The  PNBV  arrangements  effectively  reduce  lease  costs  related  to  those   transactions  (see  Note  8,  Variable  Interest  Entities).   As  of  December  31,  2015,  FirstEnergy's  leasehold  interest  was  3.75%  of  Perry  Unit  1,  93.83%  of  Bruce  Mansfield  Unit  1  and  2.60%   of  Beaver  Valley  Unit  2.   Operating  lease  expense  for  2015,  2014  and  2013,  is  summarized  as  follows:   2015   2014   2013   $   $   174   $   94   $   199   $   95   $   224   97   The  future  minimum  capital  lease  payments  as  of  December  31,  2015  are  as  follows:     (In  millions)   FirstEnergy   FES   Capital  leases   2016   2017   2018   2019   2020   Years  thereafter   Interest  portion   Total  minimum  lease  payments   Present  value  of  net  minimum  lease  payments   Less  current  portion   Noncurrent  portion   FirstEnergy   FES   $   (In  millions)   36   $   31   24   18   14   27   150   (18  )   132   32   $   100   $   6   6   2   —   —   —   14   (1  )   13   5   8   94   95                                   General  Taxes   6.  LEASES   FirstEnergy   KWH  excise   State  gross  receipts   Real  and  personal  property   Social  security  and  unemployment   Total  general  taxes   Other   FES   State  gross  receipts   Real  and  personal  property   Social  security  and  unemployment   Other   Total  general  taxes   2015   2014   2013   (In  millions)   $   193   $   194   $   978   $   962   $   224   410   119   32   44   $   36   16   2   98   $   226   393   112   37   69   $   39   17   3   128   $   $   $   $   219   240   368   110   41   978   77   40   19   2   138   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,  expiring  in  2016.  In  that  same  year,  CEI  and  TE  also  sold  portions  of   their  ownership  interests  in  Beaver  Valley  Unit  2  and  Bruce  Mansfield  Units  1,  2  and  3  and  entered  into  similar  operating  leases  for   lease  terms  of  approximately  30  years  expiring  in  2017.  OE,  CEI  and  TE  have  the  right,  at  the  expiration  of  the  respective  basic  lease   terms,  to  renew  their  respective  leases.  They  also  have  the  right  to  purchase  the  facilities  at  the  expiration  of  the  basic  lease  term  or   any  renewal  term  at  a  price  equal  to  the  fair  market  value  of  the  facilities.  The  basic  rental  payments  are  adjusted  when  applicable   federal  tax  law  changes.   In  2007,  FG  completed  a  sale  and  leaseback  transaction  for  its  93.825%  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.  In  2013,  FG  acquired  the  remaining  lessor  interests  in  Bruce  Mansfield   Units  1,  2  and  3,  which  were  part  of  the  leases  entered  into  by  CEI  and  TE  in  1987.   In  February  2014,  NG  purchased 47.7  MW  of  lessor  equity  interests  in  OE's  existing  sale  and  leaseback  of  Beaver  Valley  Unit  2  for   approximately $94  million.  On  June  24,  2014,  OE  exercised  its  irrevocable  right  to  repurchase  from  the  remaining  owner  participants   the  lessors'  interests  in  Beaver  Valley  Unit  2  at  the  end  of  the  lease  term  (June  1,  2017),  which  right  to  repurchase  was  assigned  to   NG.  Additionally,  on  June  24,  2014,  NG  entered  into  a  purchase  agreement  with  an  owner  participant  to  purchase  its  lessor  equity   interests  of  the  remaining  non-­affiliated  leasehold  interest  in  Perry  Unit  1  on  May  23,  2016,  which  is  just  prior  to  the  end  of  the  lease   term.  In  November  2014,  NG  repurchased  55.3  MW  of  lessor  equity  interests  in  OE's  existing  sale  and  leaseback  of  Perry  Unit  1  for   approximately  $87  million.  OE  and  TE  continue  to  lease  these  MW  under  their  respective  sale  and  leaseback  arrangements  and  the   related  lease  debt  remains  outstanding.   Established  by  OE  in  1996,  PNBV  purchased  a  portion  of  the  lease  obligation  bonds  issued  on  behalf  of  lessors  in  OE’s  Perry  Unit  1   and  Beaver  Valley  Unit  2  sale  and  leaseback  transactions.  Similarly,  CEI  and  TE  established  Shippingport  in  1997  to  purchase  the   lease  obligation  bonds  issued  on  behalf  of  lessors  in  their  Bruce  Mansfield  Units  1,  2  and  3  sale  and  leaseback  transactions.  During   2013,  the  investments  held  at  Shippingport  were  liquidated.  The  PNBV  arrangements  effectively  reduce  lease  costs  related  to  those   transactions  (see  Note  8,  Variable  Interest  Entities).   As  of  December  31,  2015,  FirstEnergy's  leasehold  interest  was  3.75%  of  Perry  Unit  1,  93.83%  of  Bruce  Mansfield  Unit  1  and  2.60%   of  Beaver  Valley  Unit  2.   Operating  lease  expense  for  2015,  2014  and  2013,  is  summarized  as  follows:   (In  millions)   FirstEnergy   FES   2015   2014   2013   $   $   174   $   94   $   199   $   95   $   224   97   The  future  minimum  capital  lease  payments  as  of  December  31,  2015  are  as  follows:     Capital  leases   FirstEnergy   FES   2016   2017   2018   2019   2020   Years  thereafter   Total  minimum  lease  payments   Interest  portion   Present  value  of  net  minimum  lease  payments   Less  current  portion   Noncurrent  portion   $   $   (In  millions)   36   $   31   24   18   14   27   150   (18  )   132   32   100   $   6   6   2   —   —   —   14   (1  )   13   5   8   94   95                                   FirstEnergy's  future  minimum  consolidated  operating  lease  payments  as  of  December  31,  2015,  are  as  follows:   the  VIE  or  the  right  to  receive  benefits  from  the  entity  that  could  potentially  be  significant  to  the  VIE.  FirstEnergy  consolidates  a  VIE   FirstEnergy   when  it  is  determined  that  it  is  the  primary  beneficiary.   Operating  Leases   Lease  Payments   PNBV   Net   The   caption   "noncontrolling   interest"   within   the   consolidated   financial   statements   is   used   to   reflect   the   portion   of   a   VIE   that   (In  millions)   FirstEnergy  consolidates,  but  does  not  own.   2016   2017   2018   2019   2020   $   Years  thereafter   Total  minimum  lease  payments   $   197   $   122   135   116   91   1,438   2,099   $   13   $   3   —   —   —   —   16   $   184   119   135   116   91   1,438   2,083   FES'  future  minimum  operating  lease  payments  as  of  December  31,  2015,  are  as  follows:   Operating  Leases   Lease  Payments   (In  millions)   2016   2017   2018   2019   2020   Years  thereafter   Total  minimum  lease  payments   $   $   131   82   101   97   68   1,315   1,794   7.  INTANGIBLE  ASSETS   As  of  December  31,  2015,  intangible  assets  classified  in  Other  Deferred  Charges  on  FirstEnergy’s  Consolidated  Balance  Sheet,   include  the  following:   Intangible  Assets   Actual   Accumulated   Amortization   Net   2015   Amortization  Expense   Estimated   (In  millions)   NUG  contracts(1)   OVEC   Coal  contracts(2)(3)(4)   FES  customer  contracts   Gross   $   124   $   54   556   148   882   $   $   99   $   45   126   61   25   $   9   430   87   551   $   331   $   2016   2017   2018   2019   2020   Thereafter   74   35   —   —   109   5   $   5   $   2   2   32   38   17   16   62   $   55   $   38   $   5   $   2   17   13   37   $   5   $   2   6   1   14   $   5   $   2   17   14   5   $   2   116   17   140   $   (1)   NUG  contracts  are  subject  to  regulatory  accounting  and  their  amortization  does  not  impact  earnings.   (2)   A  gross  amount  of  $40  million  ($23  million,  net)  of  the  coal  contracts  is  related  to  FES.  The  2015  and  estimated  2016  to  2019  amortization   expense  for  FES  is  $5.7  million  annually.   (3)   A  gross  amount  of  $102  million  ($16  million,  net)  of  the  coal  contracts  was  recorded  with  a  regulatory  offset  and  the  amortization  does  not   impact  earnings.  Accordingly,  the  amortization  expense  for  these  coal  contracts  is  excluded  from  table  above.   (4)   Amortization  expense  in  2015,  includes  a  $67  million  impairment  of  a  coal  contract  intangible  asset  associated  with  the  termination  of  a  coal   supply  contract,  which  impacted  earnings.   FES  acquired  certain  customer  contract  rights  which  were  capitalized  as  intangible  assets.  These  rights  allow  FES  to  supply  electric   generation  to  customers,  and  the  recorded  value  is  being  amortized  ratably  over  the  term  of  the  related  contracts.   8.  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   96   97   In  order  to  evaluate  contracts  for  consolidation  treatment  and  entities  for  which  FirstEnergy  has  an  interest,  FirstEnergy  aggregates   variable  interests  into  categories  based  on  similar  risk  characteristics  and  significance.   Consolidated  VIEs   statements):   VIEs  in  which  FirstEnergy  is  the  primary  beneficiary  consist  of  the  following  (included  in  FirstEnergy’s  consolidated  financial   •     PNBV   -­   PNBV, a   business   trust   established   by   OE   in   1996,   issued   certain   beneficial   interests   and   notes   to   fund   the   acquisition  of  a  portion  of  the  bonds  issued  by  certain  owner  trusts  in  connection  with  the  sale  and  leaseback  in  1987  of  a   portion  of  OE's  interest  in  the  Perry  Plant  and  Beaver  Valley  Unit  2.  OE  used  debt  and  available  funds  to  purchase  the  notes   issued  by  PNBV.  The  beneficial  ownership  of  PNBV  includes  a  3%  interest  by  unaffiliated  third  parties.     •     Ohio  Securitization  -­  In  September  2012,  the  Ohio  Companies  created  separate,  wholly-­owned  limited  liability  companies   (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.  As  of  December  31,  2015  and  December  31,  2014,  $362  million  and  $386   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.  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  and  JCP&L  Transition  Funding  II  and  are  collateralized  by  each  company’s  equity  and  assets,  which   consist  primarily  of  bondable  transition  property.  As  of  December  31,  2015  and  December  31,  2014,  $128  million  and  $168   million  of  the  transition  bonds  were  outstanding,  respectively.     •     MP  and  PE  Environmental  Funding  Companies  -­  The  entities  issued  bonds  of  which  the  proceeds  were  used  to  construct   environmental  control  facilities.  The  special  purpose  limited  liability  companies  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  special  purpose  limited   liability  companies,  have  no  recourse  to  any  assets  or  revenues  of  the  special  purpose  limited  liability  companies.  As  of   December  31,   2015   and   December  31,   2014,   $429   million   and   $450   million   of   the   environmental   control   bonds   were   outstanding,  respectively.     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.  See  Note  1,  Organization,   Basis   of   Presentation   and   Significant   Accounting   Policies   -­   Investments,   for   additional   information   regarding   FEV's   investment  in  Global  Holding.   As  discussed  in  Note  15,  Commitments,  Guarantees  and  Contingencies,  FE  is  the  guarantor  under  Global  Holding's  $300   million  term  loan  facility.  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  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.                                 FirstEnergy's  future  minimum  consolidated  operating  lease  payments  as  of  December  31,  2015,  are  as  follows:   Operating  Leases   Lease  Payments   PNBV   Net   FirstEnergy   (In  millions)   2016   2017   2018   2019   2020   $   197   $   122   135   116   91   1,438   2,099   $   184   119   135   116   91   1,438   2,083   Years  thereafter   Total  minimum  lease  payments   $   FES'  future  minimum  operating  lease  payments  as  of  December  31,  2015,  are  as  follows:   Operating  Leases   Lease  Payments   (In  millions)   2016   2017   2018   2019   2020   Years  thereafter   Total  minimum  lease  payments   $   $   13   $   3   —   —   —   —   16   $   131   82   101   97   68   1,315   1,794   7.  INTANGIBLE  ASSETS   include  the  following:   As  of  December  31,  2015,  intangible  assets  classified  in  Other  Deferred  Charges  on  FirstEnergy’s  Consolidated  Balance  Sheet,   Intangible  Assets   Actual   Amortization  Expense   Estimated   (In  millions)   NUG  contracts(1)   OVEC   Coal  contracts(2)(3)(4)   FES  customer  contracts   Accumulated   Amortization   Net   Gross   $   124   $   2015   2016   2017   2018   2019   2020   Thereafter   54   556   148   25   $   99   $   5   $   5   $   5   $   5   $   5   $   5   $   9   430   87   45   126   61   2   116   17   2   38   17   2   32   16   2   17   14   2   17   13   2   6   1   $   882   $   551   $   331   $   140   $   62   $   55   $   38   $   37   $   14   $   74   35   —   —   109   (1)   NUG  contracts  are  subject  to  regulatory  accounting  and  their  amortization  does  not  impact  earnings.   (2)   A  gross  amount  of  $40  million  ($23  million,  net)  of  the  coal  contracts  is  related  to  FES.  The  2015  and  estimated  2016  to  2019  amortization   expense  for  FES  is  $5.7  million  annually.   (3)   A  gross  amount  of  $102  million  ($16  million,  net)  of  the  coal  contracts  was  recorded  with  a  regulatory  offset  and  the  amortization  does  not   impact  earnings.  Accordingly,  the  amortization  expense  for  these  coal  contracts  is  excluded  from  table  above.   (4)   Amortization  expense  in  2015,  includes  a  $67  million  impairment  of  a  coal  contract  intangible  asset  associated  with  the  termination  of  a  coal   supply  contract,  which  impacted  earnings.   FES  acquired  certain  customer  contract  rights  which  were  capitalized  as  intangible  assets.  These  rights  allow  FES  to  supply  electric   generation  to  customers,  and  the  recorded  value  is  being  amortized  ratably  over  the  term  of  the  related  contracts.   8.  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.   The   caption   "noncontrolling   interest"   within   the   consolidated   financial   statements   is   used   to   reflect   the   portion   of   a   VIE   that   FirstEnergy  consolidates,  but  does  not  own.   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):   •     PNBV   -­   PNBV, a   business   trust   established   by   OE   in   1996,   issued   certain   beneficial   interests   and   notes   to   fund   the   acquisition  of  a  portion  of  the  bonds  issued  by  certain  owner  trusts  in  connection  with  the  sale  and  leaseback  in  1987  of  a   portion  of  OE's  interest  in  the  Perry  Plant  and  Beaver  Valley  Unit  2.  OE  used  debt  and  available  funds  to  purchase  the  notes   issued  by  PNBV.  The  beneficial  ownership  of  PNBV  includes  a  3%  interest  by  unaffiliated  third  parties.     •     Ohio  Securitization  -­  In  September  2012,  the  Ohio  Companies  created  separate,  wholly-­owned  limited  liability  companies   (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.  As  of  December  31,  2015  and  December  31,  2014,  $362  million  and  $386   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.  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  and  JCP&L  Transition  Funding  II  and  are  collateralized  by  each  company’s  equity  and  assets,  which   consist  primarily  of  bondable  transition  property.  As  of  December  31,  2015  and  December  31,  2014,  $128  million  and  $168   million  of  the  transition  bonds  were  outstanding,  respectively.     •     MP  and  PE  Environmental  Funding  Companies  -­  The  entities  issued  bonds  of  which  the  proceeds  were  used  to  construct   environmental  control  facilities.  The  special  purpose  limited  liability  companies  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  special  purpose  limited   liability  companies,  have  no  recourse  to  any  assets  or  revenues  of  the  special  purpose  limited  liability  companies.  As  of   December  31,   2015   and   December  31,   2014,   $429   million   and   $450   million   of   the   environmental   control   bonds   were   outstanding,  respectively.     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.  See  Note  1,  Organization,   Basis   of   Presentation   and   Significant   Accounting   Policies   -­   Investments,   for   additional   information   regarding   FEV's   investment  in  Global  Holding.   As  discussed  in  Note  15,  Commitments,  Guarantees  and  Contingencies,  FE  is  the  guarantor  under  Global  Holding's  $300   million  term  loan  facility.  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  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.   96   97                                 •     Power  Purchase  Agreements  -­  FirstEnergy  evaluated  its  power  purchase  agreements  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.   9.  FAIR  VALUE  MEASUREMENTS   RECURRING  FAIR  VALUE  MEASUREMENTS   FirstEnergy  maintains  15  long-­term  power  purchase  agreements  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  in  the  entities  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  contracts  that  may  contain  a   variable  interest  were  $116  million  and  $185  million,  respectively,  during  the  years  ended  December  31,  2015  and  2014.     •     Sale  and  Leaseback  Transactions  -­  FES  and  certain  of  the  Ohio  Companies  have  obligations  that  are  not  included  on   their  Consolidated  Balance  Sheets  related  to  the  Perry  Unit  1,  Beaver  Valley  Unit  2,  and  2007  Bruce  Mansfield  Unit  1  sale   and   leaseback   arrangements,   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.    As  of  December  31,  2015,  FirstEnergy's  leasehold  interest  was  3.75%  of  Perry  Unit  1,  93.83%  of  Bruce   Mansfield  Unit  1  and  2.60%  of  Beaver  Valley  Unit  2.     On  June  24,  2014,  OE  exercised  its  irrevocable  right  to  repurchase  from  the  remaining  owner  participants  the  lessors'   interests  in  Beaver  Valley  Unit  2  at  the  end  of  the  lease  term  (June  1,  2017),  which  right  to  repurchase  was  assigned  to  NG.   Additionally,  on  June  24,  2014,  NG  entered  into  a  purchase  agreement  with  an  owner  participant  to  purchase  its  lessor   equity  interests  of  the  remaining  non-­affiliated  leasehold  interest  in  Perry  Unit  1  on  May  23,  2016,  which  is  just  prior  to  the   end  of  the  lease  term.  Upon  the  completion  of  these  transactions,  NG  will  have  obtained  all  of  the  lessor  equity  interests  at   Perry  Unit  1  and  Beaver  Valley  Unit  2.   FES  and  other  FE  subsidiaries  are  exposed  to  losses  under  their  applicable  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  each  company’s  net  exposure  to  loss   based  upon  the  casualty  value  provisions  as  of  December  31,  2015:   Maximum   Exposure   Discounted  Lease   Payments,  net   Net   Exposure   (In  millions)   FirstEnergy   FES   $   $   1,225   $   1,155   $   950   $   933   $   275   222   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  processes  for  FTRs  and  NUGs  are  as  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  RTO  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  RTO  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  10,  Derivative  Instruments,  for  additional  information  regarding  FirstEnergy's  FTRs.   NUG  contracts  represent  purchase  power  agreements  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  MWHs.  Pricing  for  the  NUG  contracts  is  a  combination  of  market   prices  for  the  current  year  and  next  three  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  MWHs  reflects  data  provided  by  contractual  arrangements  and  historical   trends.  The  model  calculates  the  fair  value  by  multiplying  the  prices  by  the  generation  MWHs.  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,  2015,  from  those  used  as  of  December  31,  2014.  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.   98   99                                   •     Power  Purchase  Agreements  -­  FirstEnergy  evaluated  its  power  purchase  agreements  and  determined  that  certain  NUG   9.  FAIR  VALUE  MEASUREMENTS   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  15  long-­term  power  purchase  agreements  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  in  the  entities  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  contracts  that  may  contain  a   variable  interest  were  $116  million  and  $185  million,  respectively,  during  the  years  ended  December  31,  2015  and  2014.     •     Sale  and  Leaseback  Transactions  -­  FES  and  certain  of  the  Ohio  Companies  have  obligations  that  are  not  included  on   their  Consolidated  Balance  Sheets  related  to  the  Perry  Unit  1,  Beaver  Valley  Unit  2,  and  2007  Bruce  Mansfield  Unit  1  sale   and   leaseback   arrangements,   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.    As  of  December  31,  2015,  FirstEnergy's  leasehold  interest  was  3.75%  of  Perry  Unit  1,  93.83%  of  Bruce   Mansfield  Unit  1  and  2.60%  of  Beaver  Valley  Unit  2.     On  June  24,  2014,  OE  exercised  its  irrevocable  right  to  repurchase  from  the  remaining  owner  participants  the  lessors'   interests  in  Beaver  Valley  Unit  2  at  the  end  of  the  lease  term  (June  1,  2017),  which  right  to  repurchase  was  assigned  to  NG.   Additionally,  on  June  24,  2014,  NG  entered  into  a  purchase  agreement  with  an  owner  participant  to  purchase  its  lessor   equity  interests  of  the  remaining  non-­affiliated  leasehold  interest  in  Perry  Unit  1  on  May  23,  2016,  which  is  just  prior  to  the   end  of  the  lease  term.  Upon  the  completion  of  these  transactions,  NG  will  have  obtained  all  of  the  lessor  equity  interests  at   Perry  Unit  1  and  Beaver  Valley  Unit  2.   FES  and  other  FE  subsidiaries  are  exposed  to  losses  under  their  applicable  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  each  company’s  net  exposure  to  loss   based  upon  the  casualty  value  provisions  as  of  December  31,  2015:   Maximum   Exposure   Discounted  Lease   Payments,  net   Net   Exposure   (In  millions)   FirstEnergy   FES   $   $   1,225   $   1,155   $   950   $   933   $   275   222   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  processes  for  FTRs  and  NUGs  are  as  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  RTO  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  RTO  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  10,  Derivative  Instruments,  for  additional  information  regarding  FirstEnergy's  FTRs.   NUG  contracts  represent  purchase  power  agreements  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  MWHs.  Pricing  for  the  NUG  contracts  is  a  combination  of  market   prices  for  the  current  year  and  next  three  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  MWHs  reflects  data  provided  by  contractual  arrangements  and  historical   trends.  The  model  calculates  the  fair  value  by  multiplying  the  prices  by  the  generation  MWHs.  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,  2015,  from  those  used  as  of  December  31,  2014.  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.   98   99                                   Transfers  between  levels  are  recognized  at  the  end  of  the  reporting  period.  There  were  no  transfers  between  levels  during  the  years   ended  December  31,  2015  and  2014.  The  following  tables  set  forth  the  recurring  assets  and  liabilities  that  are  accounted  for  at  fair   value  by  level  within  the  fair  value  hierarchy:   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,  2015  and  December  31,  2014:   FirstEnergy   Recurring  Fair  Value  Measurements   Level  1   December  31,  2015   Level  3   Level  2   Total   Level  1   (In  millions)   December  31,  2014   Level  3   Level  2   Total   Assets   Corporate  debt  securities   $   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   Derivative  liabilities  -­  commodity  contracts   Derivative  liabilities  -­  FTRs   Derivative  liabilities  -­  NUG  contracts(1)   Total  liabilities   Net  assets  (liabilities)(4)   $   $   $   $   —   $   1,245   $   4   —   —   576   —   —   —   105   685   $   2,182   $   224   —   —   —   75   180   246   212   —   $   1,245   $   228   —   8   8   1   1   576   —   75   —   180   —   246   —   —   317   9   $   2,876   $   —   $   1,221   $   171   1   —   —   —   —   —   592   76   —   182   —   237   —   256   55   648   $   2,143   $   —   $   1,221   172   —   39   39   2   2   592   —   76   —   182   —   237   —   —   311   41   $   2,832   (9  )   $   —   —   (9  )   $   (122  )   $   —   —   (122  )   $   —   $   (13  )   (137  )   (150  )   $   (131  )   $   (13  )   (137  )   (281  )   $   (26  )   $   —   —   (26  )   $   (141  )   $   —   —   (141  )   $   —   $   (14  )   (153  )   (167  )   $   (167  )   (14  )   (153  )   (334  )   676   $   2,060   $   (141  )   $   2,595   $   622   $   2,002   $   (126  )   $   2,498   hierarchy  for  the  period  ended  December  31,  2015:   The  following  table  provides  quantitative  information  for  FTRs  and  NUG  contracts  that  are  classified  as  Level  3  in  the  fair  value   (1)   NUG  contracts  are  subject  to  regulatory  accounting  treatment  and  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  cash  and  short-­term  cash  investments.   (4)   Excludes  $7  million  and  $40  million  as  of  December  31,  2015  and  December  31,  2014,  respectively,  of  receivables,  payables,  taxes  and  accrued   income  associated  with  financial  instruments  reflected  within  the  fair  value  table.   100   101   NUG  Contracts(1)   FTRs   Derivative   Assets   Derivative   Liabilities   Net   Derivative   Assets   Derivative   Liabilities   Net   (In  millions)   January  1,  2014   Balance   Unrealized  gain  (loss)   Purchases   Settlements   December  31,  2014   Balance   $   Unrealized  gain  (loss)   Purchases   Settlements   December  31,  2015   Balance   $   20   $   (222  )   $   (202  )   $   4   $   (12  )   $   2   —   (20  )   2   2   —   (3  )   (2  )   —   71   (49  )   —   65   —   —   51   (47  )   —   62   47   26   (38  )   (5  )   22   (48  )   $   (153  )   $   (151  )   $   39   $   (14  )   $   (8  )   46   10   (23  )   25   (12  )   11   (29  )   (1  )   (16  )   15   (7  )   (11  )   19   $   1   $   (137  )   $   (136  )   $   8   $   (13  )   $   (5  )   (1)   NUG  contracts  are  subject  to  regulatory  accounting  treatment  and  do  not  impact  earnings.   Level  3  Quantitative  Information   Fair  Value,  Net   (In  millions)   Valuation   Technique   Significant  Input   Range   FTRs   NUG  Contracts   $   $   (5  )   Model   RTO  auction  clearing  prices   ($3.90)  to  $6.90   (136  )   Model   Generation   Regional  electricity  prices   400  to  3,871,000   $38.10  to  $45.60   Weighted   Average   Units   $1.00   839,000   $40.20   Dollars/MWH   MWH   Dollars/MWH   FES   Recurring  Fair  Value  Measurements   December  31,  2015   December  31,  2014   Assets   Corporate  debt  securities   $   —   $   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   Liabilities   Level  1   Level  2   Level  3   Total   Level  1   Level  2   Level  3   Total   678   $   224   —   —   59   23   4   184   (In  millions)   —   $   —   5   —   —   —   —   —   678   $   228   5   378   59   23   4   184   —   $   1   —   360   —   —   —   —   655   $   171   —   —   57   46   4   199   —   $   —   27   —   —   —   —   —   655   172   27   360   57   46   4   199   4   —   378   —   —   —   —   $   382   $   1,172   $   5   $   1,559   $   361   $   1,132   $   27   $   1,520   Derivative  liabilities  -­  commodity  contracts   $   Derivative  liabilities  -­  FTRs   Total  liabilities   (9  )   $   (122  )   $   —   —   —   $   (11  )   (131  )   $   (26  )   $   (141  )   $   (11  )   —   —   —   $   (13  )   (167  )   (13  )   (9  )   $   (122  )   $   (11  )   $   (142  )   $   (26  )   $   (141  )   $   (13  )   $   (180  )   Net  assets  (liabilities)(3)   373   $   1,050   $   (6  )   $   1,417   $   335   $   991   $   14   $   1,340   $   $                         Recurring  Fair  Value  Measurements   December  31,  2015   December  31,  2014   Level  1   Level  2   Level  3   Total   Level  1   Level  2   Level  3   Total   $   —   $   1,245   $   —   $   1,245   $   —   $   1,221   $   —   $   1,221   576   4   —   —   —   —   —   105   224   —   —   —   75   180   246   212   (In  millions)   228   8   1   576   75   180   246   317   1   —   —   592   —   —   —   55   —   8   1   —   —   —   —   —   171   —   —   —   76   182   237   256   —   39   2   —   —   —   —   —   172   39   2   592   76   182   237   311   $   685   $   2,182   $   9   $   2,876   $   648   $   2,143   $   41   $   2,832   value  by  level  within  the  fair  value  hierarchy:   FirstEnergy   Assets   Corporate  debt  securities   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   Derivative  liabilities  -­  FTRs   Derivative  liabilities  -­  NUG  contracts(1)   Derivative  liabilities  -­  commodity  contracts   $   (9  )   $   (122  )   $   (131  )   $   (26  )   $   (141  )   $   —   —   —   —   —   $   (13  )   (137  )   (13  )   (137  )   —   —   —   —   —   $   (14  )   (153  )   (167  )   (14  )   (153  )   (334  )   Total  liabilities   (9  )   $   (122  )   $   (150  )   $   (281  )   $   (26  )   $   (141  )   $   (167  )   $   Net  assets  (liabilities)(4)   676   $   2,060   $   (141  )   $   2,595   $   622   $   2,002   $   (126  )   $   2,498   $   $   (1)   NUG  contracts  are  subject  to  regulatory  accounting  treatment  and  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  cash  and  short-­term  cash  investments.   (4)   Excludes  $7  million  and  $40  million  as  of  December  31,  2015  and  December  31,  2014,  respectively,  of  receivables,  payables,  taxes  and  accrued   income  associated  with  financial  instruments  reflected  within  the  fair  value  table.   Transfers  between  levels  are  recognized  at  the  end  of  the  reporting  period.  There  were  no  transfers  between  levels  during  the  years   Rollforward  of  Level  3  Measurements   ended  December  31,  2015  and  2014.  The  following  tables  set  forth  the  recurring  assets  and  liabilities  that  are  accounted  for  at  fair   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,  2015  and  December  31,  2014:   NUG  Contracts(1)   FTRs   Derivative   Assets   Derivative   Liabilities   Net   Derivative   Assets   Derivative   Liabilities   Net   (In  millions)   January  1,  2014   Balance   $   Unrealized  gain  (loss)   Purchases   Settlements   December  31,  2014   Balance   $   Unrealized  gain  (loss)   Purchases   Settlements   December  31,  2015   Balance   $   20   2   —   (20  )   $   2   2   —   (3  )   (222  )   $   (2  )   —   71   (153  )   $   (49  )   —   65   (202  )   $   —   —   51   (151  )   $   (47  )   —   62   $   $   4   47   26   (38  )   39   (5  )   22   (48  )   (12  )   $   (1  )   (16  )   15   (14  )   $   (7  )   (11  )   19   (8  )   46   10   (23  )   25   (12  )   11   (29  )   $   1   $   (137  )   $   (136  )   $   8   $   (13  )   $   (5  )   (1)   NUG  contracts  are  subject  to  regulatory  accounting  treatment  and  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,  2015:   Fair  Value,  Net   (In  millions)   Valuation   Technique   Significant  Input   Range   Weighted   Average   FTRs   NUG  Contracts   $   $   (5  )   Model   (136  )   Model   RTO  auction  clearing  prices   Generation   Regional  electricity  prices   ($3.90)  to  $6.90   400  to  3,871,000   $38.10  to  $45.60   $1.00   839,000   $40.20   Units   Dollars/MWH   MWH   Dollars/MWH   FES   Recurring  Fair  Value  Measurements   Level  1   December  31,  2015   Level  3   Level  2   Total   Level  1   December  31,  2014   Level  3   Level  2   Total   Assets   Corporate  debt  securities   $   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   Liabilities   $   678   $   224   —   —   59   23   4   184   —   $   4   —   378   —   —   —   —   382   $   1,172   $   (In  millions)   —   $   678   $   —   228   5   5   —   378   —   59   —   23   —   4   184   —   5   $   1,559   $   —   $   655   $   1   171   —   —   360   —   —   57   —   46   —   4   199   —   361   $   1,132   $   —   $   655   —   172   27   27   —   360   —   57   —   46   —   4   199   —   27   $   1,520   Derivative  liabilities  -­  commodity  contracts   $   Derivative  liabilities  -­  FTRs   Total  liabilities   Net  assets  (liabilities)(3)   $   $   (9  )   $   —   (9  )   $   (122  )   $   —   (122  )   $   —   $   (11  )   (11  )   $   (131  )   $   (11  )   (142  )   $   (26  )   $   —   (26  )   $   (141  )   $   —   (141  )   $   —   $   (13  )   (13  )   $   (167  )   (13  )   (180  )   373   $   1,050   $   (6  )   $   1,417   $   335   $   991   $   14   $   1,340   100   101                         Securities  REIT  index.   income  associated  with  financial  instruments  reflected  within  the  fair  value  table.   (1)   NDT  funds  hold  equity  portfolios  whose  performance  is  benchmarked  against  the  Alerian  MLP  Index  or  the  Wells  Fargo  Hybrid  and  Preferred   (2)   Primarily  consists  of  short-­term  cash  investments.   (3)   Excludes  $1  million  and  $44  million  as  of  December  31,  2015  and  December  31,  2014,  respectively,  of  receivables,  payables,  taxes  and  accrued   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,  2015  and  December  31,  2014:   Derivative  Asset   Derivative  Liability   Net  Asset/(Liability)   (In  millions)   January  1,  2014  Balance   Unrealized  gain  (loss)   Purchases   Settlements   $   December  31,  2014  Balance   $   Unrealized  gain  (loss)   Purchases   Settlements   December  31,  2015  Balance   $   3   $   34   15   (25  )   27   $   2   9   (33  )   5   $   (11  )   $   (1  )   (16  )   15   (13  )   $   (5  )   (10  )   17   (11  )   $   (8  )   33   (1  )   (10  )   14   (3  )   (1  )   (16  )   (6  )   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,  2015:   December  31,  2015   Sale   Proceeds   Realized   Gains   Realized   Losses   OTTI   Interest  and   Dividend  Income   Fair  Value,  Net   (In  millions)   Valuation   Technique   Significant  Input   Range   Weighted   Average   Units   FTRs   $   (6  )   Model   RTO  auction  clearing  prices   ($3.90)  to  $5.70   $0.70   Dollars/MWH   INVESTMENTS   All  temporary  cash  investments  purchased  with  an  initial  maturity  of  three  months  or  less  are  reported  as  cash  equivalents  on  the   Consolidated  Balance  Sheets  at  cost,  which  approximates  their  fair  market  value.  Investments  other  than  cash  and  cash  equivalents   include  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  first  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  in  net  regulatory  assets.     The  investment  policy  for  the  NDT  funds  restricts  or  limits  the  trusts'  ability  to  hold  certain  types  of  assets  including  private  or  direct   placements,   warrants,   securities   of   FirstEnergy,   investments   in   companies   owning   nuclear   power   plants,   financial   derivatives,   securities  convertible  into  common  stock  and  securities  of  the  trust  funds'  custodian  or  managers  and  their  parents  or  subsidiaries.   102   103   AFS  Securities   FirstEnergy  holds  debt  and  equity  securities  within  its  NDT,  nuclear  fuel  disposal  and  NUG  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,  nuclear  fuel  disposal  and  NUG  trusts  as  of  December  31,  2015  and  December  31,  2014:   December  31,  2015(1)   December  31,  2014(2)   Cost   Basis   Unrealized   Gains   Fair  Value   Cost   Basis   Unrealized   Gains   Fair  Value   (In  millions)   1,778   $   801   16   $   9   1,794   $   810   1,724   $   788   27   $   13   1,751   801   Debt  securities   FirstEnergy   FES   Equity  securities   FirstEnergy   FES   $   $   $   $   $   542   $   354   34   $   24   576   $   378   533   $   329   58   $   31   591   360   (1)   Excludes  short-­term  cash  investments:  FE  Consolidated  -­  $157  million;;  FES  -­  $139  million.   (2)   Excludes  short-­term  cash  investments:  FE  Consolidated  -­  $241  million;;  FES  -­  $204  million.   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,  2015,  2014  and  2013  were  as  follows:   December  31,  2014   Sale   Proceeds   Realized   Gains   Realized   Losses   OTTI   Interest  and   Dividend  Income   (In  millions)   1,534   $   733   209   $   158   (191  )   $   (134  )   (102  )   $   (90  )   (In  millions)   2,133   $   1,163   146   $   113   (75  )   $   (54  )   (37  )   $   (33  )   (In  millions)   2,047   $   940   92   $   70   (46  )   $   (21  )   (90  )   $   (79  )   101   57   96   56   101   60   December  31,  2013   Sale   Proceeds   Realized   Gains   Realized   Losses   OTTI   Interest  and   Dividend  Income   FirstEnergy   FES   FirstEnergy   FES   FirstEnergy   FES   Held-­To-­Maturity  Securities   The  following  table  provides  the  amortized  cost  basis,  unrealized  gains  (there  were  no  unrealized  losses)  and  approximate  fair  values   of  investments  in  held-­to-­maturity  securities  as  of  December  31,  2015  and  December  31,  2014:   December  31,  2015   December  31,  2014   Cost   Basis   Unrealized   Gains   Fair  Value   Cost   Basis   Unrealized   Gains   Fair  Value   (In  millions)   Debt  Securities   FirstEnergy   $   6   $   2   $   8   $   13   $   4   $   17                                                         (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  $1  million  and  $44  million  as  of  December  31,  2015  and  December  31,  2014,  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,  2015  and  December  31,  2014:   January  1,  2014  Balance   $   Unrealized  gain  (loss)   December  31,  2014  Balance   $   Unrealized  gain  (loss)   Purchases   Settlements   Purchases   Settlements   December  31,  2015  Balance   $   Level  3  Quantitative  Information   Derivative  Asset   Derivative  Liability   Net  Asset/(Liability)   (In  millions)   3   $   34   15   (25  )   27   $   2   9   (33  )   5   $   (11  )   $   (1  )   (16  )   15   (13  )   $   (5  )   (10  )   17   (11  )   $   (8  )   33   (1  )   (10  )   14   (3  )   (1  )   (16  )   (6  )   AFS  Securities   FirstEnergy  holds  debt  and  equity  securities  within  its  NDT,  nuclear  fuel  disposal  and  NUG  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,  nuclear  fuel  disposal  and  NUG  trusts  as  of  December  31,  2015  and  December  31,  2014:   December  31,  2015(1)   December  31,  2014(2)   Cost   Basis   Unrealized   Gains   Fair  Value   Cost   Basis   Unrealized   Gains   Fair  Value   (In  millions)   1,778   $   801   16   $   9   1,794   $   810   1,724   $   788   27   $   13   1,751   801   542   $   354   34   $   24   576   $   378   533   $   329   58   $   31   591   360   Debt  securities   FirstEnergy   $   FES   Equity  securities   $   FirstEnergy   FES   (1)   Excludes  short-­term  cash  investments:  FE  Consolidated  -­  $157  million;;  FES  -­  $139  million.   (2)   Excludes  short-­term  cash  investments:  FE  Consolidated  -­  $241  million;;  FES  -­  $204  million.   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,  2015,  2014  and  2013  were  as  follows:   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,  2015:   December  31,  2015   Sale   Proceeds   Realized   Gains   Realized   Losses   OTTI   Interest  and   Dividend  Income   FirstEnergy   FES   December  31,  2014   FirstEnergy   FES   December  31,  2013   FirstEnergy   FES   $   $   $   (In  millions)   1,534   $   733   209   $   158   (191  )   $   (134  )   (102  )   $   (90  )   101   57   Sale   Proceeds   Realized   Gains   Realized   Losses   OTTI   Interest  and   Dividend  Income   (In  millions)   2,133   $   1,163   146   $   113   (75  )   $   (54  )   (37  )   $   (33  )   96   56   Sale   Proceeds   Realized   Gains   Realized   Losses   OTTI   Interest  and   Dividend  Income   (In  millions)   2,047   $   940   92   $   70   (46  )   $   (21  )   (90  )   $   (79  )   101   60   required  to  sell  the  securities  before  recovery  of  its  cost  basis  and  the  likelihood  of  recovery  of  the  securities'  entire  amortized  cost   Held-­To-­Maturity  Securities   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.     The  following  table  provides  the  amortized  cost  basis,  unrealized  gains  (there  were  no  unrealized  losses)  and  approximate  fair  values   of  investments  in  held-­to-­maturity  securities  as  of  December  31,  2015  and  December  31,  2014:   December  31,  2015   December  31,  2014   Cost   Basis   Unrealized   Gains   Fair  Value   Cost   Basis   Unrealized   Gains   Fair  Value   (In  millions)   Debt  Securities   FirstEnergy   $   6   $   2   $   8   $   13   $   4   $   17   102   103   Fair  Value,  Net   (In  millions)   Valuation   Technique   Significant  Input   Range   Weighted   Average   Units   FTRs   $   (6  )   Model   RTO  auction  clearing  prices   ($3.90)  to  $5.70   $0.70   Dollars/MWH   INVESTMENTS   All  temporary  cash  investments  purchased  with  an  initial  maturity  of  three  months  or  less  are  reported  as  cash  equivalents  on  the   Consolidated  Balance  Sheets  at  cost,  which  approximates  their  fair  market  value.  Investments  other  than  cash  and  cash  equivalents   include  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  first  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   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  in  net  regulatory  assets.     The  investment  policy  for  the  NDT  funds  restricts  or  limits  the  trusts'  ability  to  hold  certain  types  of  assets  including  private  or  direct   placements,   warrants,   securities   of   FirstEnergy,   investments   in   companies   owning   nuclear   power   plants,   financial   derivatives,   securities  convertible  into  common  stock  and  securities  of  the  trust  funds'  custodian  or  managers  and  their  parents  or  subsidiaries.                                                         The  held-­to-­maturity  debt  securities  contractually  mature  by  June  30,  2017.  Investments  in  employee  benefit  trusts  and  equity  method   investments  totaling  $255  million  as  of  December  31,  2015  and  $626  million  as  of  December  31,  2014,  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  and  other  long-­term  obligations,  excluding  capital  lease  obligations  and  net  unamortized   premiums  and  discounts:   December  31,  2015   December  31,  2014   Carrying   Value   Fair   Value   Carrying   Value   Fair   Value   (In  millions)   FirstEnergy   FES   $   20,244   $   3,027   21,519   $   3,121   19,828   $   3,097   21,733   3,241   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  and  its  subsidiaries.  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,  2015  and  December  31,  2014.    10.  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.   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   As  of  December  31,  2015  and  2014,  no  interest  rate  swaps  were  outstanding.     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   $11  million  and  $8  million  as  of  December  31,  2015  and  December  31,  2014,  respectively.  Since  the  forecasted  transactions  remain   probable  of  occurring,  these  amounts  will  be  amortized  into  earnings  over  the  life  of  the  hedging  instruments.  Approximately  $1  million   of  net  unamortized  losses  is  expected  to  be  amortized  to  income  during  the  next  twelve  months.   104   105   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   $42   million   and   $50   million   as   of   December  31,   2015   and   December  31,  2014,  respectively.  Based  on  current  estimates,  approximately  $9  million  of  these  unamortized  losses  is  expected  to   be  amortized  to  interest  expense  during  the  next  twelve  months.     Refer  to  Note  2,  Accumulated  Other  Comprehensive  Income,  for  reclassifications  from  AOCI  during  the  years  ended  December  31,   As  of  December  31,  2015  and  December  31,  2014,  no  commodity  or  interest  rate  derivatives  were  designated  as  cash  flow  hedges.   2015  and  2014.   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,  2015  and  December  31,  2014,  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  $20  million   and  $32  million  as  of  December  31,  2015  and  December  31,  2014,  respectively.  During  the  next  twelve  months,  approximately  $10   million  of  unamortized  gains  is  expected  to  be  amortized  to  interest  expense.  Amortization  of  unamortized  gains  included  in  long-­term   debt  totaled  approximately  $12  million  during  the  years  ended  December  31,  2015  and  2014.     As  of  December  31,  2015  and  December  31,  2014,  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,  2015,  FirstEnergy's  net  asset  position  under  commodity  derivative  contracts  was  $97  million,  which  related  to   FES  positions.  Under  these  commodity  derivative  contracts,  FES  posted  $26  million  of  collateral.  Certain  commodity  derivative   contracts  include  credit  risk  related  contingent  features  that  would  require  FES  to  post  $3  million  of  additional  collateral  if  the  credit   rating  for  its  debt  were  to  fall  below  investment  grade.   Based  on  derivative  contracts  held  as  of  December  31,  2015,  an  increase  in  commodity  prices  of  10%  would  decrease  net  income  by   approximately  $30  million  during  the  next  twelve  months.   Interest  Rate  Swaps   NUGs   FTRs   As  of  December  31,  2015,  FirstEnergy's  net  liability  position  under  NUG  contracts  was  $136  million  representing  contracts  held  at   JCP&L,  ME  and  PN.  NUG  contracts  represent  purchased  power  agreements  with  third-­party  non-­utility  generators  that  are  transacted   to  satisfy  certain  obligations  under  PURPA.  Changes  in  the  fair  value  of  NUG  contracts  are  subject  to  regulatory  accounting  treatment   and  do  not  impact  earnings.   As  of  December  31,  2015,  FirstEnergy's  and  FES'  net  liability  position  under  FTRs  was  $5  million  and  $6  million,  respectively  and   FES  posted  $6  million  of  collateral.  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   an   RTO   that   have   load   serving   obligations  and  through  the  direct  allocation  of  FTRs  from  PJM.  PJM  has  a  rule  that  allows  directly  allocated  FTRs  to  be  granted  to   LSEs  in  zones  that  have  newly  entered  PJM.  For  the  first  two  planning  years,  PJM  permits  the  LSEs  to  request  a  direct  allocation  of   FTRs  in  these  new  zones  at  no  cost  as  opposed  to  receiving  ARRs.  The  directly  allocated  FTRs  differ  from  traditional  FTRs  in  that  the   ownership  of  all  or  part  of  the  FTRs  may  shift  to  another  LSE  if  customers  choose  to  shop  with  the  other  LSE.                                                                         The  held-­to-­maturity  debt  securities  contractually  mature  by  June  30,  2017.  Investments  in  employee  benefit  trusts  and  equity  method   investments  totaling  $255  million  as  of  December  31,  2015  and  $626  million  as  of  December  31,  2014,  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  and  other  long-­term  obligations,  excluding  capital  lease  obligations  and  net  unamortized   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   $42   million   and   $50   million   as   of   December  31,   2015   and   December  31,  2014,  respectively.  Based  on  current  estimates,  approximately  $9  million  of  these  unamortized  losses  is  expected  to   be  amortized  to  interest  expense  during  the  next  twelve  months.     Refer  to  Note  2,  Accumulated  Other  Comprehensive  Income,  for  reclassifications  from  AOCI  during  the  years  ended  December  31,   2015  and  2014.   premiums  and  discounts:   As  of  December  31,  2015  and  December  31,  2014,  no  commodity  or  interest  rate  derivatives  were  designated  as  cash  flow  hedges.   December  31,  2015   December  31,  2014   Carrying   Value   Fair   Value   Carrying   Value   Fair   Value   (In  millions)   FirstEnergy   FES   $   20,244   $   3,027   21,519   $   3,121   19,828   $   3,097   21,733   3,241   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  and  its  subsidiaries.  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,  2015  and  December  31,  2014.    10.  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.   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.   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,  2015  and  December  31,  2014,  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  $20  million   and  $32  million  as  of  December  31,  2015  and  December  31,  2014,  respectively.  During  the  next  twelve  months,  approximately  $10   million  of  unamortized  gains  is  expected  to  be  amortized  to  interest  expense.  Amortization  of  unamortized  gains  included  in  long-­term   debt  totaled  approximately  $12  million  during  the  years  ended  December  31,  2015  and  2014.     As  of  December  31,  2015  and  December  31,  2014,  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,  2015,  FirstEnergy's  net  asset  position  under  commodity  derivative  contracts  was  $97  million,  which  related  to   FES  positions.  Under  these  commodity  derivative  contracts,  FES  posted  $26  million  of  collateral.  Certain  commodity  derivative   contracts  include  credit  risk  related  contingent  features  that  would  require  FES  to  post  $3  million  of  additional  collateral  if  the  credit   rating  for  its  debt  were  to  fall  below  investment  grade.   Based  on  derivative  contracts  held  as  of  December  31,  2015,  an  increase  in  commodity  prices  of  10%  would  decrease  net  income  by   approximately  $30  million  during  the  next  twelve  months.   •     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   Interest  Rate  Swaps   •     Changes   in   the   fair   value   of   derivative   instruments   that   are   not   designated   in   a   hedging   relationship   are   recorded   in   As  of  December  31,  2015  and  2014,  no  interest  rate  swaps  were  outstanding.     hedged  is  amortized  into  earnings.   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   $11  million  and  $8  million  as  of  December  31,  2015  and  December  31,  2014,  respectively.  Since  the  forecasted  transactions  remain   probable  of  occurring,  these  amounts  will  be  amortized  into  earnings  over  the  life  of  the  hedging  instruments.  Approximately  $1  million   of  net  unamortized  losses  is  expected  to  be  amortized  to  income  during  the  next  twelve  months.   NUGs   As  of  December  31,  2015,  FirstEnergy's  net  liability  position  under  NUG  contracts  was  $136  million  representing  contracts  held  at   JCP&L,  ME  and  PN.  NUG  contracts  represent  purchased  power  agreements  with  third-­party  non-­utility  generators  that  are  transacted   to  satisfy  certain  obligations  under  PURPA.  Changes  in  the  fair  value  of  NUG  contracts  are  subject  to  regulatory  accounting  treatment   and  do  not  impact  earnings.   FTRs   As  of  December  31,  2015,  FirstEnergy's  and  FES'  net  liability  position  under  FTRs  was  $5  million  and  $6  million,  respectively  and   FES  posted  $6  million  of  collateral.  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   an   RTO   that   have   load   serving   obligations  and  through  the  direct  allocation  of  FTRs  from  PJM.  PJM  has  a  rule  that  allows  directly  allocated  FTRs  to  be  granted  to   LSEs  in  zones  that  have  newly  entered  PJM.  For  the  first  two  planning  years,  PJM  permits  the  LSEs  to  request  a  direct  allocation  of   FTRs  in  these  new  zones  at  no  cost  as  opposed  to  receiving  ARRs.  The  directly  allocated  FTRs  differ  from  traditional  FTRs  in  that  the   ownership  of  all  or  part  of  the  FTRs  may  shift  to  another  LSE  if  customers  choose  to  shop  with  the  other  LSE.   104   105                                                                         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,    2015   December  31,    2014   (In  millions)   Fair  Value   December  31,    2015   December  31,    2014   (In  millions)   Current  Assets  -­   Derivatives   Commodity  Contracts   $   FTRs   Deferred  Charges  and   Other  Assets  -­  Other   Commodity  Contracts   FTRs   NUGs(1)   Derivative  Assets   $   150   $   7   157   78   1   1   80   237   $   Current  Liabilities  -­   Derivatives   121          Commodity  Contracts   38   159   FTRs   $   Noncurrent  Liabilities  -­   Adverse  Power  Contract   Liability   (94  )   $   (12  )   (106  )   (154  )   (13  )   (167  )          NUGs(1)   Noncurrent  Liabilities  -­   Other   51   1          Commodity  Contracts   2   54   213   Derivative  Liabilities   FTRs   (137  )   (153  )   (37  )   (1  )   (175  )   (281  )   $   (13  )   (1  )   (167  )   (334  )   $   (1)   NUG  contracts  are  subject  to  regulatory  accounting  treatment  and  do  not  impact  earnings.   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:   106   107   December  31,  2015   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   Derivative  Assets   Commodity  contracts   FTRs   NUG  contracts   Derivative  Liabilities   Commodity  contracts   FTRs   NUG  contracts   $   $   $   $   $   $   $   $   228   $   8   1   237   $   (131  )   $   (13  )   (137  )   (281  )   $   172   $   39   2   213   $   (167  )   $   (14  )   (153  )   (334  )   $   (125  )   $   (8  )   —   (133  )   $   125   $   8   —   133   $   (126  )   $   (14  )   —   (140  )   $   126   $   14   —   140   $   —   $   —   —   —   $   3   $   5   —   8   $   103   —   1   104   (3  )   —   (137  )   (140  )   —   $   —   —   —   $   35   $   —   —   35   $   46   25   2   73   (6  )   —   (153  )   (159  )   December  31,  2014   Fair  Value   Derivative   Instruments   Cash  Collateral   (Received)/Pledged   Net  Fair   Value   (In  millions)   Amounts  Not  Offset  in  Consolidated   Balance  Sheet   The  following  table  summarizes  the  volumes  associated  with  FirstEnergy’s  outstanding  derivative  transactions  as  of   December  31,  2015:   Power  Contracts   FTRs   NUGs   Natural  Gas   Purchases   Sales   Net   (In  millions)   16   29   4   83   49   —   —   —   Units   MWH   MWH   MWH   mmBTU   (33  )   29   4   83                                 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,   December  31,    2015    2014   (In  millions)   Fair  Value   December  31,   December  31,    2015    2014   (In  millions)   Current  Assets  -­   Derivatives   Commodity  Contracts   $   FTRs   Current  Liabilities  -­   Derivatives   121          Commodity  Contracts   $   150   $   7   157   38   159   FTRs   (94  )   $   (12  )   (106  )   (154  )   (13  )   (167  )   Deferred  Charges  and   Other  Assets  -­  Other   Commodity  Contracts   FTRs   NUGs(1)   Noncurrent  Liabilities  -­   Adverse  Power  Contract   Liability          NUGs(1)   Noncurrent  Liabilities  -­   51   Other   1          Commodity  Contracts   2   54   FTRs   78   1   1   80   (137  )   (153  )   (37  )   (1  )   (175  )   (281  )   $   (13  )   (1  )   (167  )   (334  )   Derivative  Assets   $   237   $   213   Derivative  Liabilities   $   (1)   NUG  contracts  are  subject  to  regulatory  accounting  treatment  and  do  not  impact  earnings.   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,  2015   Fair  Value   Derivative   Instruments   Cash  Collateral   (Received)/Pledged   Net  Fair   Value   Amounts  Not  Offset  in  Consolidated   Balance  Sheet   Derivative  Assets   Commodity  contracts   FTRs   NUG  contracts   Derivative  Liabilities   Commodity  contracts   FTRs   NUG  contracts   $   $   $   $   228   $   8   1   237   $   (131  )   $   (13  )   (137  )   (281  )   $   (In  millions)   (125  )   $   (8  )   —   (133  )   $   125   $   8   —   133   $   —   $   —   —   —   $   3   $   5   —   8   $   103   —   1   104   (3  )   —   (137  )   (140  )   December  31,  2014   Fair  Value   Derivative   Instruments   Cash  Collateral   (Received)/Pledged   Net  Fair   Value   Amounts  Not  Offset  in  Consolidated   Balance  Sheet   Derivative  Assets   Commodity  contracts   FTRs   NUG  contracts   Derivative  Liabilities   Commodity  contracts   FTRs   NUG  contracts   $   $   $   $   172   $   39   2   213   $   (167  )   $   (14  )   (153  )   (334  )   $   (In  millions)   (126  )   $   (14  )   —   (140  )   $   126   $   14   —   140   $   —   $   —   —   —   $   35   $   —   —   35   $   46   25   2   73   (6  )   —   (153  )   (159  )   The  following  table  summarizes  the  volumes  associated  with  FirstEnergy’s  outstanding  derivative  transactions  as  of   December  31,  2015:   Power  Contracts   FTRs   NUGs   Natural  Gas   Purchases   Sales   Net   (In  millions)   16   29   4   83   49   —   —   —   Units   MWH   MWH   MWH   mmBTU   (33  )   29   4   83   106   107                                 The  effect  of  active  derivative  instruments  not  in  a  hedging  relationship  on  the  Consolidated  Statements  of  Income  during  2015   and  2014  are  summarized  in  the  following  tables:   The  following  table  provides  a  reconciliation  of  changes  in  the  fair  value  of  FirstEnergy's  derivative  instruments  subject  to  regulatory   accounting  during  2015  and  2014.  Changes  in  the  value  of  these  contracts  are  deferred  for  future  recovery  from  (or  credit  to)   customers:   Year  Ended  December  31,   Commodity   Contracts   FTRs   Total   (In  millions)   Unrealized  Gain  (Loss)  Recognized  in:   Other  Operating  Expense(1)   Realized  Gain  (Loss)  Reclassified  to:   Revenues(2)   Purchased  Power  Expense(3)   Other  Operating  Expense(4)   Fuel  Expense   2015   $   $   93   $   (20  )   $   73   111   $   (130  )   —   (34  )   50   $   —   (49  )   —   161   (130  )   (49  )   (34  )   (1)  Includes  $93  million  for  commodity  contracts  and  ($19)  million  for  FTRs  associated  with  FES.   (2)  Includes  $111  million  for  commodity  contracts  and  $49  million  for  FTRs  associated  with  FES.   (3)  Includes  ($130)  million  for  commodity  contracts  associated  with  FES.   (4)  Includes  ($49)  million  for  FTRs  associated  with  FES.   2014   Unrealized  Gain  (Loss)  Recognized  in:   Other  Operating  Expense(5)   Realized  Gain  (Loss)  Reclassified  to:   Revenues(6)   Purchased  Power  Expense(7)   Other  Operating  Expense(8)   Fuel  Expense   Interest  Expense   Year  Ended  December  31,   Commodity   Contracts   FTRs   Interest   Rate  Swaps   Total   (In  millions)   $   $   (86  )   $   22   $   —   $   (64  )   (6  )   $   365   —   (6  )   —   68   $   —   (44  )   —   —   —   $   —   —   —   14   62   365   (44  )   (6  )   14   Derivatives  Not  in  a  Hedging  Relationship  with   Regulatory  Offset   Outstanding  net  asset  (liability)  as  of  January  1,  2015   $   (151  )   $   Unrealized  loss   Purchases   Settlements   Unrealized  gain  (loss)   Purchases   Settlements   Outstanding  net  asset  (liability)  as  of  December  31,  2015   Outstanding  net  liability  as  of  January  1,  2014   Year  Ended  December  31,   NUGs   Total   Regulated   FTRs   (In  millions)   $   $   (47  )   —   62   (136  )   $   (202  )   $   (1  )   —   52   11   $   (9  )   12   (13  )   1   $   —   $   13   11   (13  )   (140  )   (56  )   12   49   (135  )   (202  )   12   11   39   Outstanding  net  asset  (liability)  as  of  December  31,  2014   $   (151  )   $   11   $   (140  )   11.  CAPITALIZATION   COMMON  STOCK   Retained  Earnings  and  Dividends   As  of  December  31,  2015,  FirstEnergy’s  unrestricted  retained  earnings  were  $2.3  billion.  Dividends  declared  in  2015  and  2014  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  19,  2016  the  Board  of  Directors  declared  a  quarterly  dividend   of  $0.36  per  share  to  be  paid  in  the  first  quarter  of  2016.   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  the  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,  2015.   (5)  Includes  ($86)  million  for  commodity  contracts  and  $21  million  for  FTRs  associated  with  FES.   (6)  Includes  ($6)  million  for  commodity  contracts  and  $67  million  for  FTRs  associated  with  FES.   (7)  Realized  losses  on  financially  settled  wholesale  sales  contracts  of  $252  million  resulting  from  higher  market  prices  were  netted  in  purchased   power.  Includes  $365  million  for  commodity  contracts  associated  with  FES.   (8)  Includes  ($43)  million  for  FTRs  associated  with  FES.   Stock  Issuance   In  each  of  2015  and  2014,  FE  issued  approximately  2.5  million  shares  of  common  stock  to  registered  shareholders  and  its  employees   and  the  employees  of  its  subsidiaries  under  its  Stock  Investment  Plan  and  certain  share-­based  benefit  plans.     108   109                                     The  effect  of  active  derivative  instruments  not  in  a  hedging  relationship  on  the  Consolidated  Statements  of  Income  during  2015   and  2014  are  summarized  in  the  following  tables:   The  following  table  provides  a  reconciliation  of  changes  in  the  fair  value  of  FirstEnergy's  derivative  instruments  subject  to  regulatory   accounting  during  2015  and  2014.  Changes  in  the  value  of  these  contracts  are  deferred  for  future  recovery  from  (or  credit  to)   customers:   Year  Ended  December  31,   Commodity   Contracts   FTRs   Total   (In  millions)   Unrealized  Gain  (Loss)  Recognized  in:   Other  Operating  Expense(1)   Realized  Gain  (Loss)  Reclassified  to:   Revenues(2)   Purchased  Power  Expense(3)   Other  Operating  Expense(4)   Fuel  Expense   2015   $   $   93   $   (20  )   $   73   111   $   50   $   (130  )   —   (34  )   —   (49  )   —   161   (130  )   (49  )   (34  )   (1)  Includes  $93  million  for  commodity  contracts  and  ($19)  million  for  FTRs  associated  with  FES.   (2)  Includes  $111  million  for  commodity  contracts  and  $49  million  for  FTRs  associated  with  FES.   (3)  Includes  ($130)  million  for  commodity  contracts  associated  with  FES.   (4)  Includes  ($49)  million  for  FTRs  associated  with  FES.   2014   Unrealized  Gain  (Loss)  Recognized  in:   Other  Operating  Expense(5)   Realized  Gain  (Loss)  Reclassified  to:   Revenues(6)   Purchased  Power  Expense(7)   Other  Operating  Expense(8)   Fuel  Expense   Interest  Expense   Year  Ended  December  31,   Commodity   Contracts   FTRs   Interest   Rate  Swaps   Total   (In  millions)   $   $   (86  )   $   22   $   —   $   (64  )   (6  )   $   365   —   (6  )   —   —   (44  )   —   —   68   $   —   $   —   —   —   14   62   365   (44  )   (6  )   14   (5)  Includes  ($86)  million  for  commodity  contracts  and  $21  million  for  FTRs  associated  with  FES.   (6)  Includes  ($6)  million  for  commodity  contracts  and  $67  million  for  FTRs  associated  with  FES.   (7)  Realized  losses  on  financially  settled  wholesale  sales  contracts  of  $252  million  resulting  from  higher  market  prices  were  netted  in  purchased   power.  Includes  $365  million  for  commodity  contracts  associated  with  FES.   (8)  Includes  ($43)  million  for  FTRs  associated  with  FES.   Derivatives  Not  in  a  Hedging  Relationship  with   Regulatory  Offset   NUGs   Year  Ended  December  31,   Regulated   FTRs   (In  millions)   Total   Outstanding  net  asset  (liability)  as  of  January  1,  2015   Unrealized  loss   Purchases   Settlements   Outstanding  net  asset  (liability)  as  of  December  31,  2015   Outstanding  net  liability  as  of  January  1,  2014   Unrealized  gain  (loss)   Purchases   Settlements   Outstanding  net  asset  (liability)  as  of  December  31,  2014   $   $   $   $   (151  )   $   (47  )   —   62   (136  )   $   (202  )   $   (1  )   —   52   (151  )   $   11   $   (9  )   12   (13  )   1   $   —   $   13   11   (13  )   11   $   (140  )   (56  )   12   49   (135  )   (202  )   12   11   39   (140  )   11.  CAPITALIZATION   COMMON  STOCK   Retained  Earnings  and  Dividends   As  of  December  31,  2015,  FirstEnergy’s  unrestricted  retained  earnings  were  $2.3  billion.  Dividends  declared  in  2015  and  2014  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  19,  2016  the  Board  of  Directors  declared  a  quarterly  dividend   of  $0.36  per  share  to  be  paid  in  the  first  quarter  of  2016.   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  the  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,  2015.   Stock  Issuance   In  each  of  2015  and  2014,  FE  issued  approximately  2.5  million  shares  of  common  stock  to  registered  shareholders  and  its  employees   and  the  employees  of  its  subsidiaries  under  its  Stock  Investment  Plan  and  certain  share-­based  benefit  plans.     108   109                                     PREFERRED  AND  PREFERENCE  STOCK   LONG-­TERM  DEBT  AND  OTHER  LONG-­TERM  OBLIGATIONS   FirstEnergy  and  the  Utilities  were  authorized  to  issue  preferred  stock  and  preference  stock  as  of  December  31,  2015,  as  follows:   The  following  tables  present  outstanding  long-­term  debt  and  capital  lease  obligations  for  FirstEnergy  and  FES  as  of  December  31,   Preferred  Stock   Preference  Stock   Shares   Authorized   Par  Value   Shares   Authorized   Par  Value   2015  and  2014:   8,000,000   no  par   3,000,000   5,000,000   $   no  par   25   FirstEnergy   OE   OE   Penn   CEI   TE   TE   JCP&L   ME   PN   MP   PE   WP   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   no  par   100   25   no  par   no  par   no  par   100   0.01   no  par   As  of  December  31,  2015,  and  2014,  there  were  no  preferred  or  preference  shares  outstanding.   Total  long-­term  debt  and  other  long-­term  obligations   $   19,192   $   19,176   (Dollar  amounts  in  millions)   Maturity  Date   Interest  Rate   2015   2014   As  of  December  31,  2015   As  of  December  31   FirstEnergy:   FMBs   Secured  notes  -­  fixed  rate   Secured  notes  -­  variable  rate   Total  secured  notes   Unsecured  notes  -­  fixed  rate   Unsecured  notes  -­  variable  rate   Total  unsecured  notes   Capital  lease  obligations   Unamortized  debt  discounts   Unamortized  fair  value  adjustments   Currently  payable  long-­term  debt   FES:   Secured  notes  -­  fixed  rate   Secured  notes  -­  variable  rate   Total  secured  notes   Unsecured  notes  -­  fixed  rate   Unsecured  notes  -­  variable  rate   Total  unsecured  notes   Capital  lease  obligations   Unamortized  debt  discounts   Currently  payable  long-­term  debt   2016  -­  2045   3.340%  -­  9.740%   $   2016  -­  2037   0.679%  -­  12.000%   2017  -­  2017   3.500%  -­  3.500%   2016  -­  2045   2.150%  -­  7.700%   2017  -­  2020   0.010%  -­  2.180%   2016  -­  2018   5.625%  -­  12.000%   $   2017  -­  2017   3.500%  -­  3.500%   340   $   2   2016  -­  2039   2.150%  -­  6.800%   2017  -­  2017   0.010%  -­  0.010%   3,269   $   2,096   2   2,098   13,580   1,292   14,872   132   (18  )   5   (1,166  )   3,190   2,247   —   2,247   13,078   1,292   14,370   160   (8  )   21   (804  )   342   2,593   92   2,685   13   (1  )   (512  )   437   —   437   2,568   92   2,660   18   (1  )   (506  )   2,608   Total  long-­term  debt  and  other  long-­term  obligations   $   2,527   $   During  the  second  quarter  of  2015,  FE  refinanced  a  $200  million  variable  interest  term  loan,  maturing  on  December  31,  2016  with  a   new  $200  million  variable  interest  term  loan  maturing  on  May  29,  2020.     On  July  1,  2015,  FG  and  NG  remarketed  approximately  $43  million  and  $296  million,  respectively,  of  PCRBs.  The  PCRBs  were   remarketed  with  fixed  interest  rates  ranging  from  3.125%  to  4.00%  and  mandatory  put  dates  ranging  from  July  2,  2018  to  July  1,   2021.     In  August  2015,  JCP&L  issued  $250  million  of  4.30%  senior  notes  due  January  2026.  The  proceeds  received  from  the  issuance  of  the   senior  notes  were  used  to  repay  a  portion  of  JCP&L’s  short-­term  borrowings  under  the  FirstEnergy  regulated  companies'  money  pool   and  an  external  revolving  credit  facility.       Also,  in  the  second  quarter  of  2015,  WP  agreed  to  sell  $150  million  of  new  4.45%  FMBs  due  September  2045  and  PE  agreed  to  sell   $145   million   of   new   4.47%   FMBs   due   August   2045.   The   transactions   closed   on   September   17,   2015   and   August   17,   2015,   respectively.  The  proceeds  resulting  from  the  issuance  of  the  WP  FMBs  were  used  to  repay  WP’s  borrowings  under  the  FirstEnergy   regulated  companies'  money  pool  and  for  other  general  corporate  purposes.  The  proceeds  resulting  from  the  issuance  of  the  PE   FMBs  were  used  to  repay  PE’s  $145  million  5.125%  FMBs  that  matured  on  August  15,  2015.     In  October  2015,  TrAIL  issued  $75  million  of  3.76%  senior  notes  due  May  2025.  The  proceeds  resulting  from  the  issuance  of  the   senior  notes  were  used:  (i)  to  fund  capital  expenditures,  including  with  respect  to  TrAIL's  transmission  expansion  plans;;  and  (ii)  for   working  capital  needs  and  other  general  business  purposes.     Additionally,  in  October  2015,  ATSI  issued  in  total  $150  million  of  senior  notes:  $75  million  of  4.00%  senior  notes  due  April  2026  and   $75  million  of  5.23%  senior  notes  due  October  2045.  The  proceeds  resulting  from  the  issuance  of  the  senior  notes  were  used:  (i)  to   110   111                           PREFERRED  AND  PREFERENCE  STOCK   LONG-­TERM  DEBT  AND  OTHER  LONG-­TERM  OBLIGATIONS   FirstEnergy  and  the  Utilities  were  authorized  to  issue  preferred  stock  and  preference  stock  as  of  December  31,  2015,  as  follows:   The  following  tables  present  outstanding  long-­term  debt  and  capital  lease  obligations  for  FirstEnergy  and  FES  as  of  December  31,   2015  and  2014:   Preferred  Stock   Preference  Stock   Shares   Authorized   Par  Value   Shares   Authorized   Par  Value   8,000,000   no  par   3,000,000   5,000,000   $   no  par   25   FirstEnergy   OE   OE   Penn   CEI   TE   TE   JCP&L   ME   PN   MP   PE   WP   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   no  par   100   25   no  par   no  par   no  par   100   0.01   no  par   As  of  December  31,  2015   Maturity  Date   Interest  Rate   As  of  December  31   2014   2015   2016  -­  2045   2016  -­  2037   2017  -­  2017   3.340%  -­  9.740%   0.679%  -­  12.000%   3.500%  -­  3.500%   $   2016  -­  2045   2017  -­  2020   2.150%  -­  7.700%   0.010%  -­  2.180%   (Dollar  amounts  in  millions)   FirstEnergy:   FMBs   Secured  notes  -­  fixed  rate   Secured  notes  -­  variable  rate   Total  secured  notes   Unsecured  notes  -­  fixed  rate   Unsecured  notes  -­  variable  rate   Total  unsecured  notes   Capital  lease  obligations   Unamortized  debt  discounts   Unamortized  fair  value  adjustments   Currently  payable  long-­term  debt   As  of  December  31,  2015,  and  2014,  there  were  no  preferred  or  preference  shares  outstanding.   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   Unsecured  notes  -­  variable  rate   Total  unsecured  notes   Capital  lease  obligations   Unamortized  debt  discounts   Currently  payable  long-­term  debt   2016  -­  2018   2017  -­  2017   5.625%  -­  12.000%   $   3.500%  -­  3.500%   2016  -­  2039   2017  -­  2017   2.150%  -­  6.800%   0.010%  -­  0.010%   Total  long-­term  debt  and  other  long-­term  obligations   $   3,269   $   2,096   2   2,098   13,580   1,292   14,872   132   (18  )   5   (1,166  )   19,192   $   340   $   2   342   2,593   92   2,685   13   (1  )   (512  )   2,527   $   3,190   2,247   —   2,247   13,078   1,292   14,370   160   (8  )   21   (804  )   19,176   437   —   437   2,568   92   2,660   18   (1  )   (506  )   2,608   During  the  second  quarter  of  2015,  FE  refinanced  a  $200  million  variable  interest  term  loan,  maturing  on  December  31,  2016  with  a   new  $200  million  variable  interest  term  loan  maturing  on  May  29,  2020.     On  July  1,  2015,  FG  and  NG  remarketed  approximately  $43  million  and  $296  million,  respectively,  of  PCRBs.  The  PCRBs  were   remarketed  with  fixed  interest  rates  ranging  from  3.125%  to  4.00%  and  mandatory  put  dates  ranging  from  July  2,  2018  to  July  1,   2021.     In  August  2015,  JCP&L  issued  $250  million  of  4.30%  senior  notes  due  January  2026.  The  proceeds  received  from  the  issuance  of  the   senior  notes  were  used  to  repay  a  portion  of  JCP&L’s  short-­term  borrowings  under  the  FirstEnergy  regulated  companies'  money  pool   and  an  external  revolving  credit  facility.       Also,  in  the  second  quarter  of  2015,  WP  agreed  to  sell  $150  million  of  new  4.45%  FMBs  due  September  2045  and  PE  agreed  to  sell   $145   million   of   new   4.47%   FMBs   due   August   2045.   The   transactions   closed   on   September   17,   2015   and   August   17,   2015,   respectively.  The  proceeds  resulting  from  the  issuance  of  the  WP  FMBs  were  used  to  repay  WP’s  borrowings  under  the  FirstEnergy   regulated  companies'  money  pool  and  for  other  general  corporate  purposes.  The  proceeds  resulting  from  the  issuance  of  the  PE   FMBs  were  used  to  repay  PE’s  $145  million  5.125%  FMBs  that  matured  on  August  15,  2015.     In  October  2015,  TrAIL  issued  $75  million  of  3.76%  senior  notes  due  May  2025.  The  proceeds  resulting  from  the  issuance  of  the   senior  notes  were  used:  (i)  to  fund  capital  expenditures,  including  with  respect  to  TrAIL's  transmission  expansion  plans;;  and  (ii)  for   working  capital  needs  and  other  general  business  purposes.     Additionally,  in  October  2015,  ATSI  issued  in  total  $150  million  of  senior  notes:  $75  million  of  4.00%  senior  notes  due  April  2026  and   $75  million  of  5.23%  senior  notes  due  October  2045.  The  proceeds  resulting  from  the  issuance  of  the  senior  notes  were  used:  (i)  to   110   111                           fund  capital  expenditures,  including  with  respect  to  ATSI's  transmission  expansion  plans;;  (ii)  for  working  capital  needs  and  other   general  business  purposes;;  and  (iii)  to  repay  borrowings  under  the  FirstEnergy  regulated  companies'  money  pool.       The  following  table  classifies  the  outstanding  fixed  rate  PCRBs  and  variable  rate  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.   See  Note  6,  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,  2015  and  2014,  $429  million  and  $450  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,  2015  and  2014,  $128  million  and  $168   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,  2015  and  2014,  $362  million  and  $386  million  of  the  phase-­in  recovery  bonds  were   outstanding,  respectively.   See  Note  8,  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,  2015,  the  sinking  fund   requirement  for  all  FMBs  issued  under  the  various  mortgage  indentures  amounted  to  payments  of  $3  million  in  2015,  all  of  which   relate   to   Penn.   Penn   expects   to   meet   its   2016   annual   sinking   fund   requirement   with   a   replacement   credit   under   its   mortgage   indenture.   As  of  December  31,  2015,  FirstEnergy’s  currently  payable  long-­term  debt  included  approximately  $92  million  of  FES  variable  interest   rate  PCRBs,  the  bondholders  of  which  are  entitled  to  the  benefit  of  irrevocable  direct  pay  bank  LOCs.  The  interest  rates  on  the   PCRBs  are  reset  daily  or  weekly.  Bondholders  can  tender  their  PCRBs  for  mandatory  purchase  prior  to  maturity  with  the  purchase   price  payable  from  remarketing  proceeds  or,  if  the  PCRBs  are  not  successfully  remarketed,  by  drawings  on  the  irrevocable  direct  pay   LOCs.  The  subsidiary  obligor  is  required  to  reimburse  the  applicable  LOC  bank  for  any  such  drawings  or,  if  the  LOC  bank  fails  to   honor  its  LOC  for  any  reason,  must  itself  pay  the  purchase  price.     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,  2015.  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   2016   2017   2018   2019   2020   FirstEnergy   FES   $   (In  millions)   1,039   $   1,733   1,702   2,268   1,231   414   257   516   322   667   Obligations  to  repay  certain  PCRBs  are  secured  by  several  series  of  FMBs.  Certain  PCRBs  are  entitled  to  the  benefit  of  irrevocable   bank  LOCs,  to  pay  principal  of,  or  interest  on,  the  applicable  PCRBs.  To  the  extent  that  drawings  are  made  under  the  LOCs,  FG  is   entitled  to  a  credit  against  its  obligation  to  repay  those  bonds.  FG  pays  annual  fees  based  on  the  amounts  of  the  LOCs  to  the  issuing   bank  and  is  obligated  to  reimburse  the  bank  for  any  drawings  thereunder.   The  amounts  and  annual  fees  for  PCRB-­related  LOCs  for  FirstEnergy  and  FES  as  of  December  31,  2015,  are  as  follows:   Year   FirstEnergy   FES   $   (In  millions)   391   $   222   375   232   490   391   222   375   232   490   2016   2017   2018   2019   2020   Aggregate  LOC   Amount  (1)   (In  millions)   Annual  Fees   FirstEnergy   $   FES   93   93   1.25%   1.25%   (1)   Includes  approximately  $1  million  of  applicable  interest   coverage.   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,  2015,  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   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.   112   113                                                 fund  capital  expenditures,  including  with  respect  to  ATSI's  transmission  expansion  plans;;  (ii)  for  working  capital  needs  and  other   general  business  purposes;;  and  (iii)  to  repay  borrowings  under  the  FirstEnergy  regulated  companies'  money  pool.       The  following  table  classifies  the  outstanding  fixed  rate  PCRBs  and  variable  rate  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.   See  Note  6,  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,  2015  and  2014,  $429  million  and  $450  million  of   environmental  control  bonds  were  outstanding,  respectively.   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,  2015  and  2014,  $128  million  and  $168   million  of  the  transition  bonds  were  outstanding,  respectively.   Transition  Bonds   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,  2015  and  2014,  $362  million  and  $386  million  of  the  phase-­in  recovery  bonds  were   outstanding,  respectively.   See  Note  8,  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,  2015,  the  sinking  fund   requirement  for  all  FMBs  issued  under  the  various  mortgage  indentures  amounted  to  payments  of  $3  million  in  2015,  all  of  which   relate   to   Penn.   Penn   expects   to   meet   its   2016   annual   sinking   fund   requirement   with   a   replacement   credit   under   its   mortgage   indenture.   As  of  December  31,  2015,  FirstEnergy’s  currently  payable  long-­term  debt  included  approximately  $92  million  of  FES  variable  interest   rate  PCRBs,  the  bondholders  of  which  are  entitled  to  the  benefit  of  irrevocable  direct  pay  bank  LOCs.  The  interest  rates  on  the   PCRBs  are  reset  daily  or  weekly.  Bondholders  can  tender  their  PCRBs  for  mandatory  purchase  prior  to  maturity  with  the  purchase   price  payable  from  remarketing  proceeds  or,  if  the  PCRBs  are  not  successfully  remarketed,  by  drawings  on  the  irrevocable  direct  pay   LOCs.  The  subsidiary  obligor  is  required  to  reimburse  the  applicable  LOC  bank  for  any  such  drawings  or,  if  the  LOC  bank  fails  to   honor  its  LOC  for  any  reason,  must  itself  pay  the  purchase  price.     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,  2015.  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   2016   2017   2018   2019   2020   FirstEnergy   FES   (In  millions)   1,039   $   $   1,733   1,702   2,268   1,231   414   257   516   322   667   Year   FirstEnergy   FES   $   2016   2017   2018   2019   2020   (In  millions)   391   $   222   375   232   490   391   222   375   232   490   Obligations  to  repay  certain  PCRBs  are  secured  by  several  series  of  FMBs.  Certain  PCRBs  are  entitled  to  the  benefit  of  irrevocable   bank  LOCs,  to  pay  principal  of,  or  interest  on,  the  applicable  PCRBs.  To  the  extent  that  drawings  are  made  under  the  LOCs,  FG  is   entitled  to  a  credit  against  its  obligation  to  repay  those  bonds.  FG  pays  annual  fees  based  on  the  amounts  of  the  LOCs  to  the  issuing   bank  and  is  obligated  to  reimburse  the  bank  for  any  drawings  thereunder.   The  amounts  and  annual  fees  for  PCRB-­related  LOCs  for  FirstEnergy  and  FES  as  of  December  31,  2015,  are  as  follows:   Aggregate  LOC   Amount  (1)   (In  millions)   Annual  Fees   FirstEnergy   $   FES   93   93   1.25%   1.25%   (1)   Includes  approximately  $1  million  of  applicable  interest   coverage.   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,  2015,  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   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.   112   113                                                 12.  SHORT-­TERM  BORROWINGS  AND  BANK  LINES  OF  CREDIT   FE  and  certain  of  its  subsidiaries  participate  in  three  five-­year  syndicated  revolving  credit  facilities  with  aggregate  commitments  of   $6.0  billion  (Facilities),  which  are  available  until  March  31,  2019.  FirstEnergy  had  $1,708  million  and  $1,799  million  of  short-­term   borrowings  as  of  December  31,  2015  and  2014,  respectively.  FirstEnergy’s  available  liquidity  under  the  Facilities  as  of  January  31,   2016  was  as  follows:     Borrower(s)   Type   Maturity   Commitment   Available   Liquidity   FirstEnergy(1)   FES  /  AE  Supply   FET(2)   Revolving   Revolving   Revolving   March  2019   $   March  2019   March  2019   Subtotal   $   Cash   Total   $   (In  millions)   3,500   $   1,500   1,000   6,000   $   —   6,000   $   1,595   1,442   1,000   4,037   63   4,100   (1)   (2)   FE  and  the  Utilities     Includes  FET,  ATSI  and  TrAIL  as  subsidiary  borrowers   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.     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   December  31,  2015:   Borrower   FE   FES   AE  Supply   FET   OE   CEI   TE   JCP&L   ME   PN   WP   MP   PE   ATSI   Penn   TrAIL   Revolving   Credit  Facility   Sub-­Limits   Regulatory  and   Other  Short-­Term   Debt  Limitations   (In  millions)   $   3,500   1,500   1,000   1,000   500   500   500   600   300   300   200   500   150   500   50   400   $   —   (1)   —   (2)   —   (2)   —   (1)   500   (3)   500   (3)   500   (3)   500   (3)   500   (3)   300   (3)   200   (3)   500   (3)   150   (3)   500   (3)   100   (3)   400   (3)   (1)   (2)   (3)   No  limitations.     No  limitation  based  upon  blanket  financing  authorization  from  the  FERC  under  existing  market-­based  rate  tariffs.     Excluding  amounts  which  may  be  borrowed  under  the  regulated  companies'  money  pool.     The  entire  amount  of  the  FES/AE  Supply  Facility,  $600  million  of  the  FE  Facility  and  $225  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   114   115   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,  2015,  the  borrowers  were  in  compliance  with  the  applicable  debt  to  total  capitalization  ratio  covenants  under  the   respective  Facilities.       Term  Loans   FE  has  a  $1  billion  variable  rate  term  loan  credit  agreement  with  a  maturity  date  of  March  31,  2019.  The  initial  borrowing  under  the   term  loan,  which  took  the  form  of  a  Eurodollar  rate  advance,  may  be  converted  from  time  to  time,  in  whole  or  in  part,  to  alternate  base   rate  advances  or  other  Eurodollar  rate  advances.  The  proceeds  from  this  term  loan  reduced  borrowings  under  the  FE  Facility.   Additionally,  FE  has  a  $200  million  variable  rate  term  loan  with  a  maturity  date  of  May  29,  2020.  Each  of  the  term  loans  contains   covenants  and  other  terms  and  conditions  substantially  similar  to  those  of  the  FE  Facility  described  above,  including  the  same   consolidated  debt  to  total  capitalization  ratio  requirement.     As  of  December  31,  2015,  FE  was  in  compliance  with  the  applicable  consolidated  debt  to  total  capitalization  ratio  covenants  under   each  of  these  term  loans.     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.  A  similar  but  separate  arrangement  exists  among  FirstEnergy’s  unregulated  companies.   FESC  administers  these  two  money  pools  and  tracks  surplus  funds  of  FirstEnergy  and  the  respective  regulated  and  unregulated   subsidiaries,  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  2015  was  0.84%  per  annum  for  the  regulated  companies’  money  pool   and  1.64%  per  annum  for  the  unregulated  companies’  money  pool.   Weighted  Average  Interest  Rates   The  weighted  average  interest  rates  on  short-­term  borrowings  outstanding,  including  borrowings  under  the  FirstEnergy  Money  Pools,   as  of  December  31,  2015  and  2014,  were  as  follows:     FirstEnergy   FES   2015   2014   2.16  %   —  %   1.96  %   3.34  %   13.  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.  FES  uses  an  expected  cash  flow  approach  to  measure  the  fair  value  of  their  nuclear  decommissioning  AROs.   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,  2015  and  2014  were  as  follows:   FirstEnergy   FES   $   $   2015   2014   (In  millions)   2,282   $   1,327   $   2,341   1,365                                                   12.  SHORT-­TERM  BORROWINGS  AND  BANK  LINES  OF  CREDIT   FE  and  certain  of  its  subsidiaries  participate  in  three  five-­year  syndicated  revolving  credit  facilities  with  aggregate  commitments  of   $6.0  billion  (Facilities),  which  are  available  until  March  31,  2019.  FirstEnergy  had  $1,708  million  and  $1,799  million  of  short-­term   borrowings  as  of  December  31,  2015  and  2014,  respectively.  FirstEnergy’s  available  liquidity  under  the  Facilities  as  of  January  31,   2016  was  as  follows:     Borrower(s)   Type   Maturity   Commitment   FirstEnergy(1)   FES  /  AE  Supply   FET(2)   Revolving   Revolving   Revolving   Available   Liquidity   (In  millions)   3,500   $   1,500   1,000   6,000   $   —   6,000   $   1,595   1,442   1,000   4,037   63   4,100   March  2019   $   March  2019   March  2019   Subtotal   $   Cash   Total   $   FE  and  the  Utilities     (1)   (2)   Includes  FET,  ATSI  and  TrAIL  as  subsidiary  borrowers   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.     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   December  31,  2015:   Borrower   AE  Supply   JCP&L   FE   FES   FET   OE   CEI   TE   ME   PN   WP   MP   PE   ATSI   Penn   TrAIL   Revolving   Credit  Facility   Sub-­Limits   Regulatory  and   Other  Short-­Term   Debt  Limitations   (In  millions)   $   $   3,500   1,500   1,000   1,000   500   500   500   600   300   300   200   500   150   500   50   400   —   (1)   —   (2)   —   (2)   —   (1)   500   (3)   500   (3)   500   (3)   500   (3)   500   (3)   300   (3)   200   (3)   500   (3)   150   (3)   500   (3)   100   (3)   400   (3)   No  limitations.     (1)   (2)   (3)   No  limitation  based  upon  blanket  financing  authorization  from  the  FERC  under  existing  market-­based  rate  tariffs.     Excluding  amounts  which  may  be  borrowed  under  the  regulated  companies'  money  pool.     The  entire  amount  of  the  FES/AE  Supply  Facility,  $600  million  of  the  FE  Facility  and  $225  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,  2015,  the  borrowers  were  in  compliance  with  the  applicable  debt  to  total  capitalization  ratio  covenants  under  the   respective  Facilities.       Term  Loans   FE  has  a  $1  billion  variable  rate  term  loan  credit  agreement  with  a  maturity  date  of  March  31,  2019.  The  initial  borrowing  under  the   term  loan,  which  took  the  form  of  a  Eurodollar  rate  advance,  may  be  converted  from  time  to  time,  in  whole  or  in  part,  to  alternate  base   rate  advances  or  other  Eurodollar  rate  advances.  The  proceeds  from  this  term  loan  reduced  borrowings  under  the  FE  Facility.   Additionally,  FE  has  a  $200  million  variable  rate  term  loan  with  a  maturity  date  of  May  29,  2020.  Each  of  the  term  loans  contains   covenants  and  other  terms  and  conditions  substantially  similar  to  those  of  the  FE  Facility  described  above,  including  the  same   consolidated  debt  to  total  capitalization  ratio  requirement.     As  of  December  31,  2015,  FE  was  in  compliance  with  the  applicable  consolidated  debt  to  total  capitalization  ratio  covenants  under   each  of  these  term  loans.     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.  A  similar  but  separate  arrangement  exists  among  FirstEnergy’s  unregulated  companies.   FESC  administers  these  two  money  pools  and  tracks  surplus  funds  of  FirstEnergy  and  the  respective  regulated  and  unregulated   subsidiaries,  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  2015  was  0.84%  per  annum  for  the  regulated  companies’  money  pool   and  1.64%  per  annum  for  the  unregulated  companies’  money  pool.   Weighted  Average  Interest  Rates   The  weighted  average  interest  rates  on  short-­term  borrowings  outstanding,  including  borrowings  under  the  FirstEnergy  Money  Pools,   as  of  December  31,  2015  and  2014,  were  as  follows:     FirstEnergy   FES   2015   2014   2.16  %   —  %   1.96  %   3.34  %   13.  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.  FES  uses  an  expected  cash  flow  approach  to  measure  the  fair  value  of  their  nuclear  decommissioning  AROs.   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,  2015  and  2014  were  as  follows:   FirstEnergy   FES   $   $   2015   2014   (In  millions)   2,282   $   1,327   $   2,341   1,365   114   115                                                   The  following  table  summarizes  the  changes  to  the  ARO  balances  during  2015  and  2014:   ARO  Reconciliation   FirstEnergy   FES   Balance,  January  1,  2014   Liabilities  settled   Accretion   Revisions  in  estimated  cash  flows   Balance,  December  31,  2014   Liabilities  settled   Accretion   Revisions  in  estimated  cash  flows   Balance,  December  31,  2015   $   $   $   (In  millions)   1,678   $   (9  )   113   (395  )   1,387   $   (13  )   92   (56  )   1,410   $   1,015   (7  )   66   (233  )   841   (8  )   55   (57  )   831   During  2015,  FE  and  FES  reduced  its  ARO  by  $57  million based  on  the  results  of  decommissioning  cost  studies  for  the  Davis-­Besse   and  Perry  nuclear  generating  stations.   During  2014,  based  on  studies  by  a  third-­party  to  reassess  the  estimated  costs  of  decommissioning  certain  nuclear  generating   facilities,  FE  decreased  its  ARO  by  $395  million  ($233  million  at  FES)  of  which  $133  million  was  credited  against  a  regulatory  asset   associated  with  nuclear  decommissioning  and  spent  fuel  disposal  costs  for  TMI-­2.  The  decrease  in  the  ARO  primarily  resulted  from   an  extension  in  the  number  of  years  in  which  decommissioning  activities  are  estimated  to  occur  at  Davis-­Besse,  Perry,  TMI-­2  and   Beaver  Valley  Units  1  and  2.     14.  REGULATORY  MATTERS   STATE  REGULATION   Each  of  the  Utilities'  retail  rates,  conditions  of  service,  issuance  of  securities  and  other  matters  are  subject  to  regulation  in  the  states   in  which  it  operates  -­  in  Maryland  by  the  MDPSC,  in  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,  Illinois,  Michigan,  New  Jersey  and   Maryland,  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.   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  by  10%   and  reduce  electricity  demand  by  15%,  in  each  case  by  2015,  and  requiring  each  electric  utility  to  file  a  plan  every  three  years.  PE's   current  plan,  covering  the  three-­year  period  2015-­2017,  was  approved  by  the  MDPSC  on  December  23,  2014.  The  costs  of  the  2015-­ 2017   plan   are   expected   to   be   approximately   $66   million   for   that   three-­year   period,   of   which   $19   million   was   incurred   through   December  2015.  On  July  16,  2015,  the  MDPSC  issued  an  order  setting  new  incremental  energy  savings  goals  for  2017  and  beyond,   beginning  with  the  level  of  savings  achieved  under  PE's  current  plan  for  2016,  and  ramping  up  0.2%  per  year  thereafter  to  reach  2%.   PE  continues  to  recover  program  costs  subject  to  a  five-­year  amortization.  Maryland  law  only  allows  for  the  utility  to  recover  lost   distribution  revenue  attributable  to  energy  efficiency  or  demand  reduction  programs  through  a  base  rate  case  proceeding,  and  to   date,  such  recovery  has  not  been  sought  or  obtained  by  PE.  On  January  28,  2016,  PE  filed  a  request  to  increase  plan  spending  by  $2   million  in  order  to  reach  the  new  goals  for  2017  set  in  the  July  16,  2015  order.     On   February   27,   2013,   the   MDPSC   issued   an   order   (the   February   27   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.  The  order  further  required  the  Staff  of  the  MDPSC  to  report  on  possible  performance-­based  rate  structures  and  to   propose  additional  rules  relating  to  feeder  performance  standards,  outage  communication  and  reporting,  and  sharing  of  special  needs   customer  information.  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  27  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  27  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.  The  Staff  of  the  MDPSC  also  recommended  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  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  yet  issued  a  ruling   on  any  of  those  matters.   On  March  3,  2014,  pursuant  to  the  MDPSC's  regulations,  PE  filed  its  recommendations  for  SAIDI  and  SAIFI  standards  to  apply  during   the  period  2016-­2019.  The  MDPSC  directed  the  Staff  of  the  MDPSC  to  file  an  analysis  and  recommendations  with  respect  to  the   proposed  2016-­2019  SAIDI  and  SAIFI  standards  and  any  related  rule  changes  which  the  Staff  of  the  MDPSC  recommended.  The   Staff   of   the   MDPSC   made   its   filing   on   July   10,   2015,   and   recommended   that   PE   be   required   to   improve   its   SAIDI   results   by   approximately  20%  by  2019.  The  MDPSC  held  a  hearing  on  the  Staff's  analysis  and  recommendations  on  September  1-­2,  2015,  and   approved  PE's  revised  proposal  for  an  improvement  of  8.6%  in  its  SAIDI  standard  by  2019  and  maintained  its  SAIFI  standard  at  2015   levels.  The  proposed  regulations  incorporating  the  new  SAIDI  and  SAIFI  standards  were  approved  as  final  in  December  2015.     On  April  1,  2015,  PE  filed  its  annual  report  on  its  performance  relative  to  various  service  reliability  standards  set  forth  in  the  MDPSC’s   regulations.  The  MDPSC  conducted  hearings  on  the  reports  filed  by  PE  and  the  other  electric  utilities  in  Maryland  on  August  24,  2015   and  subsequently  closed  its  2014  service  reliability  review.     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.   On  March  26,  2015,  the  NJBPU  entered  final  orders  which  together  provided  an  overall  reduction  in  JCP&L's  annual  revenues  of   approximately  $34  million,  effective  April  1,  2015.  The  final  order  in  JCP&L's  base  rate  case  proceeding  directed  an  annual  base  rate   revenue  reduction  of  approximately  $115  million,  including  recovery  of  2011  storm  costs  and  the  application  of  the  NJBPU's  modified   CTA   policy   approved   in   the   generic   CTA   proceeding   referred   to   below.  Additionally,   the   final   order   in   the   generic   proceeding   established  to  review  JCP&L's  major  storm  events  of  2011  and  2012  approved  the  recovery  of  2012  storm  costs  of  $580  million   resulting  in  an  increase  in  annual  revenues  of  approximately  $81  million.  JCP&L  is  required  to  file  another  base  rate  case  no  later   than  April  1,  2017.  The  NJBPU  also  directed  that  certain  studies  be  completed.  On  July  22,  2015,  the  NJBPU  approved  the  NJBPU   staff's  recommendation  to  implement  such  studies,  which  will  include  operational  and  financial  components  and  is  expected  to  take   approximately  one  year  to  complete.     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  (Generic  CTA  proceeding),  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  New  Jersey  Superior  Court  and  JCP&L  has  filed  to  participate  as  a  respondent  in   that  proceeding.  Briefing  has  been  completed,  and  oral  argument  has  not  yet  been  scheduled.   On  June  19,  2015,  JCP&L,  along  with  PN,  ME,  FET  and  MAIT  made  filings  with  FERC,  the  NJBPU,  and  the  PPUC  requesting   authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT,  a  new  transmission-­only  subsidiary  of  FET.  On   January  8,  2016,  the  NJBPU  President  issued  an  Order  granting  Rate  Counsel’s  Motion  on  the  legal  issue  of  whether  MAIT  can  be   designated  as  a  public  utility.  The  procedural  schedule  has  been  suspended  until  a  decision  is  made  on  this  issue.  See  Transfer  of   Transmission  Assets  to  MAIT  in  FERC  Matters  below  for  further  discussion  of  this  transaction.     OHIO   prior  ESP;;   The  Ohio  Companies  operate  under  their  ESP  3  plan  which  expires  on  May  31,  2016.  The  material  terms  of  ESP  3  include:   •     A  base  distribution  rate  freeze  through  May  31,  2016;;   •     Collection  of  lost  distribution  revenues  associated  with  energy  efficiency  and  peak  demand  reduction  programs;;   •     Economic  development  and  assistance  to  low-­income  customers  for  the  two-­year  plan  period  at  levels  established  in  the   •     A   6%   generation   rate   discount   to   certain   low   income   customers   provided   by   the   Ohio   Companies   through   a   bilateral   wholesale  contract  with  FES  (FES  is  one  of  the  wholesale  suppliers  to  the  Ohio  Companies);;   •     A  requirement  to  provide  power  to  non-­shopping  customers  at  a  market-­based  price  set  through  an  auction  process;;   116   117                                               The  following  table  summarizes  the  changes  to  the  ARO  balances  during  2015  and  2014:   ARO  Reconciliation   FirstEnergy   FES   Balance,  January  1,  2014   Liabilities  settled   Accretion   Revisions  in  estimated  cash  flows   Balance,  December  31,  2014   Liabilities  settled   Accretion   Revisions  in  estimated  cash  flows   Balance,  December  31,  2015   $   $   $   (In  millions)   1,678   $   (9  )   113   (395  )   1,387   $   (13  )   92   (56  )   1,410   $   1,015   (7  )   66   (233  )   841   (8  )   55   (57  )   831   During  2015,  FE  and  FES  reduced  its  ARO  by  $57  million based  on  the  results  of  decommissioning  cost  studies  for  the  Davis-­Besse   and  Perry  nuclear  generating  stations.   During  2014,  based  on  studies  by  a  third-­party  to  reassess  the  estimated  costs  of  decommissioning  certain  nuclear  generating   facilities,  FE  decreased  its  ARO  by  $395  million  ($233  million  at  FES)  of  which  $133  million  was  credited  against  a  regulatory  asset   associated  with  nuclear  decommissioning  and  spent  fuel  disposal  costs  for  TMI-­2.  The  decrease  in  the  ARO  primarily  resulted  from   an  extension  in  the  number  of  years  in  which  decommissioning  activities  are  estimated  to  occur  at  Davis-­Besse,  Perry,  TMI-­2  and   Beaver  Valley  Units  1  and  2.     14.  REGULATORY  MATTERS   STATE  REGULATION   Each  of  the  Utilities'  retail  rates,  conditions  of  service,  issuance  of  securities  and  other  matters  are  subject  to  regulation  in  the  states   in  which  it  operates  -­  in  Maryland  by  the  MDPSC,  in  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,  Illinois,  Michigan,  New  Jersey  and   Maryland,  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.   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  by  10%   and  reduce  electricity  demand  by  15%,  in  each  case  by  2015,  and  requiring  each  electric  utility  to  file  a  plan  every  three  years.  PE's   current  plan,  covering  the  three-­year  period  2015-­2017,  was  approved  by  the  MDPSC  on  December  23,  2014.  The  costs  of  the  2015-­ 2017   plan   are   expected   to   be   approximately   $66   million   for   that   three-­year   period,   of   which   $19   million   was   incurred   through   December  2015.  On  July  16,  2015,  the  MDPSC  issued  an  order  setting  new  incremental  energy  savings  goals  for  2017  and  beyond,   beginning  with  the  level  of  savings  achieved  under  PE's  current  plan  for  2016,  and  ramping  up  0.2%  per  year  thereafter  to  reach  2%.   PE  continues  to  recover  program  costs  subject  to  a  five-­year  amortization.  Maryland  law  only  allows  for  the  utility  to  recover  lost   distribution  revenue  attributable  to  energy  efficiency  or  demand  reduction  programs  through  a  base  rate  case  proceeding,  and  to   date,  such  recovery  has  not  been  sought  or  obtained  by  PE.  On  January  28,  2016,  PE  filed  a  request  to  increase  plan  spending  by  $2   million  in  order  to  reach  the  new  goals  for  2017  set  in  the  July  16,  2015  order.     On   February   27,   2013,   the   MDPSC   issued   an   order   (the   February   27   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.  The  order  further  required  the  Staff  of  the  MDPSC  to  report  on  possible  performance-­based  rate  structures  and  to   propose  additional  rules  relating  to  feeder  performance  standards,  outage  communication  and  reporting,  and  sharing  of  special  needs   customer  information.  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  27  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  27  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.  The  Staff  of  the  MDPSC  also  recommended  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  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  yet  issued  a  ruling   on  any  of  those  matters.   On  March  3,  2014,  pursuant  to  the  MDPSC's  regulations,  PE  filed  its  recommendations  for  SAIDI  and  SAIFI  standards  to  apply  during   the  period  2016-­2019.  The  MDPSC  directed  the  Staff  of  the  MDPSC  to  file  an  analysis  and  recommendations  with  respect  to  the   proposed  2016-­2019  SAIDI  and  SAIFI  standards  and  any  related  rule  changes  which  the  Staff  of  the  MDPSC  recommended.  The   Staff   of   the   MDPSC   made   its   filing   on   July   10,   2015,   and   recommended   that   PE   be   required   to   improve   its   SAIDI   results   by   approximately  20%  by  2019.  The  MDPSC  held  a  hearing  on  the  Staff's  analysis  and  recommendations  on  September  1-­2,  2015,  and   approved  PE's  revised  proposal  for  an  improvement  of  8.6%  in  its  SAIDI  standard  by  2019  and  maintained  its  SAIFI  standard  at  2015   levels.  The  proposed  regulations  incorporating  the  new  SAIDI  and  SAIFI  standards  were  approved  as  final  in  December  2015.     On  April  1,  2015,  PE  filed  its  annual  report  on  its  performance  relative  to  various  service  reliability  standards  set  forth  in  the  MDPSC’s   regulations.  The  MDPSC  conducted  hearings  on  the  reports  filed  by  PE  and  the  other  electric  utilities  in  Maryland  on  August  24,  2015   and  subsequently  closed  its  2014  service  reliability  review.     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.   On  March  26,  2015,  the  NJBPU  entered  final  orders  which  together  provided  an  overall  reduction  in  JCP&L's  annual  revenues  of   approximately  $34  million,  effective  April  1,  2015.  The  final  order  in  JCP&L's  base  rate  case  proceeding  directed  an  annual  base  rate   revenue  reduction  of  approximately  $115  million,  including  recovery  of  2011  storm  costs  and  the  application  of  the  NJBPU's  modified   CTA   policy   approved   in   the   generic   CTA   proceeding   referred   to   below.  Additionally,   the   final   order   in   the   generic   proceeding   established  to  review  JCP&L's  major  storm  events  of  2011  and  2012  approved  the  recovery  of  2012  storm  costs  of  $580  million   resulting  in  an  increase  in  annual  revenues  of  approximately  $81  million.  JCP&L  is  required  to  file  another  base  rate  case  no  later   than  April  1,  2017.  The  NJBPU  also  directed  that  certain  studies  be  completed.  On  July  22,  2015,  the  NJBPU  approved  the  NJBPU   staff's  recommendation  to  implement  such  studies,  which  will  include  operational  and  financial  components  and  is  expected  to  take   approximately  one  year  to  complete.     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  (Generic  CTA  proceeding),  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  New  Jersey  Superior  Court  and  JCP&L  has  filed  to  participate  as  a  respondent  in   that  proceeding.  Briefing  has  been  completed,  and  oral  argument  has  not  yet  been  scheduled.   On  June  19,  2015,  JCP&L,  along  with  PN,  ME,  FET  and  MAIT  made  filings  with  FERC,  the  NJBPU,  and  the  PPUC  requesting   authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT,  a  new  transmission-­only  subsidiary  of  FET.  On   January  8,  2016,  the  NJBPU  President  issued  an  Order  granting  Rate  Counsel’s  Motion  on  the  legal  issue  of  whether  MAIT  can  be   designated  as  a  public  utility.  The  procedural  schedule  has  been  suspended  until  a  decision  is  made  on  this  issue.  See  Transfer  of   Transmission  Assets  to  MAIT  in  FERC  Matters  below  for  further  discussion  of  this  transaction.     OHIO   The  Ohio  Companies  operate  under  their  ESP  3  plan  which  expires  on  May  31,  2016.  The  material  terms  of  ESP  3  include:   •     A  base  distribution  rate  freeze  through  May  31,  2016;;   •     Collection  of  lost  distribution  revenues  associated  with  energy  efficiency  and  peak  demand  reduction  programs;;   •     Economic  development  and  assistance  to  low-­income  customers  for  the  two-­year  plan  period  at  levels  established  in  the   prior  ESP;;   •     A   6%   generation   rate   discount   to   certain   low   income   customers   provided   by   the   Ohio   Companies   through   a   bilateral   wholesale  contract  with  FES  (FES  is  one  of  the  wholesale  suppliers  to  the  Ohio  Companies);;   •     A  requirement  to  provide  power  to  non-­shopping  customers  at  a  market-­based  price  set  through  an  auction  process;;   116   117                                               •     Rider  DCR  that  allows  continued  investment  in  the  distribution  system  for  the  benefit  of  customers;;   •     A  commitment  not  to  recover  from  retail  customers  certain  costs  related  to  transmission  cost  allocations  for  the  longer  of  the   five-­year  period  from  June  1,  2011  through  May  31,  2016  or  when  the  amount  of  costs  avoided  by  customers  for  certain   types  of  products  totals  $360  million,  subject  to  the  outcome  of  certain  FERC  proceedings;;   •     Securing  generation  supply  for  a  longer  period  of  time  by  conducting  an  auction  for  a  three-­year  period  rather  than  a  one-­ year  period,  in  each  of  October  2012  and  January  2013,  to  mitigate  any  potential  price  spikes  for  the  Ohio  Companies'  utility   customers  who  do  not  switch  to  a  competitive  generation  supplier;;  and   •     Extending  the  recovery  period  for  costs  associated  with  purchasing  RECs  mandated  by  SB221,  Ohio's  renewable  energy   and  energy  efficiency  standard,  through  the  end  of  the  new  ESP  3  period.  This  is  expected  to  initially  reduce  the  monthly   renewable  energy  charge  for  all  non-­shopping  utility  customers  of  the  Ohio  Companies  by  spreading  out  the  costs  over  the   entire  ESP  period.   Notices  of  appeal  of  the  Ohio  Companies'  ESP  3  plan  to  the  Supreme  Court  of  Ohio  were  filed  by  the  Northeast  Ohio  Public  Energy   Council  and  the  ELPC.  The  oral  argument  in  this  matter  occurred  on  January  6,  2016.     The  Ohio  Companies  filed  an  application  with  the  PUCO  on  August  4,  2014  seeking  approval  of  their  ESP  IV  entitled  Powering  Ohio's   Progress.  The  Ohio  Companies  filed  a  Stipulation  and  Recommendation  on  December  22,  2014,  and  supplemental  stipulations  and   recommendations  on  May  28,  2015,  and  June  4,  2015.  The  evidentiary  hearing  on  the  ESP  IV  commenced  on  August  31,  2015  and   concluded   on   October   29,   2015.   On   December   1,   2015,   the   Ohio   Companies   filed   a   Third   Supplemental   Stipulation   and   Recommendation,  which  included  PUCO  Staff  as  a  signatory  party  in  addition  to  other  signatories. The  PUCO  completed  a  hearing   on  the  Third  Supplemental  Stipulation  and  Recommendation  in  January  2016.  Initial  briefs  are  due  on  February  16,  2016  and  reply   briefs  are  due  on  February  26,  2016.    A  final  PUCO  decision  is  expected  in  March  2016.       The  proposed  ESP  IV  supports  FirstEnergy's  strategic  focus  on  regulated  operations  and  better  positions  the  Ohio  Companies  to   deliver  on  their  ongoing  commitment  to  upgrade,  modernize  and  maintain  reliable  electric  service  for  customers  while  preserving   electric  security  in  Ohio.  The  material  terms  of  the  proposed  ESP  IV,  as  modified  by  the  stipulations  include:     •   An  eight-­year  term  (June  1,  2016  -­  May  31,  2024);;   •     Contemplates  continuing  a  base  distribution  rate  freeze  through  May  31,  2024;;   •     An  Economic  Stability  Program  that  flows  through  charges  or  credits  through  Rider  RRS  representing  the  net  result  of  the   price  paid  to  FES  through  a  proposed  eight-­year  FERC-­jurisdictional  PPA  for  the  output  of  the  Sammis  and  Davis-­Besse   plants  and  FES’  share  of  OVEC  against  the  revenues  received  from  selling  such  output  into  the  PJM  markets  over  the  same   period,  subject  to  the  PUCO’s  termination  of  Rider  RRS  charges/credits  associated  with  any  plants  or  units  that  may  be  sold   or  transferred;;     •     Continuing  to  provide  power  to  non-­shopping  customers  at  a  market-­based  price  set  through  an  auction  process;;   •     Continuing  Rider  DCR  with  increased  revenue  caps  of  approximately  $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  that  supports  continued  investment  related  to  the  distribution  system  for  the  benefit  of  customers;;     •     Collection  of  lost  distribution  revenues  associated  with  energy  efficiency  and  peak  demand  reduction  programs;;     •     A  risk-­sharing  mechanism  that  would  provide  guaranteed  credits  under  Rider  RRS  in  years  five  through  eight  to  customers     as  follows:  $10  million  in  year  five,  $20  million  in  year  six,  $30  million  in  year  seven  and  $40  million  in  year  eight;;     •     A  continuing  commitment  not  to  recover  from  retail  customers  certain  costs  related  to  transmission  cost  allocations  for  the   longer  of  the  five-­year  period  from  June  1,  2011  through  May  31,  2016  or  when  the  amount  of  such  costs  avoided  by   customers  for  certain  types  of  products  totals  $360  million,  including  such  costs  from  MISO  along  with  such  costs  from  PJM,   subject  to  the  outcome  of  certain  FERC  proceedings;;     •     Potential  procurement  of  100  MW  of  new  Ohio  wind  or  solar  resources  subject  to  a  demonstrated  need  to  procure  new   renewable  energy  resources  as  part  of  a  strategy  to  further  diversify  Ohio's  energy  portfolio;;     •     An  agreement  to  file  a  case  with  the  PUCO  by  April  3,  2017,  seeking  to  transition  to  decoupled  base  rates  for  residential   PENNSYLVANIA   customers;;   •     An  agreement  to  file  by  February  29,  2016,  a  Grid  Modernization  Business  Plan  for  PUCO  consideration  and  approval;;   •     A  contribution  of  $3  million  per  year  ($24  million  over  the  eight  year  term)  to  fund  energy  conservation  programs,   economic  development  and  job  retention  in  the  Ohio  Companies  service  territory;;     •     Contributions  of  $2.4  million  per  year  ($19  million  over  the  eight  year  term)  to  fund  a  fuel-­fund  in  each  of  the  Ohio   Companies  service  territories  to  assist  low-­income  customers;;  and     •     A  contribution  of  $1  million  per  year  ($8  million  over  the  eight  year  term)  to  establish  a  Customary  Advisory  Council  to   ensure  preservation  and  growth  of  the  competitive  market  in  Ohio.     On  January  27,  2016,  certain  parties  filed  a  complaint  at  FERC  against  FES,  OE,  CEI,  and  TE  that  requests  FERC  review  of  the  ESP   IV  PPA  under  Section  205  of  the  FPA.  In  addition  to  such  proceeding,  parties  have  expressed  an  intention  to  challenge  in  the  courts   and/or  before  FERC,  the  PPA  or  PUCO  approval  of  the  ESP  IV,  if  approved.  Management  intends  to  vigorously  defend  against  such   challenges.     Under  Ohio's  energy  efficiency  standards  (SB221  and  SB310),  and  based  on  the  Ohio  Companies'  amended  energy  efficiency  plans,   the  Ohio  Companies  are  required  to  implement  energy  efficiency  programs  that  achieve  a  total  annual  energy  savings  equivalent  of   2,266   GWHs   in   2015   and   2,288   GWHs   in   2016,   and   then   begin   to   increase   by   1%   each   year   in   2017,   subject   to   legislative   amendments  to  the  energy  efficiency  standards  discussed  below.    The  Ohio  Companies  are  also  required  to  retain  the  2014  peak   118   119   demand  reduction  level  for  2015  and  2016  and  then  increase  the  benchmark  by  an  additional 0.75%  thereafter  through  2020,  subject   to  legislative  amendments  to  the  peak  demand  reduction  standards  discussed  below.   On  September  30,  2015,  the  Energy  Mandates  Study  Committee  issued  its  report  related  to  energy  efficiency  and  renewable  energy   mandates,  recommending  that  the  current  level  of  mandates  remain  in  place  indefinitely.  The  report  also  recommended:  (i)  an   expedited   process   for   review   of   utility   proposed   energy   efficiency   plans;;   (ii)   ensuring   maximum   credit   for   all   of   Ohio's   Energy   Initiatives;;  (iii)  a  switch  from  energy  mandates  to  energy  incentives;;  and  (iv)  a  declaration  be  made  that  the  General  Assembly  may   determine  energy  policy  of  the  state.  No  legislation  has  yet  been  introduced  to  change  the  standards  described  above.     On  March  20,  2013,  the  PUCO  approved  the  three-­year  energy  efficiency  portfolio  plans  for  2013-­2015,  originally  estimated  to  cost   the  Ohio  Companies  approximately  $250  million  over  the  three-­year  period,  which  is  expected  to  be  recovered  in  rates.  Actual  costs   may  be  lower  for  a  number  of  reasons  including  the  approval  of  the  amended  portfolio  plan  under  SB310.  On  July  17,  2013,  the   PUCO  modified  the  plan  to  authorize  the  Ohio  Companies  to  receive  20%  of  any  revenues  obtained  from  offering  energy  efficiency   and  DR  reserves  into  the  PJM  auction.  The  PUCO  also  confirmed  that  the  Ohio  Companies  can  recover  PJM  costs  and  applicable   penalties  associated  with  PJM  auctions,  including  the  costs  of  purchasing  replacement  capacity  from  PJM  incremental  auctions,  to   the  extent  that  such  costs  or  penalties  are  prudently  incurred.  ELPC  and  OCC  filed  applications  for  rehearing,  which  were  granted  for   the  sole  purpose  of  further  consideration  of  the  issue.  On  September  24,  2014,  the  Ohio  Companies  filed  an  amendment  to  their   portfolio  plan  as  contemplated  by  SB310,  seeking  to  suspend  certain  programs  for  the  2015-­2016  period  in  order  to  better  align  the   plan  with  the  new  benchmarks  under  SB310.  On  November  20,  2014,  the  PUCO  approved  the  Ohio  Companies'  amended  portfolio   plan.  Several  applications  for  rehearing  were  filed,  and  the  PUCO  granted  those  applications  for  further  consideration  of  the  matters   specified  in  those  applications.   On  September  16,  2013,  the  Ohio  Companies  filed  with  the  Supreme  Court  of  Ohio  a  notice  of  appeal  of  the  PUCO's  July  17,  2013   Entry  on  Rehearing  related  to  energy  efficiency,  alternative  energy,  and  long-­term  forecast  rules  stating  that  the  rules  issued  by  the   PUCO  are  inconsistent  with,  and  are  not  supported  by,  statutory  authority.  On  October  23,  2013,  the  PUCO  filed  a  motion  to  dismiss   the  appeal,  which  is  still  pending.  The  matter  has  not  been  scheduled  for  oral  argument.   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,  subject  to  legislative  amendments  discussed  above,  except   2015  and  2016  that  remain  at  the  2014  level.  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.  On  February  18,   2014,  the  OCC  and  the  ELPC  also  filed  appeals  of  the  PUCO's  order.  The  Ohio  Companies  timely  filed  their  merit  brief  with  the   Supreme  Court  of  Ohio  and  the  briefing  process  has  concluded.  The  matter  is  not  yet  scheduled  for  oral  argument.   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.     The   Pennsylvania   Companies   currently   operate   under   DSPs   that   expire   on   May   31,   2017,   and   provide   for   the   competitive   procurement  of  generation  supply  for  customers  that  do  not  choose  an  alternative  EGS  or  for  customers  of  alternative  EGSs  that  fail   to  provide  the  contracted  service.  The  default  service  supply  is  currently  provided  by  wholesale  suppliers  through  a  mix  of  long-­term   and  short-­term  contracts  procured  through  spot  market  purchases,  quarterly  descending  clock  auctions  for  3,  12-­  and  24-­month   energy  contracts,  and  one  RFP  seeking  2-­year  contracts  to  serve  SRECs  for  ME,  PN  and  Penn.     On  November  3,  2015,  the  Pennsylvania  Companies  filed  their  proposed  DSPs  for  the  June  1,  2017  through  May  31,  2019  delivery   period,  which  would  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  proposed  programs,  the  supply  would   be  provided  by  wholesale  suppliers  though  a  mix  of  12  and  24-­month  energy  contracts,  as  well  as  one  RFP  for  2-­year  SREC   contracts  for  ME,  PN  and  Penn.  In  addition,  the  proposal  includes  modifications  to  the  Pennsylvania  Companies’  existing  POR   programs  in  order  to  reduce  the  level  of  uncollectibles  the  Pennsylvania  Companies  experience  associated  with  alternative  EGS   charges.     Pursuant  to  Pennsylvania's  EE&C  legislation  (Act  129  of  2008)  and  PPUC  orders,  Pennsylvania  EDCs  implement  energy  efficiency   and  peak  demand  reduction  programs.  The  Pennsylvania  Companies'  Phase  II  EE&C  Plans  are  effective  through  May  31,  2016.  Total   costs   of   these   plans   are   expected   to   be   approximately   $234   million   and   recoverable   through   the   Pennsylvania   Companies'                                   •     Rider  DCR  that  allows  continued  investment  in  the  distribution  system  for  the  benefit  of  customers;;   •     A  commitment  not  to  recover  from  retail  customers  certain  costs  related  to  transmission  cost  allocations  for  the  longer  of  the   five-­year  period  from  June  1,  2011  through  May  31,  2016  or  when  the  amount  of  costs  avoided  by  customers  for  certain   types  of  products  totals  $360  million,  subject  to  the  outcome  of  certain  FERC  proceedings;;   •     Securing  generation  supply  for  a  longer  period  of  time  by  conducting  an  auction  for  a  three-­year  period  rather  than  a  one-­ year  period,  in  each  of  October  2012  and  January  2013,  to  mitigate  any  potential  price  spikes  for  the  Ohio  Companies'  utility   customers  who  do  not  switch  to  a  competitive  generation  supplier;;  and   •     Extending  the  recovery  period  for  costs  associated  with  purchasing  RECs  mandated  by  SB221,  Ohio's  renewable  energy   and  energy  efficiency  standard,  through  the  end  of  the  new  ESP  3  period.  This  is  expected  to  initially  reduce  the  monthly   renewable  energy  charge  for  all  non-­shopping  utility  customers  of  the  Ohio  Companies  by  spreading  out  the  costs  over  the   entire  ESP  period.   Notices  of  appeal  of  the  Ohio  Companies'  ESP  3  plan  to  the  Supreme  Court  of  Ohio  were  filed  by  the  Northeast  Ohio  Public  Energy   Council  and  the  ELPC.  The  oral  argument  in  this  matter  occurred  on  January  6,  2016.     The  Ohio  Companies  filed  an  application  with  the  PUCO  on  August  4,  2014  seeking  approval  of  their  ESP  IV  entitled  Powering  Ohio's   Progress.  The  Ohio  Companies  filed  a  Stipulation  and  Recommendation  on  December  22,  2014,  and  supplemental  stipulations  and   recommendations  on  May  28,  2015,  and  June  4,  2015.  The  evidentiary  hearing  on  the  ESP  IV  commenced  on  August  31,  2015  and   concluded   on   October   29,   2015.   On   December   1,   2015,   the   Ohio   Companies   filed   a   Third   Supplemental   Stipulation   and   Recommendation,  which  included  PUCO  Staff  as  a  signatory  party  in  addition  to  other  signatories. The  PUCO  completed  a  hearing   on  the  Third  Supplemental  Stipulation  and  Recommendation  in  January  2016.  Initial  briefs  are  due  on  February  16,  2016  and  reply   briefs  are  due  on  February  26,  2016.    A  final  PUCO  decision  is  expected  in  March  2016.       The  proposed  ESP  IV  supports  FirstEnergy's  strategic  focus  on  regulated  operations  and  better  positions  the  Ohio  Companies  to   deliver  on  their  ongoing  commitment  to  upgrade,  modernize  and  maintain  reliable  electric  service  for  customers  while  preserving   electric  security  in  Ohio.  The  material  terms  of  the  proposed  ESP  IV,  as  modified  by  the  stipulations  include:     •   An  eight-­year  term  (June  1,  2016  -­  May  31,  2024);;   •     Contemplates  continuing  a  base  distribution  rate  freeze  through  May  31,  2024;;   •     An  Economic  Stability  Program  that  flows  through  charges  or  credits  through  Rider  RRS  representing  the  net  result  of  the   price  paid  to  FES  through  a  proposed  eight-­year  FERC-­jurisdictional  PPA  for  the  output  of  the  Sammis  and  Davis-­Besse   plants  and  FES’  share  of  OVEC  against  the  revenues  received  from  selling  such  output  into  the  PJM  markets  over  the  same   period,  subject  to  the  PUCO’s  termination  of  Rider  RRS  charges/credits  associated  with  any  plants  or  units  that  may  be  sold   or  transferred;;     •     Continuing  to  provide  power  to  non-­shopping  customers  at  a  market-­based  price  set  through  an  auction  process;;   •     Continuing  Rider  DCR  with  increased  revenue  caps  of  approximately  $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  that  supports  continued  investment  related  to  the  distribution  system  for  the  benefit  of  customers;;     •     Collection  of  lost  distribution  revenues  associated  with  energy  efficiency  and  peak  demand  reduction  programs;;     •     A  risk-­sharing  mechanism  that  would  provide  guaranteed  credits  under  Rider  RRS  in  years  five  through  eight  to  customers     as  follows:  $10  million  in  year  five,  $20  million  in  year  six,  $30  million  in  year  seven  and  $40  million  in  year  eight;;     •     A  continuing  commitment  not  to  recover  from  retail  customers  certain  costs  related  to  transmission  cost  allocations  for  the   longer  of  the  five-­year  period  from  June  1,  2011  through  May  31,  2016  or  when  the  amount  of  such  costs  avoided  by   customers  for  certain  types  of  products  totals  $360  million,  including  such  costs  from  MISO  along  with  such  costs  from  PJM,   subject  to  the  outcome  of  certain  FERC  proceedings;;     •     Potential  procurement  of  100  MW  of  new  Ohio  wind  or  solar  resources  subject  to  a  demonstrated  need  to  procure  new   renewable  energy  resources  as  part  of  a  strategy  to  further  diversify  Ohio's  energy  portfolio;;     customers;;   •     An  agreement  to  file  by  February  29,  2016,  a  Grid  Modernization  Business  Plan  for  PUCO  consideration  and  approval;;   •     A  contribution  of  $3  million  per  year  ($24  million  over  the  eight  year  term)  to  fund  energy  conservation  programs,   economic  development  and  job  retention  in  the  Ohio  Companies  service  territory;;     •     Contributions  of  $2.4  million  per  year  ($19  million  over  the  eight  year  term)  to  fund  a  fuel-­fund  in  each  of  the  Ohio   Companies  service  territories  to  assist  low-­income  customers;;  and     •     A  contribution  of  $1  million  per  year  ($8  million  over  the  eight  year  term)  to  establish  a  Customary  Advisory  Council  to   ensure  preservation  and  growth  of  the  competitive  market  in  Ohio.     On  January  27,  2016,  certain  parties  filed  a  complaint  at  FERC  against  FES,  OE,  CEI,  and  TE  that  requests  FERC  review  of  the  ESP   IV  PPA  under  Section  205  of  the  FPA.  In  addition  to  such  proceeding,  parties  have  expressed  an  intention  to  challenge  in  the  courts   and/or  before  FERC,  the  PPA  or  PUCO  approval  of  the  ESP  IV,  if  approved.  Management  intends  to  vigorously  defend  against  such   challenges.     Under  Ohio's  energy  efficiency  standards  (SB221  and  SB310),  and  based  on  the  Ohio  Companies'  amended  energy  efficiency  plans,   the  Ohio  Companies  are  required  to  implement  energy  efficiency  programs  that  achieve  a  total  annual  energy  savings  equivalent  of   2,266   GWHs   in   2015   and   2,288   GWHs   in   2016,   and   then   begin   to   increase   by   1%   each   year   in   2017,   subject   to   legislative   amendments  to  the  energy  efficiency  standards  discussed  below.    The  Ohio  Companies  are  also  required  to  retain  the  2014  peak   demand  reduction  level  for  2015  and  2016  and  then  increase  the  benchmark  by  an  additional 0.75%  thereafter  through  2020,  subject   to  legislative  amendments  to  the  peak  demand  reduction  standards  discussed  below.   On  September  30,  2015,  the  Energy  Mandates  Study  Committee  issued  its  report  related  to  energy  efficiency  and  renewable  energy   mandates,  recommending  that  the  current  level  of  mandates  remain  in  place  indefinitely.  The  report  also  recommended:  (i)  an   expedited   process   for   review   of   utility   proposed   energy   efficiency   plans;;   (ii)   ensuring   maximum   credit   for   all   of   Ohio's   Energy   Initiatives;;  (iii)  a  switch  from  energy  mandates  to  energy  incentives;;  and  (iv)  a  declaration  be  made  that  the  General  Assembly  may   determine  energy  policy  of  the  state.  No  legislation  has  yet  been  introduced  to  change  the  standards  described  above.     On  March  20,  2013,  the  PUCO  approved  the  three-­year  energy  efficiency  portfolio  plans  for  2013-­2015,  originally  estimated  to  cost   the  Ohio  Companies  approximately  $250  million  over  the  three-­year  period,  which  is  expected  to  be  recovered  in  rates.  Actual  costs   may  be  lower  for  a  number  of  reasons  including  the  approval  of  the  amended  portfolio  plan  under  SB310.  On  July  17,  2013,  the   PUCO  modified  the  plan  to  authorize  the  Ohio  Companies  to  receive  20%  of  any  revenues  obtained  from  offering  energy  efficiency   and  DR  reserves  into  the  PJM  auction.  The  PUCO  also  confirmed  that  the  Ohio  Companies  can  recover  PJM  costs  and  applicable   penalties  associated  with  PJM  auctions,  including  the  costs  of  purchasing  replacement  capacity  from  PJM  incremental  auctions,  to   the  extent  that  such  costs  or  penalties  are  prudently  incurred.  ELPC  and  OCC  filed  applications  for  rehearing,  which  were  granted  for   the  sole  purpose  of  further  consideration  of  the  issue.  On  September  24,  2014,  the  Ohio  Companies  filed  an  amendment  to  their   portfolio  plan  as  contemplated  by  SB310,  seeking  to  suspend  certain  programs  for  the  2015-­2016  period  in  order  to  better  align  the   plan  with  the  new  benchmarks  under  SB310.  On  November  20,  2014,  the  PUCO  approved  the  Ohio  Companies'  amended  portfolio   plan.  Several  applications  for  rehearing  were  filed,  and  the  PUCO  granted  those  applications  for  further  consideration  of  the  matters   specified  in  those  applications.   On  September  16,  2013,  the  Ohio  Companies  filed  with  the  Supreme  Court  of  Ohio  a  notice  of  appeal  of  the  PUCO's  July  17,  2013   Entry  on  Rehearing  related  to  energy  efficiency,  alternative  energy,  and  long-­term  forecast  rules  stating  that  the  rules  issued  by  the   PUCO  are  inconsistent  with,  and  are  not  supported  by,  statutory  authority.  On  October  23,  2013,  the  PUCO  filed  a  motion  to  dismiss   the  appeal,  which  is  still  pending.  The  matter  has  not  been  scheduled  for  oral  argument.   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,  subject  to  legislative  amendments  discussed  above,  except   2015  and  2016  that  remain  at  the  2014  level.  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.  On  February  18,   2014,  the  OCC  and  the  ELPC  also  filed  appeals  of  the  PUCO's  order.  The  Ohio  Companies  timely  filed  their  merit  brief  with  the   Supreme  Court  of  Ohio  and  the  briefing  process  has  concluded.  The  matter  is  not  yet  scheduled  for  oral  argument.   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.     •     An  agreement  to  file  a  case  with  the  PUCO  by  April  3,  2017,  seeking  to  transition  to  decoupled  base  rates  for  residential   PENNSYLVANIA   The   Pennsylvania   Companies   currently   operate   under   DSPs   that   expire   on   May   31,   2017,   and   provide   for   the   competitive   procurement  of  generation  supply  for  customers  that  do  not  choose  an  alternative  EGS  or  for  customers  of  alternative  EGSs  that  fail   to  provide  the  contracted  service.  The  default  service  supply  is  currently  provided  by  wholesale  suppliers  through  a  mix  of  long-­term   and  short-­term  contracts  procured  through  spot  market  purchases,  quarterly  descending  clock  auctions  for  3,  12-­  and  24-­month   energy  contracts,  and  one  RFP  seeking  2-­year  contracts  to  serve  SRECs  for  ME,  PN  and  Penn.     On  November  3,  2015,  the  Pennsylvania  Companies  filed  their  proposed  DSPs  for  the  June  1,  2017  through  May  31,  2019  delivery   period,  which  would  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  proposed  programs,  the  supply  would   be  provided  by  wholesale  suppliers  though  a  mix  of  12  and  24-­month  energy  contracts,  as  well  as  one  RFP  for  2-­year  SREC   contracts  for  ME,  PN  and  Penn.  In  addition,  the  proposal  includes  modifications  to  the  Pennsylvania  Companies’  existing  POR   programs  in  order  to  reduce  the  level  of  uncollectibles  the  Pennsylvania  Companies  experience  associated  with  alternative  EGS   charges.     Pursuant  to  Pennsylvania's  EE&C  legislation  (Act  129  of  2008)  and  PPUC  orders,  Pennsylvania  EDCs  implement  energy  efficiency   and  peak  demand  reduction  programs.  The  Pennsylvania  Companies'  Phase  II  EE&C  Plans  are  effective  through  May  31,  2016.  Total   costs   of   these   plans   are   expected   to   be   approximately   $234   million   and   recoverable   through   the   Pennsylvania   Companies'   118   119                                   reconcilable  EE&C  riders.  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  filed  their  Phase  III  EE&C   plans  for  the  June  2016  through  May  2021  period  on  November  23,  2015,  which  are  designed  to  achieve  the  targets  established  in   the  PPUC's  Phase  III  Final  Implementation  Order.  EDCs  are  permitted  to  recover  costs  for  implementing  their  EE&C  plans.  On   February   10,   2016,   the   Pennsylvania   Companies   and   the   parties   intervening   in   the   PPUC's   Phase   III   proceeding   filed   a   joint   settlement  that  resolves  all  issues  in  the  proceeding  and  is  subject  to  PPUC  approval.       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  October  19,  2015,  each  of  the  Pennsylvania  Companies  filed   LTIIPs  with  the  PPUC  for  infrastructure  improvement  over  the  five-­year  period  of  2016  to  2020  for  the  following  costs:  WP  $88.34   million;;  PN  $56.74  million;;  Penn  $56.35  million;;  and  ME  $43.44  million.  These  amounts  include  all  qualifying  distribution  capital   additions  identified  in  the  revised  implementation  plan  for  the  recent  focused  management  and  operations  audit  of  the  Pennsylvania   Companies  as  discussed  below.  On  February  11,  2016,  the  PPUC  approved  the  Pennsylvania  Companies'  LTIIPs.  On  February  16,   2016,  the  Pennsylvania  Companies  filed  DSIC  riders  for  PPUC  approval  for  quarterly  cost  recovery  associated  with  the  capital   projects  approved  in  the  LTIIPs.  The  DSIC  riders  are  expected  to  be  effective  July  1,  2016.       Each  of  the  Pennsylvania  Companies  currently  offer  distribution  rates  under  their  respective  Joint  Petitions  for  Settlement  approved   on  April  9,  2015  by  the  PPUC,  which,  among  other  things,  provided  for  a  total  increase  in  annual  revenues  for  all  Pennsylvania   Companies  of  $292.8  million,  ($89.3  million  for  ME,  $90.8  million  for  PN,  $15.9  million  for  Penn  and  $96.8  million  for  WP),  including   the   recovery   of   $87.7   million   of   additional   annual   operating   expenses,   including   costs   associated   with   service   reliability   enhancements  to  the  distribution  system,  amortization  of  deferred  storm  costs  and  the  remaining  net  book  value  of  legacy  meters,   assistance  for  providing  service  to  low-­income  customers,  and  the  creation  of  a  storm  reserve  for  each  utility.  Additionally,  the   approved  settlements  include  commitments  to  meet  certain  wait  times  for  call  centers  and  service  reliability  standards.  The  new  rates   were  effective  May  3,  2015.     On  July  16,  2013,  the  PPUC's  Bureau  of  Audits  initiated  a  focused  management  and  operations  audit  of  the  Pennsylvania  Companies   as  required  every  eight  years  by  statute.  The  PPUC  issued  a  report  on  its  findings  and  recommendations  on  February  12,  2015,  at   which  time  the  Pennsylvania  Companies'  associated  implementation  plan  was  also  made  public.  In  an  order  issued  on  March  30,   2015,  the  Pennsylvania  Companies  were  directed  to  develop  and  file  by  May  29,  2015  a  revised  implementation  plan  regarding   certain  of  the  operational  topics  addressed  in  the  report,  including  addressing  certain  reliability  matters.  The  Pennsylvania  Companies   filed  their  revised  implementation  plan  in  compliance  with  this  order.  A  final  order  adopting  the  plan,  as  revised,  was  entered  on   November  5,  2015.  The  cost  of  compliance  for  the  Pennsylvania  Companies  is  currently  expected  to  range  from  approximately  $200   million  to  $230  million.     On  June  19,  2015,  ME  and  PN,  along  with  JCP&L,  FET  and  MAIT  made  filings  with  FERC,  the  NJBPU,  and  the  PPUC  requesting   authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT,  a  new  transmission-­only  subsidiary  of  FET.   Evidentiary  hearings  are  scheduled  to  commence  before  the  PPUC  on  February  29,  2016.  A  final  decision  from  the  PPUC  is  expected   by  mid-­2016.  See  Transfer  of  Transmission  Assets  to  MAIT  in  FERC  Matters  below  for  further  discussion  of  this  transaction.     WEST  VIRGINIA   MP  and  PE  currently  operate  under  a  Joint  Stipulation  and  Agreement  of  Settlement  approved  by  the  WVPSC  on  February  3,  2015,   that  provided  for:  a  $15  million  increase  in  annual  base  rate  revenues  effective  February  25,  2015;;  the  implementation  of  a  Vegetation   Management  Surcharge  to  recover  all  costs  related  to  both  new  and  existing  vegetation  maintenance  programs;;  authority  to  establish   a  regulatory  asset  for  MATS  investments  placed  into  service  in  2016  and  2017;;  authority  to  defer,  amortize  and  recover  over  a  five-­ year  period  through  base  rates  approximately  $46  million  of  storm  restoration  costs;;  and  elimination  of  the  TTS  for  costs  associated   with  MP's  acquisition  of  the  Harrison  plant  in  October  2013  and  movement  of  those  costs  into  base  rates.   On  August  14,  2015,  MP  and  PE  filed  their  annual  ENEC  case  with  the  WVPSC  proposing  an  approximate  $165.1  million  annual   increase  in  rates  effective  January  1,  2016  or  before,  which  would  be  a  12.5%  overall  increase  over  existing  rates.  The  original   proposed  increase  was  comprised  of  a  $97  million  under-­recovered  balance  as  of  June  30,  2015,  a  projected  $23.7  million  under-­ recovery  for  the  2016  calendar  year,  and  an  actual  under-­recovered  balance  from  MP  and  PE's  TTS  for  Harrison  Power  Station  of   $44.4   million.   On   September   10,   2015,   MP   and   PE   filed   an   amendment   addressing   the   results   of   the   recent   PJM  Transitional   Auctions  for  Capacity  Performance,  which  resulted  in  a  net  decrease  of  $20.6  million  from  the  initial  requested  increase  to  $144.5   million.  A  settlement  was  reached  among  all  the  parties  increasing  revenues  $96.9  million  and  deferring  other  costs  for  recovery  into   2017.  The  settlement  was  presented  to  the  WVPSC  on  November  19,  2015,  and  a  final  order  approving  the  settlement  without   changes  was  issued  on  December  22,  2015,  with  rates  effective  on  January  1,  2016.     On  August  31,  2015,  MP  and  PE  filed  with  the  WVPSC  their  biennial  petition  for  reconciliation  of  the  Vegetation  Management   Program  Surcharge  and  regular  review  of  the  program  proposing  an  approximate  $37.7  million  annual  increase  in  rates  over  a  two   year  period,  which  is  a  2.8%  overall  increase  over  existing  rates.  The  proposed  increase  was  comprised  of  a  $2.1  million  under-­ recovered  balance  as  of  June  30,  2015,  a  projected  $23.9  million  in  under-­recovery  for  the  2016/2017  rate  effective  period,  and   recovery  of  previously  authorized  deferred  vegetation  management  costs  from  April  14,  2014  through  February  24,  2015  in  the   amount  of  $49.9  million. A  settlement  was  reached  among  all  the  parties  increasing  revenues  $36.7  million  annually  for  the  2016-­ 2017  two  year  rate  recovery  period,  and  was  presented  to  the  WVPSC  on  November  19,  2015.  A  final  order  approving  the  settlement   without  changes  was  issued  on  December  21,  2015,  with  rates  effective  on  January  1,  2016.     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,  AE  Supply,  FG,  FENOC,  NG,  ATSI  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   FirstEnergy  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   occasionally   learns   of   isolated   facts   or   circumstances   that   could   be   interpreted   as   excursions   from   the   reliability   standards.   If   and   when   such   occurrences   are   found,   FirstEnergy  develops  information  about  the  occurrence  and  develops  a  remedial  response  to  the  specific  circumstances,  including  in   appropriate  cases  “self-­reporting”  an  occurrence  to  RFC.  Moreover,  it  is  clear  that  NERC,  RFC  and  FERC  will  continue  to  refine   existing  reliability  standards  as  well  as  to  develop  and  adopt  new  reliability  standards.  Any  inability  on  FirstEnergy's  part  to  comply   with  the  reliability  standards  for  its  bulk  electric  system  could  result  in  the  imposition  of  financial  penalties,  and  obligations  to  upgrade   or  build  transmission  facilities,  that  could  have  a  material  adverse  effect  on  its  financial  condition,  results  of  operations  and  cash   RFC.   flows.   FERC  MATTERS   PJM  Transmission  Rates   PJM  and  its  stakeholders  have  been  debating  the  proper  method  to  allocate  costs  for  new  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.  Settlement  discussions   under  a  FERC-­appointed  settlement  judge  are  ongoing.   In  a  series  of  orders  in  certain  Order  No.  1000  dockets,  FERC  asserted  that  the  PJM  transmission  owners  do  not  hold  an  incumbent   “right  of  first  refusal”  to  construct,  own  and  operate  transmission  projects  within  their  respective  footprints  that  are  approved  as  part  of   PJM’s  RTEP  process.  FirstEnergy  and  other  PJM  transmission  owners  have  appealed  these  rulings,  and  the  question  of  whether   FirstEnergy  and  the  PJM  transmission  owners  have  a  "right  of  first  refusal"  is  now  pending  before  the  U.S.  Court  of  Appeals  for  the   D.C.  Circuit  in  an  appeal  of  FERC's  order  approving  PJM's  Order  No.  1000  compliance  filing.   The  outcome  of  these  proceedings  and  their  impact,  if  any,  on  FirstEnergy  cannot  be  predicted  at  this  time.   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.  FirstEnergy's  request  for  rehearing  of  FERC's  order  rejecting  the  settlement  agreement  remains   pending.   Separately,  the  question  of  ATSI's  responsibility  for  certain  costs  for  the  “Michigan  Thumb”  transmission  project  continues  to  be   disputed.  Potential  responsibility  arises  under  the  MISO  MVP  tariff,  which  has  been  litigated  in  complex  proceedings  before  FERC   and  certain  United  States  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  is  pending  at  FERC.  In  the  event  of  a  final  non-­appealable  order  that  rules  that  ATSI  must  pay  these  charges,  ATSI  will  seek   120   121                                                 reconcilable  EE&C  riders.  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  filed  their  Phase  III  EE&C   plans  for  the  June  2016  through  May  2021  period  on  November  23,  2015,  which  are  designed  to  achieve  the  targets  established  in   the  PPUC's  Phase  III  Final  Implementation  Order.  EDCs  are  permitted  to  recover  costs  for  implementing  their  EE&C  plans.  On   February   10,   2016,   the   Pennsylvania   Companies   and   the   parties   intervening   in   the   PPUC's   Phase   III   proceeding   filed   a   joint   settlement  that  resolves  all  issues  in  the  proceeding  and  is  subject  to  PPUC  approval.       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  October  19,  2015,  each  of  the  Pennsylvania  Companies  filed   LTIIPs  with  the  PPUC  for  infrastructure  improvement  over  the  five-­year  period  of  2016  to  2020  for  the  following  costs:  WP  $88.34   million;;  PN  $56.74  million;;  Penn  $56.35  million;;  and  ME  $43.44  million.  These  amounts  include  all  qualifying  distribution  capital   additions  identified  in  the  revised  implementation  plan  for  the  recent  focused  management  and  operations  audit  of  the  Pennsylvania   Companies  as  discussed  below.  On  February  11,  2016,  the  PPUC  approved  the  Pennsylvania  Companies'  LTIIPs.  On  February  16,   2016,  the  Pennsylvania  Companies  filed  DSIC  riders  for  PPUC  approval  for  quarterly  cost  recovery  associated  with  the  capital   projects  approved  in  the  LTIIPs.  The  DSIC  riders  are  expected  to  be  effective  July  1,  2016.       Each  of  the  Pennsylvania  Companies  currently  offer  distribution  rates  under  their  respective  Joint  Petitions  for  Settlement  approved   on  April  9,  2015  by  the  PPUC,  which,  among  other  things,  provided  for  a  total  increase  in  annual  revenues  for  all  Pennsylvania   Companies  of  $292.8  million,  ($89.3  million  for  ME,  $90.8  million  for  PN,  $15.9  million  for  Penn  and  $96.8  million  for  WP),  including   the   recovery   of   $87.7   million   of   additional   annual   operating   expenses,   including   costs   associated   with   service   reliability   enhancements  to  the  distribution  system,  amortization  of  deferred  storm  costs  and  the  remaining  net  book  value  of  legacy  meters,   assistance  for  providing  service  to  low-­income  customers,  and  the  creation  of  a  storm  reserve  for  each  utility.  Additionally,  the   approved  settlements  include  commitments  to  meet  certain  wait  times  for  call  centers  and  service  reliability  standards.  The  new  rates   were  effective  May  3,  2015.     On  July  16,  2013,  the  PPUC's  Bureau  of  Audits  initiated  a  focused  management  and  operations  audit  of  the  Pennsylvania  Companies   as  required  every  eight  years  by  statute.  The  PPUC  issued  a  report  on  its  findings  and  recommendations  on  February  12,  2015,  at   which  time  the  Pennsylvania  Companies'  associated  implementation  plan  was  also  made  public.  In  an  order  issued  on  March  30,   2015,  the  Pennsylvania  Companies  were  directed  to  develop  and  file  by  May  29,  2015  a  revised  implementation  plan  regarding   certain  of  the  operational  topics  addressed  in  the  report,  including  addressing  certain  reliability  matters.  The  Pennsylvania  Companies   filed  their  revised  implementation  plan  in  compliance  with  this  order.  A  final  order  adopting  the  plan,  as  revised,  was  entered  on   November  5,  2015.  The  cost  of  compliance  for  the  Pennsylvania  Companies  is  currently  expected  to  range  from  approximately  $200   million  to  $230  million.     On  June  19,  2015,  ME  and  PN,  along  with  JCP&L,  FET  and  MAIT  made  filings  with  FERC,  the  NJBPU,  and  the  PPUC  requesting   authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT,  a  new  transmission-­only  subsidiary  of  FET.   Evidentiary  hearings  are  scheduled  to  commence  before  the  PPUC  on  February  29,  2016.  A  final  decision  from  the  PPUC  is  expected   by  mid-­2016.  See  Transfer  of  Transmission  Assets  to  MAIT  in  FERC  Matters  below  for  further  discussion  of  this  transaction.     WEST  VIRGINIA   MP  and  PE  currently  operate  under  a  Joint  Stipulation  and  Agreement  of  Settlement  approved  by  the  WVPSC  on  February  3,  2015,   that  provided  for:  a  $15  million  increase  in  annual  base  rate  revenues  effective  February  25,  2015;;  the  implementation  of  a  Vegetation   Management  Surcharge  to  recover  all  costs  related  to  both  new  and  existing  vegetation  maintenance  programs;;  authority  to  establish   a  regulatory  asset  for  MATS  investments  placed  into  service  in  2016  and  2017;;  authority  to  defer,  amortize  and  recover  over  a  five-­ year  period  through  base  rates  approximately  $46  million  of  storm  restoration  costs;;  and  elimination  of  the  TTS  for  costs  associated   with  MP's  acquisition  of  the  Harrison  plant  in  October  2013  and  movement  of  those  costs  into  base  rates.   On  August  14,  2015,  MP  and  PE  filed  their  annual  ENEC  case  with  the  WVPSC  proposing  an  approximate  $165.1  million  annual   increase  in  rates  effective  January  1,  2016  or  before,  which  would  be  a  12.5%  overall  increase  over  existing  rates.  The  original   proposed  increase  was  comprised  of  a  $97  million  under-­recovered  balance  as  of  June  30,  2015,  a  projected  $23.7  million  under-­ recovery  for  the  2016  calendar  year,  and  an  actual  under-­recovered  balance  from  MP  and  PE's  TTS  for  Harrison  Power  Station  of   $44.4   million.   On   September   10,   2015,   MP   and   PE   filed   an   amendment   addressing   the   results   of   the   recent   PJM  Transitional   Auctions  for  Capacity  Performance,  which  resulted  in  a  net  decrease  of  $20.6  million  from  the  initial  requested  increase  to  $144.5   million.  A  settlement  was  reached  among  all  the  parties  increasing  revenues  $96.9  million  and  deferring  other  costs  for  recovery  into   2017.  The  settlement  was  presented  to  the  WVPSC  on  November  19,  2015,  and  a  final  order  approving  the  settlement  without   changes  was  issued  on  December  22,  2015,  with  rates  effective  on  January  1,  2016.     On  August  31,  2015,  MP  and  PE  filed  with  the  WVPSC  their  biennial  petition  for  reconciliation  of  the  Vegetation  Management   Program  Surcharge  and  regular  review  of  the  program  proposing  an  approximate  $37.7  million  annual  increase  in  rates  over  a  two   year  period,  which  is  a  2.8%  overall  increase  over  existing  rates.  The  proposed  increase  was  comprised  of  a  $2.1  million  under-­ recovered  balance  as  of  June  30,  2015,  a  projected  $23.9  million  in  under-­recovery  for  the  2016/2017  rate  effective  period,  and   recovery  of  previously  authorized  deferred  vegetation  management  costs  from  April  14,  2014  through  February  24,  2015  in  the   amount  of  $49.9  million. A  settlement  was  reached  among  all  the  parties  increasing  revenues  $36.7  million  annually  for  the  2016-­ 2017  two  year  rate  recovery  period,  and  was  presented  to  the  WVPSC  on  November  19,  2015.  A  final  order  approving  the  settlement   without  changes  was  issued  on  December  21,  2015,  with  rates  effective  on  January  1,  2016.     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,  AE  Supply,  FG,  FENOC,  NG,  ATSI  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  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   occasionally   learns   of   isolated   facts   or   circumstances   that   could   be   interpreted   as   excursions   from   the   reliability   standards.   If   and   when   such   occurrences   are   found,   FirstEnergy  develops  information  about  the  occurrence  and  develops  a  remedial  response  to  the  specific  circumstances,  including  in   appropriate  cases  “self-­reporting”  an  occurrence  to  RFC.  Moreover,  it  is  clear  that  NERC,  RFC  and  FERC  will  continue  to  refine   existing  reliability  standards  as  well  as  to  develop  and  adopt  new  reliability  standards.  Any  inability  on  FirstEnergy's  part  to  comply   with  the  reliability  standards  for  its  bulk  electric  system  could  result  in  the  imposition  of  financial  penalties,  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   PJM  Transmission  Rates   PJM  and  its  stakeholders  have  been  debating  the  proper  method  to  allocate  costs  for  new  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.  Settlement  discussions   under  a  FERC-­appointed  settlement  judge  are  ongoing.   In  a  series  of  orders  in  certain  Order  No.  1000  dockets,  FERC  asserted  that  the  PJM  transmission  owners  do  not  hold  an  incumbent   “right  of  first  refusal”  to  construct,  own  and  operate  transmission  projects  within  their  respective  footprints  that  are  approved  as  part  of   PJM’s  RTEP  process.  FirstEnergy  and  other  PJM  transmission  owners  have  appealed  these  rulings,  and  the  question  of  whether   FirstEnergy  and  the  PJM  transmission  owners  have  a  "right  of  first  refusal"  is  now  pending  before  the  U.S.  Court  of  Appeals  for  the   D.C.  Circuit  in  an  appeal  of  FERC's  order  approving  PJM's  Order  No.  1000  compliance  filing.   The  outcome  of  these  proceedings  and  their  impact,  if  any,  on  FirstEnergy  cannot  be  predicted  at  this  time.   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.  FirstEnergy's  request  for  rehearing  of  FERC's  order  rejecting  the  settlement  agreement  remains   pending.   Separately,  the  question  of  ATSI's  responsibility  for  certain  costs  for  the  “Michigan  Thumb”  transmission  project  continues  to  be   disputed.  Potential  responsibility  arises  under  the  MISO  MVP  tariff,  which  has  been  litigated  in  complex  proceedings  before  FERC   and  certain  United  States  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  is  pending  at  FERC.  In  the  event  of  a  final  non-­appealable  order  that  rules  that  ATSI  must  pay  these  charges,  ATSI  will  seek   120   121                                                 recovery  of  these  charges  through  its  formula  rate.  On  a  related  issue,  FirstEnergy  joined  certain  other  PJM  transmission  owners  in  a   protest  of  MISO's  proposal  to  allocate  MVP  costs  to  energy  transactions  that  cross  MISO's  borders  into  the  PJM  Region.  On  January   22,  2015,  FERC  issued  an  order  establishing  a  paper  hearing  on  remand  from  the  Seventh  Circuit  of  the  issue  of  whether  any   limitation  on  "export  pricing"  for  sales  of  energy  from  MISO  into  PJM  is  justified  in  light  of  applicable  FERC  precedent.  Certain  PJM   transmission  owners,  including  FirstEnergy,  filed  an  initial  brief  asserting  that  FERC’s  prior  ruling  rejecting  MISO’s  proposed  MVP   export  charge  on  transactions  into  PJM  was  correct  and  should  be  re-­affirmed  on  remand.  The  briefs  and  replies  thereto  are  now   before  FERC  for  consideration.     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  costs  for  the  "Michigan  Thumb"  transmission   project  and  "legacy  RTEP"  transmission  projects  cannot  be  predicted  at  this  time.   2014  ATSI  Formula  Rate  Filing   On   October   31,   2014,  ATSI   filed   a   proposal   with   FERC   to   change   the   structure   of   its   formula   rate   from   an   “historical   looking”   approach,  where  transmission  rates  reflect  actual  costs  for  the  prior  year,  to  a  “forward  looking”  approach,  where  transmission  rates   would  be  based  on  the  estimated  costs  for  the  coming  year,  with  an  annual  true  up.  On  December  31,  2014,  FERC  issued  an  order   accepting  ATSI's  filing  effective  January  1,  2015,  subject  to  refund  and  the  outcome  of  hearing  and  settlement  proceedings.  FERC   subsequently  issued  an  order  on  October  29,  2015,  accepting  a  settlement  agreement  on  the  forward-­looking  formula  rate,  subject  to   minor   compliance   requirements.   The   settlement   agreement   provides   for   certain   changes   to  ATSI's   formula   rate   template   and   protocols,  and  also  changes  ATSI's  ROE  from  12.38%  to  the  following  values:  (i)  12.38%  from  January  1,  2015  through  June  30,   2015;;  (ii)  11.06%  from  July  1,  2015  through  December  31,  2015;;  and  (iii)  10.38%  from  January  1,  2016,  unless  changed  pursuant  to   section  205  or  206  of  the  FPA,  provided  the  effective  date  for  any  change  cannot  be  earlier  than  January  1,  2018.     Transfer  of  Transmission  Assets  to  MAIT     On  June  10,  2015,  MAIT,  a  Delaware  limited  liability  company,  was  formed  as  a  new  transmission-­only  subsidiary  of  FET  for  the   purposes  of  owning  and  operating  all  FERC-­jurisdictional  transmission  assets  of  JCP&L,  ME  and  PN  following  the  receipt  of  all   necessary  state  and  federal  regulatory  approvals.  On  June  19,  2015,  JCP&L,  PN,  ME,  FET,  and  MAIT  made  filings  with  FERC,  the   NJBPU,  and  the  PPUC  requesting  authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT.  Additionally,   the  filings  requested  approval  from  the  NJBPU  and  PPUC,  as  applicable,  of:  (i)  a  lease  to  MAIT  of  real  property  and  rights-­of-­way   associated  with  the  utilities'  transmission  assets;;  (ii)  a  Mutual  Assistance  Agreement;;  (iii)  MAIT  being  deemed  a  public  utility  under   state   law;;   (iv)   MAIT's   participation   in   FE's   regulated   companies'   money   pool;;   and   (v)   certain   affiliated   interest   agreements.   If   approved,  JCP&L,  ME,  and  PN  will  contribute  their  transmission  assets  at  net  book  value  and  an  allocated  portion  of  goodwill  in  a  tax-­ free  exchange  to  MAIT,  which  will  operate  similar  to  FET's  two  existing  stand-­alone  transmission  subsidiaries,  ATSI  and  TrAIL.  MAIT's   transmission  facilities  will  remain  under  the  functional  control  of  PJM,  and  PJM  will  provide  transmission  service  using  these  facilities   under  the  PJM  Tariff.  During  the  third  quarter  of  2015,  FirstEnergy  responded  to  FERC  Staff's  request  for  additional  information   regarding  the  application.  FERC  approval  is  expected  during  the  first  quarter  of  2016  with  final  decisions  expected  from  the  NJBPU   and  PPUC  by  mid-­2016.  Following  FERC  approval  of  the  transfer,  MAIT  expects  to  file  a  Section  204  application  with  FERC,  and   other  necessary  filings  with  the  PPUC  and  the  NJBPU,  seeking  authorization  to  issue  equity  to  FET,  JCP&L,  PN  and  ME  for  their   respective  contributions,  and  to  issue  debt.  MAIT  will  also  make  a  Section  205  formula  rate  application  with  FERC  to  establish  its   transmission  rate.  See  New  Jersey  and  Pennsylvania  in  State  Regulation  above  for  further  discussion  of  this  transaction.     California  Claims  Matters   In  October  2006,  several  California  governmental  and  utility  parties  presented  AE  Supply  with  a  settlement  proposal  to  resolve   alleged  overcharges  for  power  sales  by  AE  Supply  to  the  California  Energy  Resource  Scheduling  division  of  the  CDWR  during  2001.   The  settlement  proposal  claims  that  CDWR  is  owed  approximately  $190  million  for  these  alleged  overcharges.  This  proposal  was   made  in  the  context  of  mediation  efforts  by  FERC  and  the  Ninth  Circuit  in  several  pending  proceedings  to  resolve  all  outstanding   refund  and  other  claims,  including  claims  of  alleged  price  manipulation  in  the  California  energy  markets  during  2000  and  2001.  The   Ninth  Circuit  had  previously  remanded  one  of  those  proceedings  to  FERC,  which  dismissed  the  claims  of  the  California  parties  in  May   2011.  The  California  parties  appealed  FERC's  decision  back  to  the  Ninth  Circuit.  AE  Supply  joined  with  other  intervenors  in  the  case   and  filed  a  brief  in  support  of  FERC's  dismissal  of  the  case.  On  April  29,  2015,  the  Ninth  Circuit  remanded  the  case  to  FERC  for   further  proceedings.  On  November  3,  2015,  FERC  set  for  hearing  and  settlement  procedures  the  remanded  issue  of  whether  any   individual   public   utility   seller’s   violation   of   FERC’s   market-­based   rate   quarterly   reporting   requirement   led   to   an   unjust   and   unreasonable  rate  for  that  particular  seller  in  California  during  the  2000-­2001  period.  Settlement  discussions  under  a  FERC-­appointed   settlement  judge  are  ongoing.  Requests  for  rehearing  or  clarification  of  FERC’s  November  3,  2015  order  by  various  parties,  including   AE  Supply,  remain  pending.     In  another  proceeding,  in  May  2009,  the  California  Attorney  General,  on  behalf  of  certain  California  parties,  filed  a  complaint  with   FERC  against  various  sellers,  including  AE  Supply,  again  seeking  refunds  for  transactions  in  the  California  energy  markets  during   2000  and  2001.  The  above-­noted  transactions  with  CDWR  are  the  basis  for  including  AE  Supply  in  this  complaint.  AE  Supply  and   other  parties  filed  motions  to  dismiss,  which  FERC  granted.  The  California  Attorney  General  appealed  FERC's  dismissal  of  its   complaint  to  the  Ninth  Circuit,  which  has  consolidated  the  case  with  other  pending  appeals  related  to  California  refund  claims,  and   stayed  the  proceedings  pending  further  order.   The  outcome  of  either  of  the  above  matters  or  estimate  of  loss  or  range  of  loss  cannot  be  predicted  at  this  time.   PATH  Transmission  Project   On  August  24,  2012,  the  PJM  Board  of  Managers  canceled  the  PATH  project,  a  proposed  transmission  line  from  West  Virginia   through  Virginia  and  into  Maryland  which  PJM  had  previously  suspended  in  February  2011.  As  a  result  of  PJM  canceling  the  project,   approximately  $62  million  and  approximately  $59  million  in  costs  incurred  by  PATH-­Allegheny  and  PATH-­WV  (an  equity  method   investment  for  FE),  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   settlement   proceedings   and   hearing   if   the   parties   could   not   agree   to   a   settlement.   On   March   24,   2014,   the   FERC   Chief  ALJ   terminated  settlement  proceedings  and  appointed  an  ALJ  to  preside  over  the  hearing  phase  of  the  case,  including  discovery  and   additional  pleadings  leading  up  to  hearing,  which  subsequently  included  the  parties  addressing  the  application  of  FERC's  Opinion  No.   531,  discussed  below,  to  the  PATH  proceeding.  On  September  14,  2015,  the  ALJ  issued  his  initial  decision,  disallowing  recovery  of   certain  costs.  The  initial  decision  and  exceptions  thereto  are  now  before  FERC  for  review  and  a  final  order.  FirstEnergy  continues  to   believe  the  costs  are  recoverable,  subject  to  final  ruling  from  FERC.     FERC  Opinion  No.  531     On  June  19,  2014,  FERC  issued  Opinion  No.  531,  in  which  FERC  revised  its  approach  for  calculating  the  discounted  cash  flow   element  of  FERC’s  ROE  methodology,  and  announced  the  potential  for  a  qualitative  adjustment  to  the  ROE  methodology  results.   Under  the  old  methodology,  FERC  used  a  five-­year  forecast  for  the  dividend  growth  variable,  whereas  going  forward  the  growth   variable  will  consist  of  two  parts:  (a)  a  five-­year  forecast  for  dividend  growth  (2/3  weight);;  and  (b)  a  long-­term  dividend  growth  forecast   based  on  a  forecast  for  the  U.S.  economy  (1/3  weight).  Regarding  the  qualitative  adjustment,  for  single-­utility  rate  cases  FERC   formerly  pegged  ROE  at  the  median  of  the  “zone  of  reasonableness”  that  came  out  of  the  ROE  formula,  whereas  going  forward,   FERC  may  rely  on  record  evidence  to  make  qualitative  adjustments  to  the  outcome  of  the  ROE  methodology  in  order  to  reach  a  level   sufficient   to   attract   future   investment.   On   October   16,   2014,   FERC   issued   its   Opinion   No.   531-­A,   applying   the   revised   ROE   methodology  to  certain  ISO  New  England  transmission  owners,  and  on  March  3,  2015,  FERC  issued  Opinion  No.  531-­B  affirming  its   prior  rulings.  Appeals  of  Opinion  Nos.  531,  532-­A  and  531-­B  are  pending  before  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit.   FirstEnergy  is  evaluating  the  potential  impact  of  Opinion  No.  531  on  the  authorized  ROE  of  our  FERC-­regulated  transmission  utilities   and  the  cost-­of-­service  wholesale  power  generation  transactions  of  MP.     MISO  Capacity  Portability   On  June  11,  2012,  in  response  to  certain  arguments  advanced  by  MISO,  FERC  requested  comments  regarding  whether  existing   rules  on  transfer  capability  act  as  barriers  to  the  delivery  of  capacity  between  MISO  and  PJM.  FirstEnergy  and  other  parties  submitted   filings   arguing   that   MISO's   concerns   largely   are   without   foundation,   FERC   did   not   mandate   a   solution   in   response   to   MISO's   concerns.  At  FERC's  direction,  in  May,  2015,  PJM,  MISO,  and  their  respective  independent  market  monitors  provided  additional   information  on  their  various  joint  issues  surrounding  the  PJM/MISO  seam  to  assist  FERC's  understanding  of  the  issues  and  what,  if   any,  additional  steps  FERC  should  take  to  improve  the  efficiency  of  operations  at  the  PJM/MISO  seam.  Stakeholders,  including  FESC   on  behalf  of  certain  of  its  affiliates  and  as  part  of  a  coalition  of  certain  other  PJM  utilities,  filed  responses  to  the  RTO  submissions.  The   various  submissions  and  responses  are  now  before  FERC  for  consideration.     Changes  to  the  criteria  and  qualifications  for  participation  in  the  PJM  RPM  capacity  auctions  could  have  a  significant  impact  on  the   outcome  of  those  auctions,  including  a  negative  impact  on  the  prices  at  which  those  auctions  would  clear.     FTR  Underfunding  Complaint   In  PJM,  FTRs  are  a  mechanism  to  hedge  congestion  and  operate  as  a  financial  replacement  for  physical  firm  transmission  service.   FTRs   are   financially-­settled   instruments   that   entitle   the   holder   to   a   stream   of   revenues   based   on   the   hourly   congestion   price   differences  across  a  specific  transmission  path  in  the  PJM  Day-­ahead  Energy  Market.  Due  to  certain  language  in  the  PJM  Tariff,  the   funds  that  are  set  aside  to  pay  FTRs  can  be  diverted  to  other  uses,  which  may  result  in  “underfunding”  of  FTR  payments.  On   February  15,  2013,  FES  and  AE  Supply  filed  a  renewed  complaint  with  FERC  for  the  purpose  of  changing  the  PJM  Tariff  to  eliminate   FTR  underfunding.  On  June  5,  2013,  FERC  issued  an  order  denying  the  complaint,  and  on  June  8,  2015,  denied  a  request  for   rehearing  of  the  June  5,  2013  order.     122   123                                                     recovery  of  these  charges  through  its  formula  rate.  On  a  related  issue,  FirstEnergy  joined  certain  other  PJM  transmission  owners  in  a   protest  of  MISO's  proposal  to  allocate  MVP  costs  to  energy  transactions  that  cross  MISO's  borders  into  the  PJM  Region.  On  January   22,  2015,  FERC  issued  an  order  establishing  a  paper  hearing  on  remand  from  the  Seventh  Circuit  of  the  issue  of  whether  any   limitation  on  "export  pricing"  for  sales  of  energy  from  MISO  into  PJM  is  justified  in  light  of  applicable  FERC  precedent.  Certain  PJM   transmission  owners,  including  FirstEnergy,  filed  an  initial  brief  asserting  that  FERC’s  prior  ruling  rejecting  MISO’s  proposed  MVP   2000  and  2001.  The  above-­noted  transactions  with  CDWR  are  the  basis  for  including  AE  Supply  in  this  complaint.  AE  Supply  and   other  parties  filed  motions  to  dismiss,  which  FERC  granted.  The  California  Attorney  General  appealed  FERC's  dismissal  of  its   complaint  to  the  Ninth  Circuit,  which  has  consolidated  the  case  with  other  pending  appeals  related  to  California  refund  claims,  and   stayed  the  proceedings  pending  further  order.   export  charge  on  transactions  into  PJM  was  correct  and  should  be  re-­affirmed  on  remand.  The  briefs  and  replies  thereto  are  now   The  outcome  of  either  of  the  above  matters  or  estimate  of  loss  or  range  of  loss  cannot  be  predicted  at  this  time.   PATH  Transmission  Project   On  August  24,  2012,  the  PJM  Board  of  Managers  canceled  the  PATH  project,  a  proposed  transmission  line  from  West  Virginia   through  Virginia  and  into  Maryland  which  PJM  had  previously  suspended  in  February  2011.  As  a  result  of  PJM  canceling  the  project,   approximately  $62  million  and  approximately  $59  million  in  costs  incurred  by  PATH-­Allegheny  and  PATH-­WV  (an  equity  method   investment  for  FE),  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   settlement   proceedings   and   hearing   if   the   parties   could   not   agree   to   a   settlement.   On   March   24,   2014,   the   FERC   Chief  ALJ   terminated  settlement  proceedings  and  appointed  an  ALJ  to  preside  over  the  hearing  phase  of  the  case,  including  discovery  and   additional  pleadings  leading  up  to  hearing,  which  subsequently  included  the  parties  addressing  the  application  of  FERC's  Opinion  No.   531,  discussed  below,  to  the  PATH  proceeding.  On  September  14,  2015,  the  ALJ  issued  his  initial  decision,  disallowing  recovery  of   certain  costs.  The  initial  decision  and  exceptions  thereto  are  now  before  FERC  for  review  and  a  final  order.  FirstEnergy  continues  to   believe  the  costs  are  recoverable,  subject  to  final  ruling  from  FERC.     minor   compliance   requirements.   The   settlement   agreement   provides   for   certain   changes   to  ATSI's   formula   rate   template   and   FERC  Opinion  No.  531     free  exchange  to  MAIT,  which  will  operate  similar  to  FET's  two  existing  stand-­alone  transmission  subsidiaries,  ATSI  and  TrAIL.  MAIT's   MISO  Capacity  Portability   On  June  19,  2014,  FERC  issued  Opinion  No.  531,  in  which  FERC  revised  its  approach  for  calculating  the  discounted  cash  flow   element  of  FERC’s  ROE  methodology,  and  announced  the  potential  for  a  qualitative  adjustment  to  the  ROE  methodology  results.   Under  the  old  methodology,  FERC  used  a  five-­year  forecast  for  the  dividend  growth  variable,  whereas  going  forward  the  growth   variable  will  consist  of  two  parts:  (a)  a  five-­year  forecast  for  dividend  growth  (2/3  weight);;  and  (b)  a  long-­term  dividend  growth  forecast   based  on  a  forecast  for  the  U.S.  economy  (1/3  weight).  Regarding  the  qualitative  adjustment,  for  single-­utility  rate  cases  FERC   formerly  pegged  ROE  at  the  median  of  the  “zone  of  reasonableness”  that  came  out  of  the  ROE  formula,  whereas  going  forward,   FERC  may  rely  on  record  evidence  to  make  qualitative  adjustments  to  the  outcome  of  the  ROE  methodology  in  order  to  reach  a  level   sufficient   to   attract   future   investment.   On   October   16,   2014,   FERC   issued   its   Opinion   No.   531-­A,   applying   the   revised   ROE   methodology  to  certain  ISO  New  England  transmission  owners,  and  on  March  3,  2015,  FERC  issued  Opinion  No.  531-­B  affirming  its   prior  rulings.  Appeals  of  Opinion  Nos.  531,  532-­A  and  531-­B  are  pending  before  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit.   FirstEnergy  is  evaluating  the  potential  impact  of  Opinion  No.  531  on  the  authorized  ROE  of  our  FERC-­regulated  transmission  utilities   and  the  cost-­of-­service  wholesale  power  generation  transactions  of  MP.     On  June  11,  2012,  in  response  to  certain  arguments  advanced  by  MISO,  FERC  requested  comments  regarding  whether  existing   rules  on  transfer  capability  act  as  barriers  to  the  delivery  of  capacity  between  MISO  and  PJM.  FirstEnergy  and  other  parties  submitted   filings   arguing   that   MISO's   concerns   largely   are   without   foundation,   FERC   did   not   mandate   a   solution   in   response   to   MISO's   concerns.  At  FERC's  direction,  in  May,  2015,  PJM,  MISO,  and  their  respective  independent  market  monitors  provided  additional   information  on  their  various  joint  issues  surrounding  the  PJM/MISO  seam  to  assist  FERC's  understanding  of  the  issues  and  what,  if   any,  additional  steps  FERC  should  take  to  improve  the  efficiency  of  operations  at  the  PJM/MISO  seam.  Stakeholders,  including  FESC   on  behalf  of  certain  of  its  affiliates  and  as  part  of  a  coalition  of  certain  other  PJM  utilities,  filed  responses  to  the  RTO  submissions.  The   various  submissions  and  responses  are  now  before  FERC  for  consideration.     Changes  to  the  criteria  and  qualifications  for  participation  in  the  PJM  RPM  capacity  auctions  could  have  a  significant  impact  on  the   outcome  of  those  auctions,  including  a  negative  impact  on  the  prices  at  which  those  auctions  would  clear.     FTR  Underfunding  Complaint   In  PJM,  FTRs  are  a  mechanism  to  hedge  congestion  and  operate  as  a  financial  replacement  for  physical  firm  transmission  service.   FTRs   are   financially-­settled   instruments   that   entitle   the   holder   to   a   stream   of   revenues   based   on   the   hourly   congestion   price   differences  across  a  specific  transmission  path  in  the  PJM  Day-­ahead  Energy  Market.  Due  to  certain  language  in  the  PJM  Tariff,  the   funds  that  are  set  aside  to  pay  FTRs  can  be  diverted  to  other  uses,  which  may  result  in  “underfunding”  of  FTR  payments.  On   February  15,  2013,  FES  and  AE  Supply  filed  a  renewed  complaint  with  FERC  for  the  purpose  of  changing  the  PJM  Tariff  to  eliminate   FTR  underfunding.  On  June  5,  2013,  FERC  issued  an  order  denying  the  complaint,  and  on  June  8,  2015,  denied  a  request  for   rehearing  of  the  June  5,  2013  order.     122   123   before  FERC  for  consideration.     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  costs  for  the  "Michigan  Thumb"  transmission   project  and  "legacy  RTEP"  transmission  projects  cannot  be  predicted  at  this  time.   2014  ATSI  Formula  Rate  Filing   On   October   31,   2014,  ATSI   filed   a   proposal   with   FERC   to   change   the   structure   of   its   formula   rate   from   an   “historical   looking”   approach,  where  transmission  rates  reflect  actual  costs  for  the  prior  year,  to  a  “forward  looking”  approach,  where  transmission  rates   would  be  based  on  the  estimated  costs  for  the  coming  year,  with  an  annual  true  up.  On  December  31,  2014,  FERC  issued  an  order   accepting  ATSI's  filing  effective  January  1,  2015,  subject  to  refund  and  the  outcome  of  hearing  and  settlement  proceedings.  FERC   subsequently  issued  an  order  on  October  29,  2015,  accepting  a  settlement  agreement  on  the  forward-­looking  formula  rate,  subject  to   protocols,  and  also  changes  ATSI's  ROE  from  12.38%  to  the  following  values:  (i)  12.38%  from  January  1,  2015  through  June  30,   2015;;  (ii)  11.06%  from  July  1,  2015  through  December  31,  2015;;  and  (iii)  10.38%  from  January  1,  2016,  unless  changed  pursuant  to   section  205  or  206  of  the  FPA,  provided  the  effective  date  for  any  change  cannot  be  earlier  than  January  1,  2018.     Transfer  of  Transmission  Assets  to  MAIT     On  June  10,  2015,  MAIT,  a  Delaware  limited  liability  company,  was  formed  as  a  new  transmission-­only  subsidiary  of  FET  for  the   purposes  of  owning  and  operating  all  FERC-­jurisdictional  transmission  assets  of  JCP&L,  ME  and  PN  following  the  receipt  of  all   necessary  state  and  federal  regulatory  approvals.  On  June  19,  2015,  JCP&L,  PN,  ME,  FET,  and  MAIT  made  filings  with  FERC,  the   NJBPU,  and  the  PPUC  requesting  authorization  for  JCP&L,  PN  and  ME  to  contribute  their  transmission  assets  to  MAIT.  Additionally,   the  filings  requested  approval  from  the  NJBPU  and  PPUC,  as  applicable,  of:  (i)  a  lease  to  MAIT  of  real  property  and  rights-­of-­way   associated  with  the  utilities'  transmission  assets;;  (ii)  a  Mutual  Assistance  Agreement;;  (iii)  MAIT  being  deemed  a  public  utility  under   state   law;;   (iv)   MAIT's   participation   in   FE's   regulated   companies'   money   pool;;   and   (v)   certain   affiliated   interest   agreements.   If   approved,  JCP&L,  ME,  and  PN  will  contribute  their  transmission  assets  at  net  book  value  and  an  allocated  portion  of  goodwill  in  a  tax-­ transmission  facilities  will  remain  under  the  functional  control  of  PJM,  and  PJM  will  provide  transmission  service  using  these  facilities   under  the  PJM  Tariff.  During  the  third  quarter  of  2015,  FirstEnergy  responded  to  FERC  Staff's  request  for  additional  information   regarding  the  application.  FERC  approval  is  expected  during  the  first  quarter  of  2016  with  final  decisions  expected  from  the  NJBPU   and  PPUC  by  mid-­2016.  Following  FERC  approval  of  the  transfer,  MAIT  expects  to  file  a  Section  204  application  with  FERC,  and   other  necessary  filings  with  the  PPUC  and  the  NJBPU,  seeking  authorization  to  issue  equity  to  FET,  JCP&L,  PN  and  ME  for  their   respective  contributions,  and  to  issue  debt.  MAIT  will  also  make  a  Section  205  formula  rate  application  with  FERC  to  establish  its   transmission  rate.  See  New  Jersey  and  Pennsylvania  in  State  Regulation  above  for  further  discussion  of  this  transaction.     California  Claims  Matters   In  October  2006,  several  California  governmental  and  utility  parties  presented  AE  Supply  with  a  settlement  proposal  to  resolve   alleged  overcharges  for  power  sales  by  AE  Supply  to  the  California  Energy  Resource  Scheduling  division  of  the  CDWR  during  2001.   The  settlement  proposal  claims  that  CDWR  is  owed  approximately  $190  million  for  these  alleged  overcharges.  This  proposal  was   made  in  the  context  of  mediation  efforts  by  FERC  and  the  Ninth  Circuit  in  several  pending  proceedings  to  resolve  all  outstanding   refund  and  other  claims,  including  claims  of  alleged  price  manipulation  in  the  California  energy  markets  during  2000  and  2001.  The   Ninth  Circuit  had  previously  remanded  one  of  those  proceedings  to  FERC,  which  dismissed  the  claims  of  the  California  parties  in  May   2011.  The  California  parties  appealed  FERC's  decision  back  to  the  Ninth  Circuit.  AE  Supply  joined  with  other  intervenors  in  the  case   and  filed  a  brief  in  support  of  FERC's  dismissal  of  the  case.  On  April  29,  2015,  the  Ninth  Circuit  remanded  the  case  to  FERC  for   further  proceedings.  On  November  3,  2015,  FERC  set  for  hearing  and  settlement  procedures  the  remanded  issue  of  whether  any   individual   public   utility   seller’s   violation   of   FERC’s   market-­based   rate   quarterly   reporting   requirement   led   to   an   unjust   and   unreasonable  rate  for  that  particular  seller  in  California  during  the  2000-­2001  period.  Settlement  discussions  under  a  FERC-­appointed   settlement  judge  are  ongoing.  Requests  for  rehearing  or  clarification  of  FERC’s  November  3,  2015  order  by  various  parties,  including   AE  Supply,  remain  pending.     In  another  proceeding,  in  May  2009,  the  California  Attorney  General,  on  behalf  of  certain  California  parties,  filed  a  complaint  with   FERC  against  various  sellers,  including  AE  Supply,  again  seeking  refunds  for  transactions  in  the  California  energy  markets  during                                                     PJM  Market  Reform:  PJM  Capacity  Performance  Proposal   In  December  2014,  PJM  submitted  proposed  “Capacity  Performance”  reforms  of  its  RPM  capacity  and  energy  markets.  On  June  9,   2015,  FERC  issued  an  order  conditionally  approving  the  bulk  of  the  proposed  Capacity  Performance  reforms  with  an  effective  date  of   April  1,  2015,  and  directed  PJM  to  make  a  compliance  filing  reflecting  the  mandate  of  FERC’s  order.  On  July  9,  2015,  several  parties,   including  FESC  on  behalf  of  certain  of  its  affiliates,  submitted  requests  for  rehearing  for  FERC's  June  9,  2015  order,  and  PJM   submitted  its  compliance  filing  as  directed  by  the  order.  The  requests  for  rehearing  and  PJM's  compliance  filing  are  pending  before   FERC.     In  August  and  September  2015,  PJM  conducted  RPM  auctions  pursuant  to  the  new  Capacity  Performance  rules.  FirstEnergy’s  net   competitive  capacity  position  as  a  result  of  the  BRA  and  Capacity  Performance  transition  auctions  is  as  follows:       2016  -­  2017   2017  -­  2018   2018  -­  2019*   Legacy   Obligation   Capacity   Performance   Legacy   Obligation   Capacity   Performance   Base   Generation   Capacity   Performance   (MW)   ($/MWD)   (MW)   2,765   $114.23   4,210   $59.37   3,675   875   $119.13   —   135   ($/MWD)   $134.00   $134.00   $134.00   ATSI   RTO   All  Other   Zones   ($/MWD)   ($/MWD)   (MW)   (MW)   (MW)   $149.98   6,245   375   $120.00   6,245   $151.50   —   985   $120.00   3,565   $151.50   240   $149.98   3,930   $151.50   150   $120.00   —   ($/MWD)   20   35   **   (MW)   ($/MWD)   $164.77   $164.77   **   3,775   7,885   1,510   9,810   275   10,195   *Approximately  885  MWs  remain  uncommitted  for  the  2018/2019  delivery  year.       **Base  Generation:  10  MWs  cleared  at  $200.21/MWD  and  25  MWs  cleared  at  $149.98/MWD.  Capacity  Performance:  5  MWs  cleared  at   $215.00/MWD  and  15  MWs  cleared  at  $164.77/MWD.       PJM  Market  Reform:  FERC  Order  No.  745  -­  DR   On  May  23,  2014,  a  divided  three-­judge  panel  of  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  issued  an  opinion  vacating  FERC   Order   No.   745,   which   required   that,   under   certain   parameters,   DR   participating   in   organized   wholesale   energy   markets   be   compensated  at  LMP.  The  majority  concluded  that  DR  is  a  retail  service,  and  therefore  falls  under  state,  and  not  federal,  jurisdiction,   and  that  FERC,  therefore,  lacks  jurisdiction  to  regulate  DR.  The  majority  also  found  that  even  if  FERC  had  jurisdiction  over  DR,  Order   No.  745  would  be  arbitrary  and  capricious  because,  under  its  requirements,  DR  was  inappropriately  receiving  a  double  payment  (LMP   plus  the  savings  of  foregone  energy  purchases).  On  January  25,  2016,  the  United  States  Supreme  Court  reversed  the  opinion  of  the   U.S.  Court  of  Appeals  for  the  D.C.  Circuit  and  remanded  for  further  action,  finding  FERC  has  statutory  authority  under  the  FPA  to   regulate  compensation  of  demand  response  resources  in  FERC-­jurisdictional  wholesale  power  markets.  The  United  States  Supreme   Court  also  reversed  the  holding  that  FERC's  Order  No.  745  was  arbitrary  and  capricious,  finding  that  the  order  included  detailed   support  of  the  chosen  compensation  method.     On  May  23,  2014,  as  amended  September  22,  2014,  FESC,  on  behalf  of  its  affiliates  with  market-­based  rate  authorization,  filed  a   complaint  asking  FERC  to  issue  an  order  requiring  the  removal  of  all  portions  of  the  PJM  Tariff  allowing  or  requiring  DR  to  be  included   in  the  PJM  capacity  market,  with  a  refund  effective  date  of  May  23,  2014.  FESC  also  requested  that  the  results  of  the  May  2014  PJM   BRA  be  considered  void  and  legally  invalid  to  the  extent  that  DR  cleared  that  auction  because  the  participation  of  DR  in  that  auction   was  unlawful.  However,  in  light  of  the  United  States  Supreme  Court's  January  25,  2016  decision  discussed  above,  on  January  29,   2016,  FESC  withdrew  the  complaint.     15.  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   $13.5   billion   (assuming  103  units  licensed  to  operate)  for  a  single  nuclear  incident,  which  amount  is  covered  by:  (i)  private  insurance  amounting  to   $375  million;;  and  (ii)  $13.1  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  maximum  potential  assessment  under   these  provisions  would  be  $509  million  (NG-­$501  million)  per  incident  but  not  more  than  $76  million  (NG-­$75  million)  in  any  one  year   for  each  incident.   In  addition  to  the  public  liability  insurance  provided  pursuant  to  the  Price-­Anderson  Act,  FirstEnergy  has  also  obtained  insurance   coverage  in  limited  amounts  for  economic  loss  and  property  damage  arising  out  of  nuclear  incidents.  FirstEnergy  is  a  member  of   NEIL,  which  provides  coverage  (NEIL  I)  for  the  extra  expense  of  replacement  power  incurred  due  to  prolonged  accidental  outages  of   nuclear  units.  Under  NEIL  I,  FirstEnergy’s  subsidiaries  have  policies,  renewable  annually,  corresponding  to  their  respective  nuclear   2015:   124   125   interests,  which  provide  an  aggregate  indemnity  of  up  to  approximately  $1.96  billion  (NG-­$1.93  billion)  for  replacement  power  costs   incurred  during  an  outage  after  an  initial  20-­week  waiting  period.  Members  of  NEIL  I  pay  annual  premiums  and  are  subject  to   assessments  if  losses  exceed  the  accumulated  funds  available  to  the  insurer.  FirstEnergy’s  present  maximum  aggregate  assessment   for  incidents  at  any  covered  nuclear  facility  occurring  during  a  policy  year  would  be  approximately  $15  million  (NG-­$15  million).   FirstEnergy  is  insured  as  to  its  respective  nuclear  interests  under  property  damage  insurance  provided  by  NEIL  to  the  operating   company  for  each  plant.  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.  FirstEnergy  pays  annual  premiums  for  this  coverage  and   is  liable  for  retrospective  assessments  of  up  to  approximately  $83  million  (NG-­$81  million).   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  FirstEnergy’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,   2015,   outstanding   guarantees   and   other   assurances   aggregated   approximately   $3.7   billion,   consisting   of   parental  guarantees  ($583  million),  subsidiaries'  guarantees  ($2,137  million),  other  guarantees  ($300  million)  and  other  assurances   ($667  million).   Of  this  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  FES'  power  portfolio  exposure  as  of  December  31,  2015,  FES  has  posted  collateral  of  $188  million  and  AE   Supply  has  posted  no  collateral.  The  Regulated  Distribution  segment  has  posted  collateral  of  $1  million.   These  credit-­risk-­related  contingent  features  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  could  be  required.   Subsequent  to  the  occurrence  of  a  senior  unsecured  credit  rating  downgrade  to  below  S&P's  BBB-­  and  Moody's  Baa3,  or  a  “material   adverse  event,”  the  immediate  posting  of  collateral  or  accelerated  payments  may  be  required  of  FE  or  its  subsidiaries.  The  following   table  discloses  the  additional  credit  contingent  contractual  obligations  that  may  be  required  under  certain  events  as  of  December  31,                                                       PJM  Market  Reform:  PJM  Capacity  Performance  Proposal   In  December  2014,  PJM  submitted  proposed  “Capacity  Performance”  reforms  of  its  RPM  capacity  and  energy  markets.  On  June  9,   2015,  FERC  issued  an  order  conditionally  approving  the  bulk  of  the  proposed  Capacity  Performance  reforms  with  an  effective  date  of   April  1,  2015,  and  directed  PJM  to  make  a  compliance  filing  reflecting  the  mandate  of  FERC’s  order.  On  July  9,  2015,  several  parties,   including  FESC  on  behalf  of  certain  of  its  affiliates,  submitted  requests  for  rehearing  for  FERC's  June  9,  2015  order,  and  PJM   submitted  its  compliance  filing  as  directed  by  the  order.  The  requests  for  rehearing  and  PJM's  compliance  filing  are  pending  before   FERC.     In  August  and  September  2015,  PJM  conducted  RPM  auctions  pursuant  to  the  new  Capacity  Performance  rules.  FirstEnergy’s  net   competitive  capacity  position  as  a  result  of  the  BRA  and  Capacity  Performance  transition  auctions  is  as  follows:       2016  -­  2017   2017  -­  2018   2018  -­  2019*   Legacy   Obligation   Capacity   Performance   Legacy   Obligation   Capacity   Performance   Base   Generation   Capacity   Performance   (MW)   ($/MWD)   (MW)   ($/MWD)   (MW)   (MW)   ($/MWD)   ($/MWD)   (MW)   ($/MWD)   ($/MWD)   (MW)   2,765   $114.23   4,210   $134.00   375   $120.00   6,245   $151.50   —   $149.98   6,245   $164.77   $59.37   3,675   $134.00   985   $120.00   3,565   $151.50   240   $149.98   3,930   $164.77   $119.13   —   $134.00   150   $120.00   —   $151.50   35   **   20   **   ATSI   RTO   All  Other   Zones   875   135   3,775   7,885   1,510   9,810   275   10,195   *Approximately  885  MWs  remain  uncommitted  for  the  2018/2019  delivery  year.       **Base  Generation:  10  MWs  cleared  at  $200.21/MWD  and  25  MWs  cleared  at  $149.98/MWD.  Capacity  Performance:  5  MWs  cleared  at   $215.00/MWD  and  15  MWs  cleared  at  $164.77/MWD.       PJM  Market  Reform:  FERC  Order  No.  745  -­  DR   On  May  23,  2014,  a  divided  three-­judge  panel  of  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  issued  an  opinion  vacating  FERC   Order   No.   745,   which   required   that,   under   certain   parameters,   DR   participating   in   organized   wholesale   energy   markets   be   compensated  at  LMP.  The  majority  concluded  that  DR  is  a  retail  service,  and  therefore  falls  under  state,  and  not  federal,  jurisdiction,   and  that  FERC,  therefore,  lacks  jurisdiction  to  regulate  DR.  The  majority  also  found  that  even  if  FERC  had  jurisdiction  over  DR,  Order   No.  745  would  be  arbitrary  and  capricious  because,  under  its  requirements,  DR  was  inappropriately  receiving  a  double  payment  (LMP   plus  the  savings  of  foregone  energy  purchases).  On  January  25,  2016,  the  United  States  Supreme  Court  reversed  the  opinion  of  the   U.S.  Court  of  Appeals  for  the  D.C.  Circuit  and  remanded  for  further  action,  finding  FERC  has  statutory  authority  under  the  FPA  to   regulate  compensation  of  demand  response  resources  in  FERC-­jurisdictional  wholesale  power  markets.  The  United  States  Supreme   Court  also  reversed  the  holding  that  FERC's  Order  No.  745  was  arbitrary  and  capricious,  finding  that  the  order  included  detailed   support  of  the  chosen  compensation  method.     On  May  23,  2014,  as  amended  September  22,  2014,  FESC,  on  behalf  of  its  affiliates  with  market-­based  rate  authorization,  filed  a   complaint  asking  FERC  to  issue  an  order  requiring  the  removal  of  all  portions  of  the  PJM  Tariff  allowing  or  requiring  DR  to  be  included   in  the  PJM  capacity  market,  with  a  refund  effective  date  of  May  23,  2014.  FESC  also  requested  that  the  results  of  the  May  2014  PJM   BRA  be  considered  void  and  legally  invalid  to  the  extent  that  DR  cleared  that  auction  because  the  participation  of  DR  in  that  auction   was  unlawful.  However,  in  light  of  the  United  States  Supreme  Court's  January  25,  2016  decision  discussed  above,  on  January  29,   2016,  FESC  withdrew  the  complaint.     15.  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   $13.5   billion   (assuming  103  units  licensed  to  operate)  for  a  single  nuclear  incident,  which  amount  is  covered  by:  (i)  private  insurance  amounting  to   $375  million;;  and  (ii)  $13.1  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  maximum  potential  assessment  under   these  provisions  would  be  $509  million  (NG-­$501  million)  per  incident  but  not  more  than  $76  million  (NG-­$75  million)  in  any  one  year   for  each  incident.   In  addition  to  the  public  liability  insurance  provided  pursuant  to  the  Price-­Anderson  Act,  FirstEnergy  has  also  obtained  insurance   coverage  in  limited  amounts  for  economic  loss  and  property  damage  arising  out  of  nuclear  incidents.  FirstEnergy  is  a  member  of   NEIL,  which  provides  coverage  (NEIL  I)  for  the  extra  expense  of  replacement  power  incurred  due  to  prolonged  accidental  outages  of   nuclear  units.  Under  NEIL  I,  FirstEnergy’s  subsidiaries  have  policies,  renewable  annually,  corresponding  to  their  respective  nuclear   interests,  which  provide  an  aggregate  indemnity  of  up  to  approximately  $1.96  billion  (NG-­$1.93  billion)  for  replacement  power  costs   incurred  during  an  outage  after  an  initial  20-­week  waiting  period.  Members  of  NEIL  I  pay  annual  premiums  and  are  subject  to   assessments  if  losses  exceed  the  accumulated  funds  available  to  the  insurer.  FirstEnergy’s  present  maximum  aggregate  assessment   for  incidents  at  any  covered  nuclear  facility  occurring  during  a  policy  year  would  be  approximately  $15  million  (NG-­$15  million).   FirstEnergy  is  insured  as  to  its  respective  nuclear  interests  under  property  damage  insurance  provided  by  NEIL  to  the  operating   company  for  each  plant.  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.  FirstEnergy  pays  annual  premiums  for  this  coverage  and   is  liable  for  retrospective  assessments  of  up  to  approximately  $83  million  (NG-­$81  million).   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  FirstEnergy’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,   2015,   outstanding   guarantees   and   other   assurances   aggregated   approximately   $3.7   billion,   consisting   of   parental  guarantees  ($583  million),  subsidiaries'  guarantees  ($2,137  million),  other  guarantees  ($300  million)  and  other  assurances   ($667  million).   Of  this  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  FES'  power  portfolio  exposure  as  of  December  31,  2015,  FES  has  posted  collateral  of  $188  million  and  AE   Supply  has  posted  no  collateral.  The  Regulated  Distribution  segment  has  posted  collateral  of  $1  million.   These  credit-­risk-­related  contingent  features  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  could  be  required.   Subsequent  to  the  occurrence  of  a  senior  unsecured  credit  rating  downgrade  to  below  S&P's  BBB-­  and  Moody's  Baa3,  or  a  “material   adverse  event,”  the  immediate  posting  of  collateral  or  accelerated  payments  may  be  required  of  FE  or  its  subsidiaries.  The  following   table  discloses  the  additional  credit  contingent  contractual  obligations  that  may  be  required  under  certain  events  as  of  December  31,   2015:   124   125                                                       BB+/Ba1  Credit  Ratings   Full  impact  of  credit  contingent  contractual  obligations   Collateral  Provisions   FES   AE  Supply   Utilities   Total   198   $   231   $   363   $   (In  millions)   6   $   6   $   16   $   41   $   41   $   41   $   245   278   420   Split  Rating  (One  rating  agency's  rating  below  investment  grade)   $   $   $   Excluded   from   the   preceding   chart   are   the   potential   collateral   obligations   due   to   affiliate   transactions   between   the   Regulated   Distribution  segment  and  CES  segment.  As  of  December  31,  2015,  neither  FES  nor  AE  Supply  had  any  collateral  posted  with  their   affiliates.  In  the  event  of  a  senior  unsecured  credit  rating  downgrade  to  below  S&P's  BB-­  or  Moody's  Ba3,  FES  would  be  required  to   post  $8  million  with  affiliated  parties.     OTHER  COMMITMENTS  AND  CONTINGENCIES   FirstEnergy  is  a  guarantor  under  a  syndicated  senior  secured  term  loan  facility  due  March  3,  2020,  under  which  Global  Holding   borrowed  $300  million.  In  addition  to  FirstEnergy,  Signal  Peak,  Global  Rail,  Global  Mining  Group,  LLC  and  Global  Coal  Sales  Group,   LLC,   each   being   a   direct   or   indirect   subsidiary   of   Global   Holding,   have   also   provided   their   joint   and   several   guaranties   of   the   obligations  of  Global  Holding  under  the  facility.   In  connection  with  Global  Holding's  term  loan  facility,  a  portion  of  Global  Holding's  direct  and  indirect  membership  interests  in  Signal   Peak,  Global  Rail  and  their  affiliates  along  with  each  of  FEV's  and  WMB  Marketing  Ventures,LLC's    33-­1/3%  membership  interests  in   Global  Holding,  are  pledged  to  the  lenders  under  Global  Holding's  facility  as  collateral.  Failure  by  Global  Holding  to  meet  the  terms   and  conditions  under  its  term  loan  facility  could  require  FirstEnergy  to  be  obligated  under  the  provisions  of  its  guarantee,  resulting  in   consolidation  of  Global  Holding  by  FE.   During  the  first  quarter  of  2015,  a  subsidiary  of  Global  Holding  eliminated  its  right  to  put  2  million  tons  annually  through  2024  from  the   Signal  Peak  mine  to  FG  in  exchange  for  FirstEnergy  extending  its  guarantee  under  Global  Holding's  $300  million  senior  secured  term   loan  facility  through  2020,  resulting  in  a  pre-­tax  charge  of  $24  million.  See  Note  8,  Variable  Interest  Entities,  and  Note  1,  Organization,   Basis  of  Presentation  and  Significant  Accounting  Policies  -­  Investments,  for  additional  information  regarding  FEV's  investment  in   Global  Holding.     ENVIRONMENTAL  MATTERS   Various  federal,  state  and  local  authorities  regulate  FirstEnergy  with  regard  to  air  and  water  quality  and  other  environmental  matters.   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  U.S.  Court  of  Appeals  for  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  EPA’s  regulatory  approach  under  CSAPR,  but  questioning  whether  EPA  required  upwind   states  to  reduce  emissions  by  more  than  their  contribution  to  air  pollution  in  downwind  states.  EPA  proposed  a  CSAPR  update  rule  on   November  16,  2015,  that  would  reduce  summertime  NOx  emissions  from  power  plants  in  23  states  in  the  eastern  U.S.,  including   Ohio,  Pennsylvania  and  West  Virginia,  beginning  in  2017.  Depending  on  how  the  EPA  and  the  states  implement  CSAPR,  the  future   cost  of  compliance  may  be  substantial  and  changes  to  FirstEnergy's  and  FES'  operations  may  result.   EPA  tightened  the  primary  and  secondary  NAAQS  for  ozone  from  the  2008  standard  levels  of  75  PPB  to  70  PPB  on  October  1,  2015.   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  EPA  will  designate  those  counties  that  fail  to  attain  the  new  2015  ozone  NAAQS  by  October  1,  2017.  States  will  then   have  roughly  three  years  to  develop  implementation  plans  to  attain  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  substantial  and  changes  to  FirstEnergy’s  and   FES’  operations  may  result.     MATS  imposes  emission  limits  for  mercury,  PM,  and  HCl  for  all  existing  and  new  fossil  fuel  fired  electric  generating  units  effective  in   April  2015  with  averaging  of  emissions  from  multiple  units  located  at  a  single  plant.  Under  the  CAA,  state  permitting  authorities  can   126   127   grant  an  additional  compliance  year  through  April  2016,  as  needed,  including  instances  when  necessary  to  maintain  reliability  where   electric  generating  units  are  being  closed.  On  December  28,  2012,  the  WVDEP  granted  a  conditional  extension  through  April  16,   2016  for  MATS  compliance  at  the  Fort  Martin,  Harrison  and  Pleasants  plants.  On  March  20,  2013,  the  PA  DEP  granted  an  extension   through  April  16,  2016  for  MATS  compliance  at  the  Hatfield's  Ferry  and  Bruce  Mansfield  plants.  On  February  5,  2015,  the  OEPA   granted  an  extension  through  April  16,  2016  for  MATS  compliance  at  the  Bay  Shore  and  Sammis  plants.  Nearly  all  spending  for   MATS  compliance  at  Bay  Shore  and  Sammis  has  been  completed  through  2014.  In  addition,  an  EPA  enforcement  policy  document   contemplates  up  to  an  additional  year  to  achieve  compliance,  through  April  2017,  under  certain  circumstances  for  reliability  critical   units.  On  June  29,  2015,  the  United  States  Supreme  Court  reversed  a  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  decision  that  upheld   MATS,  rejecting  EPA’s  regulatory  approach  that  costs  are  not  relevant  to  the  decision  of  whether  or  not  to  regulate  power  plant   emissions  under  Section  112  of  the  Clean  Air  Act  and  remanded  the  case  back  to  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  for   further  proceedings.  The  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  later  remanded  MATS  back  to  EPA,  who  represented  to  such  court   that  the  EPA  is  on  track  to  issue  a  finalized  MATS  by  April  15,  2016.  Subject  to  the  outcome  of  any  further  proceedings  before  the   U.S.   Court   of  Appeals   for   the   D.C.   Circuit   and   how   the   MATS   are   ultimately   implemented,   FirstEnergy's   total   capital   cost   for   compliance  (over  the  2012  to  2018  time  period)  is  currently  expected  to  be  approximately  $345  million  (CES  segment  of  $168  million   and  Regulated  Distribution  segment  of  $177  million),  of  which  $202  million  has  been  spent  through  December  31,  2015  ($80  million   at  CES  and  $122  million  at  Regulated  Distribution).     As  a  result  of  MATS,  Eastlake  Units  1-­3,  Ashtabula  Unit  5  and  Lake  Shore  Unit  18  were  deactivated  in  April  2015,  which  completes   the  deactivation  of  5,429  MW  of  coal-­fired  plants  since  2012.       On  August  3,  2015,  FG,  a  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  that  excuses  FG’s  performance  under  its   coal  transportation  contract  with  these  parties.  Specifically,  the  dispute  arises  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,  those  plants  were  deactivated  by  April  16,  2015.  In  January  2012,  FG  notified   BNSF  and  CSX  that  MATS  constituted  a  force  majeure  event  under  the  contract  that  excused  FG’s  further  performance.  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  including,  but  not  limited  to,  lost  profits  under  the  contract  through  2025.  As  part  of  its  statement  of  claim,  a  right  to   liquidated  damages  is  alleged.  The  arbitration  panel  has  determined  to  consolidate  the  claims  with  a  liability  hearing  expected  to   begin   in   November   2016,   and,   if   necessary,   a   damages   hearing   is   expected   to   begin   in   May   2017.  The   decision   on   liability   is   expected  to  be  issued  within  sixty  days  from  the  end  of  the  liability  hearings.  FirstEnergy  and  FES  continue  to  believe  that  MATS   constitutes  a  force  majeure  event  under  the  contract  as  it  relates  to  the  deactivated  plants  and  that  FG’s  performance  under  the   contract   is   therefore   excused.   FirstEnergy   and   FES   intend   to   vigorously   assert   their   position   in   the   arbitration   proceedings.   If,   however,  the  arbitration  panel  rules  in  favor  of  BNSF  and  CSX,  the  results  of  operations  and  financial  condition  of  both  FirstEnergy   and  FES  could  be  materially  adversely  impacted.  FirstEnergy  and  FES  are  unable  to  estimate  the  loss  or  range  of  loss.       FG  is  also  a  party  to  another  coal  transportation  contract  covering  the  delivery  of  2.5  million  tons  annually  through  2025,  a  portion  of   which  is  to  be  delivered  to  another  coal-­fired  plant  owned  by  FG  that  was  deactivated  as  a  result  of  MATS.  FG  has  asserted  a   defense  of  force  majeure  in  response  to  delivery  shortfalls  to  such  plant  under  this  contract  as  well.  If  FirstEnergy  and  FES  fail  to   reach  a  resolution  with  the  applicable  counterparties  to  the  contract,  and  if  it  were  ultimately  determined  that,  contrary  to  FirstEnergy’s   and  FES’  belief,  the  force  majeure  provisions  of  that  contract  do  not  excuse  the  delivery  shortfalls  to  the  deactivated  plant,  the  results   of  operations  and  financial  condition  of  both  FirstEnergy  and  FES  could  be  materially  adversely  impacted.  FirstEnergy  and  FES  are   unable  to  estimate  the  loss  or  range  of  loss.     As  to  both  coal  transportation  agreements  referenced  above,  FES  paid  in  settlement  approximately  $70  million  in  liquidated  damages   for  delivery  shortfalls  in  2014  related  to  its  deactivated  plants.   As  to  a  specific  coal  supply  agreement,  FirstEnergy  and  AE  Supply  have  asserted  termination  rights  effective  in  2015.  In  response  to   notification  of  the  termination,  the  coal  supplier  commenced  litigation  alleging  FirstEnergy  and  AE  Supply  do  not  have  sufficient   justification   to   terminate   the   agreement.   FirstEnergy   and  AE   Supply   have   filed   an   answer   denying   any   liability   related   to   the   termination.  This  matter  is  currently  in  the  discovery  phase  of  litigation  and  no  trial  date  has  been  established.  There  are  6  million  tons   remaining  under  the  contract  for  delivery.  At  this  time,  FirstEnergy  cannot  estimate  the  loss  or  range  of  loss  regarding  the  on-­going   litigation  with  respect  to  this  agreement.     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,  and  March  27,  2013,   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,  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.                                                   Collateral  Provisions   Split  Rating  (One  rating  agency's  rating  below  investment  grade)   $   BB+/Ba1  Credit  Ratings   Full  impact  of  credit  contingent  contractual  obligations   FES   AE  Supply   Utilities   Total   198   $   231   $   363   $   $   $   (In  millions)   6   $   6   $   16   $   41   $   41   $   41   $   245   278   420   Excluded   from   the   preceding   chart   are   the   potential   collateral   obligations   due   to   affiliate   transactions   between   the   Regulated   Distribution  segment  and  CES  segment.  As  of  December  31,  2015,  neither  FES  nor  AE  Supply  had  any  collateral  posted  with  their   affiliates.  In  the  event  of  a  senior  unsecured  credit  rating  downgrade  to  below  S&P's  BB-­  or  Moody's  Ba3,  FES  would  be  required  to   post  $8  million  with  affiliated  parties.     OTHER  COMMITMENTS  AND  CONTINGENCIES   FirstEnergy  is  a  guarantor  under  a  syndicated  senior  secured  term  loan  facility  due  March  3,  2020,  under  which  Global  Holding   borrowed  $300  million.  In  addition  to  FirstEnergy,  Signal  Peak,  Global  Rail,  Global  Mining  Group,  LLC  and  Global  Coal  Sales  Group,   LLC,   each   being   a   direct   or   indirect   subsidiary   of   Global   Holding,   have   also   provided   their   joint   and   several   guaranties   of   the   obligations  of  Global  Holding  under  the  facility.   In  connection  with  Global  Holding's  term  loan  facility,  a  portion  of  Global  Holding's  direct  and  indirect  membership  interests  in  Signal   Peak,  Global  Rail  and  their  affiliates  along  with  each  of  FEV's  and  WMB  Marketing  Ventures,LLC's    33-­1/3%  membership  interests  in   Global  Holding,  are  pledged  to  the  lenders  under  Global  Holding's  facility  as  collateral.  Failure  by  Global  Holding  to  meet  the  terms   and  conditions  under  its  term  loan  facility  could  require  FirstEnergy  to  be  obligated  under  the  provisions  of  its  guarantee,  resulting  in   consolidation  of  Global  Holding  by  FE.   During  the  first  quarter  of  2015,  a  subsidiary  of  Global  Holding  eliminated  its  right  to  put  2  million  tons  annually  through  2024  from  the   Signal  Peak  mine  to  FG  in  exchange  for  FirstEnergy  extending  its  guarantee  under  Global  Holding's  $300  million  senior  secured  term   loan  facility  through  2020,  resulting  in  a  pre-­tax  charge  of  $24  million.  See  Note  8,  Variable  Interest  Entities,  and  Note  1,  Organization,   Basis  of  Presentation  and  Significant  Accounting  Policies  -­  Investments,  for  additional  information  regarding  FEV's  investment  in   Global  Holding.     ENVIRONMENTAL  MATTERS   Various  federal,  state  and  local  authorities  regulate  FirstEnergy  with  regard  to  air  and  water  quality  and  other  environmental  matters.   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   emission  allowances.   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   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  U.S.  Court  of  Appeals  for  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  EPA’s  regulatory  approach  under  CSAPR,  but  questioning  whether  EPA  required  upwind   states  to  reduce  emissions  by  more  than  their  contribution  to  air  pollution  in  downwind  states.  EPA  proposed  a  CSAPR  update  rule  on   November  16,  2015,  that  would  reduce  summertime  NOx  emissions  from  power  plants  in  23  states  in  the  eastern  U.S.,  including   Ohio,  Pennsylvania  and  West  Virginia,  beginning  in  2017.  Depending  on  how  the  EPA  and  the  states  implement  CSAPR,  the  future   cost  of  compliance  may  be  substantial  and  changes  to  FirstEnergy's  and  FES'  operations  may  result.   EPA  tightened  the  primary  and  secondary  NAAQS  for  ozone  from  the  2008  standard  levels  of  75  PPB  to  70  PPB  on  October  1,  2015.   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  EPA  will  designate  those  counties  that  fail  to  attain  the  new  2015  ozone  NAAQS  by  October  1,  2017.  States  will  then   have  roughly  three  years  to  develop  implementation  plans  to  attain  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  substantial  and  changes  to  FirstEnergy’s  and   FES’  operations  may  result.     MATS  imposes  emission  limits  for  mercury,  PM,  and  HCl  for  all  existing  and  new  fossil  fuel  fired  electric  generating  units  effective  in   April  2015  with  averaging  of  emissions  from  multiple  units  located  at  a  single  plant.  Under  the  CAA,  state  permitting  authorities  can   grant  an  additional  compliance  year  through  April  2016,  as  needed,  including  instances  when  necessary  to  maintain  reliability  where   electric  generating  units  are  being  closed.  On  December  28,  2012,  the  WVDEP  granted  a  conditional  extension  through  April  16,   2016  for  MATS  compliance  at  the  Fort  Martin,  Harrison  and  Pleasants  plants.  On  March  20,  2013,  the  PA  DEP  granted  an  extension   through  April  16,  2016  for  MATS  compliance  at  the  Hatfield's  Ferry  and  Bruce  Mansfield  plants.  On  February  5,  2015,  the  OEPA   granted  an  extension  through  April  16,  2016  for  MATS  compliance  at  the  Bay  Shore  and  Sammis  plants.  Nearly  all  spending  for   MATS  compliance  at  Bay  Shore  and  Sammis  has  been  completed  through  2014.  In  addition,  an  EPA  enforcement  policy  document   contemplates  up  to  an  additional  year  to  achieve  compliance,  through  April  2017,  under  certain  circumstances  for  reliability  critical   units.  On  June  29,  2015,  the  United  States  Supreme  Court  reversed  a  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  decision  that  upheld   MATS,  rejecting  EPA’s  regulatory  approach  that  costs  are  not  relevant  to  the  decision  of  whether  or  not  to  regulate  power  plant   emissions  under  Section  112  of  the  Clean  Air  Act  and  remanded  the  case  back  to  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  for   further  proceedings.  The  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  later  remanded  MATS  back  to  EPA,  who  represented  to  such  court   that  the  EPA  is  on  track  to  issue  a  finalized  MATS  by  April  15,  2016.  Subject  to  the  outcome  of  any  further  proceedings  before  the   U.S.   Court   of  Appeals   for   the   D.C.   Circuit   and   how   the   MATS   are   ultimately   implemented,   FirstEnergy's   total   capital   cost   for   compliance  (over  the  2012  to  2018  time  period)  is  currently  expected  to  be  approximately  $345  million  (CES  segment  of  $168  million   and  Regulated  Distribution  segment  of  $177  million),  of  which  $202  million  has  been  spent  through  December  31,  2015  ($80  million   at  CES  and  $122  million  at  Regulated  Distribution).     As  a  result  of  MATS,  Eastlake  Units  1-­3,  Ashtabula  Unit  5  and  Lake  Shore  Unit  18  were  deactivated  in  April  2015,  which  completes   the  deactivation  of  5,429  MW  of  coal-­fired  plants  since  2012.       On  August  3,  2015,  FG,  a  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  that  excuses  FG’s  performance  under  its   coal  transportation  contract  with  these  parties.  Specifically,  the  dispute  arises  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,  those  plants  were  deactivated  by  April  16,  2015.  In  January  2012,  FG  notified   BNSF  and  CSX  that  MATS  constituted  a  force  majeure  event  under  the  contract  that  excused  FG’s  further  performance.  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  including,  but  not  limited  to,  lost  profits  under  the  contract  through  2025.  As  part  of  its  statement  of  claim,  a  right  to   liquidated  damages  is  alleged.  The  arbitration  panel  has  determined  to  consolidate  the  claims  with  a  liability  hearing  expected  to   begin   in   November   2016,   and,   if   necessary,   a   damages   hearing   is   expected   to   begin   in   May   2017.  The   decision   on   liability   is   expected  to  be  issued  within  sixty  days  from  the  end  of  the  liability  hearings.  FirstEnergy  and  FES  continue  to  believe  that  MATS   constitutes  a  force  majeure  event  under  the  contract  as  it  relates  to  the  deactivated  plants  and  that  FG’s  performance  under  the   contract   is   therefore   excused.   FirstEnergy   and   FES   intend   to   vigorously   assert   their   position   in   the   arbitration   proceedings.   If,   however,  the  arbitration  panel  rules  in  favor  of  BNSF  and  CSX,  the  results  of  operations  and  financial  condition  of  both  FirstEnergy   and  FES  could  be  materially  adversely  impacted.  FirstEnergy  and  FES  are  unable  to  estimate  the  loss  or  range  of  loss.       FG  is  also  a  party  to  another  coal  transportation  contract  covering  the  delivery  of  2.5  million  tons  annually  through  2025,  a  portion  of   which  is  to  be  delivered  to  another  coal-­fired  plant  owned  by  FG  that  was  deactivated  as  a  result  of  MATS.  FG  has  asserted  a   defense  of  force  majeure  in  response  to  delivery  shortfalls  to  such  plant  under  this  contract  as  well.  If  FirstEnergy  and  FES  fail  to   reach  a  resolution  with  the  applicable  counterparties  to  the  contract,  and  if  it  were  ultimately  determined  that,  contrary  to  FirstEnergy’s   and  FES’  belief,  the  force  majeure  provisions  of  that  contract  do  not  excuse  the  delivery  shortfalls  to  the  deactivated  plant,  the  results   of  operations  and  financial  condition  of  both  FirstEnergy  and  FES  could  be  materially  adversely  impacted.  FirstEnergy  and  FES  are   unable  to  estimate  the  loss  or  range  of  loss.     As  to  both  coal  transportation  agreements  referenced  above,  FES  paid  in  settlement  approximately  $70  million  in  liquidated  damages   for  delivery  shortfalls  in  2014  related  to  its  deactivated  plants.   As  to  a  specific  coal  supply  agreement,  FirstEnergy  and  AE  Supply  have  asserted  termination  rights  effective  in  2015.  In  response  to   notification  of  the  termination,  the  coal  supplier  commenced  litigation  alleging  FirstEnergy  and  AE  Supply  do  not  have  sufficient   justification   to   terminate   the   agreement.   FirstEnergy   and  AE   Supply   have   filed   an   answer   denying   any   liability   related   to   the   termination.  This  matter  is  currently  in  the  discovery  phase  of  litigation  and  no  trial  date  has  been  established.  There  are  6  million  tons   remaining  under  the  contract  for  delivery.  At  this  time,  FirstEnergy  cannot  estimate  the  loss  or  range  of  loss  regarding  the  on-­going   litigation  with  respect  to  this  agreement.     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,  and  March  27,  2013,   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,  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.     126   127                                                 Climate  Change   There  are  a  number  of  initiatives  to  reduce  GHG  emissions  at  the  state,  federal  and  international  level.  Certain  northeastern  states   are  participating  in  the  RGGI  and  western  states  led  by  California,  have  implemented  programs,  primarily  cap  and  trade  mechanisms,   to  control  emissions  of  certain  GHGs.  Additional  policies  reducing  GHG  emissions,  such  as  demand  reduction  programs,  renewable   portfolio  standards  and  renewable  subsidies  have  been  implemented  across  the  nation.  A  June  2013,  Presidential  Climate  Action   Plan  outlined  goals  to:  (i)  cut  carbon  pollution  in  America  by  17%  by  2020  (from  2005  levels);;  (ii)  prepare  the  United  States  for  the   impacts  of  climate  change;;  and  (iii)  lead  international  efforts  to  combat  global  climate  change  and  prepare  for  its  impacts.  GHG   emissions   have   already   been   reduced   by   10%   between   2005   and   2012   according   to   an  April,   2014   EPA   Report.   Due   to   plant   deactivations  and  increased  efficiencies,  FirstEnergy  anticipates  its  CO2  emissions  will  be  reduced  25%  below  2005  levels  by  2015,   exceeding  the  President’s  Climate  Action  Plan  goals  both  in  terms  of  timing  and  reduction  levels.   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.  The  EPA  released  its  final  regulations  in  August  2015,  to  reduce  CO2  emissions  from  existing  fossil  fuel  fired   electric  generating  units  that  would  require  each  state  to  develop  SIPs  by  September  6,  2016,  to  meet  the  EPA’s  state  specific  CO2   emission  rate  goals.  The  EPA’s  CPP  allows  states  to  request  a  two-­year  extension  to  finalize  SIPs  by  September  6,  2018.  If  states  fail   to  develop  SIPs,  the  EPA  also  proposed  a  federal  implementation  plan  that  can  be  implemented  by  the  EPA  that  included  model   emissions  trading  rules  which  states  can  also  adopt  in  their  SIPs.  The  EPA  also  finalized  separate  regulations  imposing  CO2  emission   limits  for  new,  modified,  and  reconstructed  fossil  fuel  fired  electric  generating  units.  On  June  23,  2014,  the  United  States  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.   Numerous  states  and  private  parties  filed  appeals  and  motions  to  stay  the  CPP  with  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  in   October  2015.  On  January  21,  2015,  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.  Depending  on  the  outcome  of  further  appeals  and  how  any  final  rules  are  ultimately  implemented,   the  future  cost  of  compliance  may  be  substantial.     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  greenhouse  gas   emissions  by  26  to  28  percent  below  2005  levels  by  2025  and  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  must  be  ratified  by  at  least  55   countries  representing  at  least  55%  of  global  GHG  emissions  before  its  non-­binding  obligations  to  limit  global  warming  to  well  below   two  degrees  Celsius  become  effective.  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  significant  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  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.  FirstEnergy  is  studying  various  control  options  and  their  costs  and  effectiveness,  including  pilot  testing   of  reverse  louvers  in  a  portion  of  the  Bay  Shore  plant's  cooling  water  intake  channel  to  divert  fish  away  from  the  plant's  cooling  water   intake  system.  Depending  on  the  results  of  such  studies  and  any  final  action  taken  by  the  states  based  on  those  studies,  the  future   capital  costs  of  compliance  with  these  standards  may  be  substantial.   The  EPA  proposed  updates  to  the  waste  water  effluent  limitations  guidelines  and  standards  for  the  Steam  Electric  Power  Generating   category  (40  CFR  Part  423)  in  April  2013.  On  September  30,  2015,  the  EPA  finalized  new,  more  stringent  effluent  limits  for  arsenic,   mercury,  selenium  and  nitrogen  for  wastewater  from  wet  scrubber  systems  and  zero  discharge  of  pollutants  in  ash  transport  water.   The  treatment  obligations  will  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.  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  coal  combustion  residuals,  such  as  coal  ash,  were  exempted  from  hazardous  waste  disposal   requirements  pending  the  EPA's  evaluation  of  the  need  for  future  regulation.   In  December  2014,  the  EPA  finalized  regulations  for  the  disposal  of  CCRs  (non-­hazardous),  establishing  national  standards  regarding   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.   Based  on  an  assessment  of  the  finalized  regulations,  the  future  cost  of  compliance  and  expected  timing  of  spend  had  no  significant   impact  on  FirstEnergy's  or  FES'  existing  AROs  associated  with  CCRs.  Although  unexpected,  changes  in  timing  and  closure  plan   requirements  in  the  future  could  impact  our  asset  retirement  obligations  significantly.   Pursuant  to  a  2013  consent  decree,  PA  DEP  issued  a  2014  permit  requiring  FE  to  provide  bonding  for  45  years  of  closure  and  post-­ closure   activities   and   to   complete   closure   within   a   12-­year   period,   but   authorizing   FE   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  Bruce  Mansfield   plant  is  pursuing  several  options  for  disposal  of  CCRs  following  December  31,  2016  and  expects  beneficial  reuse  and  disposal   options  will  be  sufficient  for  the  ongoing  operation  of  the  plant.  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.  On   July  6,  2015  and  October  22,  2015,  the  Sierra  Club  filed  Notice  of  Appeals  with  the  Pennsylvania  Environmental  Hearing  Board   challenging  the  renewal,  reissuance  and  modification  of  the  permit  for  the  Hatfield’s  Ferry  CCR  disposal  facility.     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,  2015  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   $126  million  have  been  accrued  through  December  31,  2015.  Included  in  the  total  are  accrued  liabilities  of  approximately  $87  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,  2015,  FirstEnergy  had  approximately  $2.3  billion  invested  in  external  trusts  to  be  used  for  the  decommissioning  and   environmental  remediation  of  Davis-­Besse,  Beaver  Valley,  Perry  and  TMI-­2.  The  values  of  FirstEnergy's  NDTs  fluctuate  based  on   market  conditions.  If  the  value  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.  FE  and  FES  have  also  entered  into  a  total  of  $24.5  million  in  parental  guarantees  in  support  of  the  decommissioning  of  the   spent  fuel  storage  facilities  located  at  the  nuclear  facilities.  As  required  by  the  NRC,  FirstEnergy  annually  recalculates  and  adjusts  the   amount  of  its  parental  guaranties,  as  appropriate.     In  August  2010,  FENOC  submitted  an  application  to  the  NRC  for  renewal  of  the  Davis-­Besse  operating  license  for  an  additional   twenty  years.  On  December  8,  2015,  the  NRC  renewed  the  operating  license  for  Davis-­Besse,  which  is  now  authorized  to  continue   operation  through  April  22,  2037.  Prior  to  that  decision,  the  NRC  Commissioners  denied  an  intervenor's  request  to  reopen  the  record   and   admit   a   contention   on   the   NRC’s   Continued   Storage   Rule.   On  August   6,   2015,   this   intervenor   sought   review   of   the   NRC   Commissioners'  decision  before  the  U.S.  Court  of  Appeals  for  the  DC  Circuit.  FENOC  has  moved  to  intervene  in  that  proceeding.     128   129                                             Climate  Change   There  are  a  number  of  initiatives  to  reduce  GHG  emissions  at  the  state,  federal  and  international  level.  Certain  northeastern  states   are  participating  in  the  RGGI  and  western  states  led  by  California,  have  implemented  programs,  primarily  cap  and  trade  mechanisms,   to  control  emissions  of  certain  GHGs.  Additional  policies  reducing  GHG  emissions,  such  as  demand  reduction  programs,  renewable   portfolio  standards  and  renewable  subsidies  have  been  implemented  across  the  nation.  A  June  2013,  Presidential  Climate  Action   Plan  outlined  goals  to:  (i)  cut  carbon  pollution  in  America  by  17%  by  2020  (from  2005  levels);;  (ii)  prepare  the  United  States  for  the   impacts  of  climate  change;;  and  (iii)  lead  international  efforts  to  combat  global  climate  change  and  prepare  for  its  impacts.  GHG   emissions   have   already   been   reduced   by   10%   between   2005   and   2012   according   to   an  April,   2014   EPA   Report.   Due   to   plant   deactivations  and  increased  efficiencies,  FirstEnergy  anticipates  its  CO2  emissions  will  be  reduced  25%  below  2005  levels  by  2015,   exceeding  the  President’s  Climate  Action  Plan  goals  both  in  terms  of  timing  and  reduction  levels.   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.   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   Regulation  of  Waste  Disposal   pollutants"  under  the  CAA  and  mandated  measurement  and  reporting  of  GHG  emissions  from  certain  sources,  including  electric   generating  plants.  The  EPA  released  its  final  regulations  in  August  2015,  to  reduce  CO2  emissions  from  existing  fossil  fuel  fired   electric  generating  units  that  would  require  each  state  to  develop  SIPs  by  September  6,  2016,  to  meet  the  EPA’s  state  specific  CO2   emission  rate  goals.  The  EPA’s  CPP  allows  states  to  request  a  two-­year  extension  to  finalize  SIPs  by  September  6,  2018.  If  states  fail   to  develop  SIPs,  the  EPA  also  proposed  a  federal  implementation  plan  that  can  be  implemented  by  the  EPA  that  included  model   emissions  trading  rules  which  states  can  also  adopt  in  their  SIPs.  The  EPA  also  finalized  separate  regulations  imposing  CO2  emission   limits  for  new,  modified,  and  reconstructed  fossil  fuel  fired  electric  generating  units.  On  June  23,  2014,  the  United  States  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.   Numerous  states  and  private  parties  filed  appeals  and  motions  to  stay  the  CPP  with  the  U.S.  Court  of  Appeals  for  the  D.C.  Circuit  in   October  2015.  On  January  21,  2015,  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.  Depending  on  the  outcome  of  further  appeals  and  how  any  final  rules  are  ultimately  implemented,   the  future  cost  of  compliance  may  be  substantial.     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  greenhouse  gas   emissions  by  26  to  28  percent  below  2005  levels  by  2025  and  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  must  be  ratified  by  at  least  55   countries  representing  at  least  55%  of  global  GHG  emissions  before  its  non-­binding  obligations  to  limit  global  warming  to  well  below   two  degrees  Celsius  become  effective.  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  significant  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.   Federal   and   state   hazardous   waste   regulations   have   been   promulgated   as   a   result   of   the   RCRA,   as   amended,   and   the  Toxic   Substances  Control  Act.  Certain  coal  combustion  residuals,  such  as  coal  ash,  were  exempted  from  hazardous  waste  disposal   requirements  pending  the  EPA's  evaluation  of  the  need  for  future  regulation.   In  December  2014,  the  EPA  finalized  regulations  for  the  disposal  of  CCRs  (non-­hazardous),  establishing  national  standards  regarding   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.   Based  on  an  assessment  of  the  finalized  regulations,  the  future  cost  of  compliance  and  expected  timing  of  spend  had  no  significant   impact  on  FirstEnergy's  or  FES'  existing  AROs  associated  with  CCRs.  Although  unexpected,  changes  in  timing  and  closure  plan   requirements  in  the  future  could  impact  our  asset  retirement  obligations  significantly.   Pursuant  to  a  2013  consent  decree,  PA  DEP  issued  a  2014  permit  requiring  FE  to  provide  bonding  for  45  years  of  closure  and  post-­ closure   activities   and   to   complete   closure   within   a   12-­year   period,   but   authorizing   FE   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  Bruce  Mansfield   plant  is  pursuing  several  options  for  disposal  of  CCRs  following  December  31,  2016  and  expects  beneficial  reuse  and  disposal   options  will  be  sufficient  for  the  ongoing  operation  of  the  plant.  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.  On   July  6,  2015  and  October  22,  2015,  the  Sierra  Club  filed  Notice  of  Appeals  with  the  Pennsylvania  Environmental  Hearing  Board   challenging  the  renewal,  reissuance  and  modification  of  the  permit  for  the  Hatfield’s  Ferry  CCR  disposal  facility.     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,  2015  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   $126  million  have  been  accrued  through  December  31,  2015.  Included  in  the  total  are  accrued  liabilities  of  approximately  $87  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.     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   OTHER  LEGAL  PROCEEDINGS   day  to  conduct  studies  to  determine  site-­specific  controls,  if  any,  to  reduce  entrainment,  which  occurs  when  aquatic  life  is  drawn  into  a   Nuclear  Plant  Matters   facility's  cooling  water  system.  FirstEnergy  is  studying  various  control  options  and  their  costs  and  effectiveness,  including  pilot  testing   of  reverse  louvers  in  a  portion  of  the  Bay  Shore  plant's  cooling  water  intake  channel  to  divert  fish  away  from  the  plant's  cooling  water   intake  system.  Depending  on  the  results  of  such  studies  and  any  final  action  taken  by  the  states  based  on  those  studies,  the  future   capital  costs  of  compliance  with  these  standards  may  be  substantial.   The  EPA  proposed  updates  to  the  waste  water  effluent  limitations  guidelines  and  standards  for  the  Steam  Electric  Power  Generating   category  (40  CFR  Part  423)  in  April  2013.  On  September  30,  2015,  the  EPA  finalized  new,  more  stringent  effluent  limits  for  arsenic,   mercury,  selenium  and  nitrogen  for  wastewater  from  wet  scrubber  systems  and  zero  discharge  of  pollutants  in  ash  transport  water.   The  treatment  obligations  will  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.  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.     Under  NRC  regulations,  FirstEnergy  must  ensure  that  adequate  funds  will  be  available  to  decommission  its  nuclear  facilities.  As  of   December  31,  2015,  FirstEnergy  had  approximately  $2.3  billion  invested  in  external  trusts  to  be  used  for  the  decommissioning  and   environmental  remediation  of  Davis-­Besse,  Beaver  Valley,  Perry  and  TMI-­2.  The  values  of  FirstEnergy's  NDTs  fluctuate  based  on   market  conditions.  If  the  value  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.  FE  and  FES  have  also  entered  into  a  total  of  $24.5  million  in  parental  guarantees  in  support  of  the  decommissioning  of  the   spent  fuel  storage  facilities  located  at  the  nuclear  facilities.  As  required  by  the  NRC,  FirstEnergy  annually  recalculates  and  adjusts  the   amount  of  its  parental  guaranties,  as  appropriate.     In  August  2010,  FENOC  submitted  an  application  to  the  NRC  for  renewal  of  the  Davis-­Besse  operating  license  for  an  additional   twenty  years.  On  December  8,  2015,  the  NRC  renewed  the  operating  license  for  Davis-­Besse,  which  is  now  authorized  to  continue   operation  through  April  22,  2037.  Prior  to  that  decision,  the  NRC  Commissioners  denied  an  intervenor's  request  to  reopen  the  record   and   admit   a   contention   on   the   NRC’s   Continued   Storage   Rule.   On  August   6,   2015,   this   intervenor   sought   review   of   the   NRC   Commissioners'  decision  before  the  U.S.  Court  of  Appeals  for  the  DC  Circuit.  FENOC  has  moved  to  intervene  in  that  proceeding.     128   129                                             FirstEnergy  does  not  bill  directly  or  allocate  any  of  its  costs  to  any  subsidiary  company.  Costs  are  allocated  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.  Management  believes  that  these  allocation   methods  are  reasonable.  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,  and  may  purchase  the  uncommitted  output  of  AE  Supply,  as  well   as   the   output   relating   to   leasehold   interests   of   OE   and  TE   in   certain   of   those   facilities   that   are   subject   to   sale   and   leaseback   arrangements,  and  pursuant  to  full  output,  cost-­of-­service  PSAs.   FES  and  the  Utilities  are  parties  to  an  intercompany  income  tax  allocation  agreement  with  FirstEnergy  and  its  other  subsidiaries  that   provides  for  the  allocation  of  consolidated  tax  liabilities.  Net  tax  benefits  attributable  to  FirstEnergy  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  5,  Taxes).   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.   FENOC  plans  to  submit  a  license  amendment  application  related  to  the  Shield  Building  analysis  in  2016.       On  March  12,  2012,  the  NRC  issued  orders  requiring  safety  enhancements  at  U.S.  reactors  based  on  recommendations  from  the   lessons  learned  Task  Force  review  of  the  accident  at  Japan's  Fukushima  Daiichi  nuclear  power  plant.  These  orders  require  additional   mitigation  strategies  for  beyond-­design-­basis  external  events,  and  enhanced  equipment  for  monitoring  water  levels  in  spent  fuel   pools.   The   NRC   also   requested   that   licensees   including   FENOC:   re-­analyze   earthquake   and   flooding   risks   using   the   latest   information   available;;   conduct   earthquake   and   flooding   hazard   walkdowns   at   their   nuclear   plants;;   assess   the   ability   of   current   communications  systems  and  equipment  to  perform  under  a  prolonged  loss  of  onsite  and  offsite  electrical  power;;  and  assess  plant   staffing   levels   needed   to   fill   emergency   positions.   These   and   other   NRC   requirements   adopted   as   a   result   of   the   accident   at   Fukushima  Daiichi  are  likely  to  result  in  additional  material  costs  from  plant  modifications  and  upgrades  at  FirstEnergy's  nuclear   facilities.     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  14,   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.     16.  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,  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.   The   primary   affiliated   company   transactions   for   FES   during   the   three   years   ended   December  31,  2015  are  as  follows:   FES   2015   2014   (In  millions)   2013   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   $   664   $   6   861   $   6   353   1   705   2   4   3   271   1   619   3   3   4   652   6   486   —   619   2   4   6   130   131               FirstEnergy  does  not  bill  directly  or  allocate  any  of  its  costs  to  any  subsidiary  company.  Costs  are  allocated  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.  Management  believes  that  these  allocation   methods  are  reasonable.  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,  and  may  purchase  the  uncommitted  output  of  AE  Supply,  as  well   as   the   output   relating   to   leasehold   interests   of   OE   and  TE   in   certain   of   those   facilities   that   are   subject   to   sale   and   leaseback   arrangements,  and  pursuant  to  full  output,  cost-­of-­service  PSAs.   FES  and  the  Utilities  are  parties  to  an  intercompany  income  tax  allocation  agreement  with  FirstEnergy  and  its  other  subsidiaries  that   provides  for  the  allocation  of  consolidated  tax  liabilities.  Net  tax  benefits  attributable  to  FirstEnergy  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  5,  Taxes).   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.   FENOC  plans  to  submit  a  license  amendment  application  related  to  the  Shield  Building  analysis  in  2016.       On  March  12,  2012,  the  NRC  issued  orders  requiring  safety  enhancements  at  U.S.  reactors  based  on  recommendations  from  the   lessons  learned  Task  Force  review  of  the  accident  at  Japan's  Fukushima  Daiichi  nuclear  power  plant.  These  orders  require  additional   mitigation  strategies  for  beyond-­design-­basis  external  events,  and  enhanced  equipment  for  monitoring  water  levels  in  spent  fuel   pools.   The   NRC   also   requested   that   licensees   including   FENOC:   re-­analyze   earthquake   and   flooding   risks   using   the   latest   information   available;;   conduct   earthquake   and   flooding   hazard   walkdowns   at   their   nuclear   plants;;   assess   the   ability   of   current   communications  systems  and  equipment  to  perform  under  a  prolonged  loss  of  onsite  and  offsite  electrical  power;;  and  assess  plant   staffing   levels   needed   to   fill   emergency   positions.   These   and   other   NRC   requirements   adopted   as   a   result   of   the   accident   at   Fukushima  Daiichi  are  likely  to  result  in  additional  material  costs  from  plant  modifications  and  upgrades  at  FirstEnergy's  nuclear   facilities.     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  14,   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.     16.  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,  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.   The   primary   affiliated   company   transactions   for   FES   during   the   three   years   ended   December  31,  2015  are  as  follows:   Electric  sales  to  affiliates   $   664   $   861   $   FES   Revenues:   Other   Expenses:   Fuel   Purchased  power  from  affiliates   Support  services   Investment  Income:   Interest  income  from  FE   Interest  Expense:   Interest  expense  to  affiliates   Interest  expense  to  FE   2015   2014   2013   (In  millions)   6   353   1   705   2   4   3   6   271   1   619   3   3   4   652   6   486   —   619   2   4   6   130   131               17.  SUPPLEMENTAL  GUARANTOR  INFORMATION   In  2007,  FG  completed  a  sale  and  leaseback  transaction  for  its  undivided  interest  in  Bruce  Mansfield  Unit  1.  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  FES  or  FG,  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,   2015,   2014,   and   2013,   Condensed   Consolidating   Balance   Sheets   as   of   December  31,   2015   and   December  31,   2014,   and   Condensed  Consolidating  Statements  of  Cash  Flows  for  the  years  ended  December  31,  2015,  2014,  and  2013,  for  FES  (parent  and   guarantor),  FG  and  NG  (non-­guarantor)  are  presented  below.  These  statements  are  provided  as  FES  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  FES  using  the  equity  method.  Results  of  operations  for  FG  and  NG  are,  therefore,  reflected  in  FES’  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.   CONDENSED  CONSOLIDATING  STATEMENTS  OF  INCOME  AND  COMPREHENSIVE  INCOME   FIRSTENERGY  SOLUTIONS  CORP.   For  the  Year  Ended  December  31,  2015   FES   FG   NG   Eliminations   Consolidated   STATEMENTS  OF  INCOME   (In  millions)   REVENUES   $   4,824   $   1,801   $   2,138   $   (3,758  )   $   5,005   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   Total  operating  expenses   OPERATING  INCOME  (LOSS)   OTHER  INCOME  (EXPENSE):   Investment  income  (loss),  including  net  income  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   NET  INCOME   STATEMENTS  OF  COMPREHENSIVE  INCOME   —   3,826   1,684   399   (8  )   12   45   5,958   (1,134  )   844   1   (29  )   (52  )   —   764   (370  )   (452  )   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   (6  )   (3  )   (9  )   (18  )   (7  )   (11  )   71   $   $   $   $   679   —   —   275   10   124   26   1,114   687   17   2   (8  )   (104  )   6   (87  )   600   224   (5  )   —   —   (5  )   (2  )   (3  )   192   285   —   618   55   191   27   1,368   770   (5  )   —   (4  )   (49  )   29   (29  )   741   278   —   —   (8  )   (8  )   (3  )   (5  )   (3,758  )   —   —   49   —   (3  )   —   (3,712  )   (46  )   (870  )   —   34   58   —   (778  )   (824  )   15   5   —   8   13   5   8   82   $   376   $   463   $   (839  )   $   82   $   376   $   463   $   (839  )   $   373   $   458   $   (831  )   $   871   353   1,684   1,341   57   324   98   4,728   277   (14  )   3   (7  )   (147  )   35   (130  )   147   65   82   82   (6  )   (3  )   (9  )   (18  )   (7  )   (11  )   71   132   133                   17.  SUPPLEMENTAL  GUARANTOR  INFORMATION   In  2007,  FG  completed  a  sale  and  leaseback  transaction  for  its  undivided  interest  in  Bruce  Mansfield  Unit  1.  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  FES  or  FG,  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.   FIRSTENERGY  SOLUTIONS  CORP.   CONDENSED  CONSOLIDATING  STATEMENTS  OF  INCOME  AND  COMPREHENSIVE  INCOME   For  the  Year  Ended  December  31,  2015   FES   FG   NG   Eliminations   Consolidated   STATEMENTS  OF  INCOME   (In  millions)   $   4,824   $   1,801   $   2,138   $   (3,758  )   $   5,005   The  Condensed  Consolidating  Statements  of  Income  (Loss)  and  Comprehensive  Income  (Loss)  for  the  years  ended  December  31,   2015,   2014,   and   2013,   Condensed   Consolidating   Balance   Sheets   as   of   December  31,   2015   and   December  31,   2014,   and   REVENUES   Condensed  Consolidating  Statements  of  Cash  Flows  for  the  years  ended  December  31,  2015,  2014,  and  2013,  for  FES  (parent  and   guarantor),  FG  and  NG  (non-­guarantor)  are  presented  below.  These  statements  are  provided  as  FES  fully  and  unconditionally   OPERATING  EXPENSES:   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  FES  using  the  equity  method.  Results  of  operations  for  FG  and  NG  are,  therefore,  reflected  in  FES’  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.   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   Total  operating  expenses   OPERATING  INCOME  (LOSS)   OTHER  INCOME  (EXPENSE):   Investment  income  (loss),  including  net  income  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   —   3,826   1,684   399   (8  )   12   45   5,958   (1,134  )   844   1   (29  )   (52  )   —   764   (370  )   (452  )   679   —   —   275   10   124   26   1,114   687   17   2   (8  )   (104  )   6   (87  )   600   224   192   285   —   618   55   191   27   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  )   $   Income  tax  benefits  on  other  comprehensive  loss   Other  comprehensive  loss,  net  of  tax   COMPREHENSIVE  INCOME   (6  )   (3  )   (9  )   (18  )   (7  )   (5  )   —   —   (5  )   (2  )   —   —   (8  )   (8  )   (3  )   $   (11  )   71   $   (3  )   373   $   (5  )   458   $   5   —   8   13   5   8   (831  )   $   871   353   1,684   1,341   57   324   98   4,728   277   (14  )   3   (7  )   (147  )   35   (130  )   147   65   82   82   (6  )   (3  )   (9  )   (18  )   (7  )   (11  )   71   132   133                   FIRSTENERGY  SOLUTIONS  CORP.   CONDENSED  CONSOLIDATING  STATEMENTS  OF  INCOME  (LOSS)  AND  COMPREHENSIVE  INCOME  (LOSS)   For  the  Year  Ended  December  31,  2014   FES   FG   NG   Eliminations   Consolidated   STATEMENTS  OF  INCOME  (LOSS)   (In  millions)   REVENUES   $   5,990   $   1,902   $   2,172   $   (3,920  )   $   6,144   CONDENSED  CONSOLIDATING  STATEMENTS  OF  INCOME  AND  COMPREHENSIVE  INCOME   FIRSTENERGY  SOLUTIONS  CORP.   For  the  Year  Ended  December  31,  2013   FES   FG   NG   Eliminations   Consolidated   STATEMENTS  OF  INCOME   (In  millions)   REVENUES   $   6,068   $   2,399   $   1,634   $   (3,928  )   $   6,173   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   Total  operating  expenses   OPERATING  INCOME  (LOSS)   OTHER  INCOME  (EXPENSE):   Loss  on  debt  redemptions   Investment  income,  including  net  income  from  equity   investees   Miscellaneous  income   Interest  expense  —  affiliates   Interest  expense  —  other   Capitalized  interest   Total  other  income  (expense)   INCOME  (LOSS)  FROM  CONTINUING  OPERATIONS   BEFORE  INCOME  TAXES  (BENEFITS)   INCOME  TAXES  (BENEFITS)   INCOME  (LOSS)  FROM  CONTINUING  OPERATIONS   Discontinued  operations  (net  of  income  taxes  of  $70)   —   3,920   2,767   790   19   10   72   7,578   (1,588  )   (3  )   791   2   (12  )   (53  )   —   725   (863  )   (619  )   (244  )   —   1,055   —   4   269   90   119   31   1,568   334   (1  )   8   4   (6  )   (101  )   4   (92  )   242   87   155   116   198   271   —   527   188   193   25   1,402   770   (2  )   61   —   (4  )   (52  )   30   33   803   298   505   —   —   (3,920  )   —   49   —   (3  )   —   (3,874  )   (46  )   —   (799  )   —   15   60   —   (724  )   (770  )   6   (776  )   —   NET  INCOME  (LOSS)   $   (244  )   $   271   $   505   $   (776  )   $   STATEMENTS  OF  COMPREHENSIVE  INCOME  (LOSS)   1,253   271   2,771   1,635   297   319   128   6,674   (530  )   (6  )   61   6   (7  )   (146  )   34   (58  )   (588  )   (228  )   (360  )   116   (244  )   NET  INCOME  (LOSS)   $   (244  )   $   271   $   505   $   (776  )   $   (244  )   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)   Other  comprehensive  income  (loss),  net  of  tax   COMPREHENSIVE  INCOME  (LOSS)   $   (6  )   (10  )   21   5   2   3   (241  )   $   (5  )   —   —   (5  )   (2  )   (3  )   268   $   —   —   21   21   8   13   518   $   5   —   (21  )   (16  )   (6  )   (10  )   (786  )   $   (6  )   (10  )   21   5   2   3   (241  )   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   Total  operating  expenses   OPERATING  INCOME  (LOSS)   OTHER  INCOME  (EXPENSE):   Loss  on  debt  redemptions   investees   Miscellaneous  income   Interest  expense  —  affiliates   Interest  expense  —  other   Capitalized  interest   Total  other  income  (expense)   Investment  income,  including  net  income  from  equity   INCOME  (LOSS)  FROM  CONTINUING  OPERATIONS   BEFORE  INCOME  TAXES  (BENEFITS)   INCOME  TAXES  (BENEFITS)   INCOME  FROM  CONTINUING  OPERATIONS   Discontinued  operations  (net  of  income  taxes  of  $8)   NET  INCOME   NET  INCOME   STATEMENTS  OF  COMPREHENSIVE  INCOME   —   4,148   2,326   635   (8  )   6   80   7,187   (1,119  )   (103  )   847   4   (13  )   (63  )   1   673   (446  )   (506  )   60   —   1,056   —   7   275   (37  )   127   34   1,462   937   —   1   24   (5  )   (104  )   2   (82  )   855   365   490   14   60   $   504   $   333   $   (837  )   $   60   $   504   $   333   $   (837  )   $   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   (15  )   (6  )   (8  )   (29  )   (11  )   (18  )   42   $   (13  )   —   —   (13  )   (5  )   (8  )   496   $   328   $   (824  )   $   $   $   $   206   266   —   529   (36  )   178   24   1,167   467   —   25   —   (6  )   (54  )   36   1   468   135   333   —   —   —   (8  )   (8  )   (3  )   (5  )   (3,928  )   —   —   48   —   (5  )   —   (3,885  )   (43  )   —   (857  )   —   14   61   —   (782  )   (825  )   12   (837  )   —   13   —   8   21   8   13   1,262   486   2,333   1,487   (81  )   306   138   5,931   242   (103  )   16   28   (10  )   (160  )   39   (190  )   52   6   46   14   60   60   (15  )   (6  )   (8  )   (29  )   (11  )   (18  )   42   134   135                   STATEMENTS  OF  INCOME  (LOSS)   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   Total  operating  expenses   OPERATING  INCOME  (LOSS)   OTHER  INCOME  (EXPENSE):   Loss  on  debt  redemptions   investees   Miscellaneous  income   Interest  expense  —  affiliates   Interest  expense  —  other   Capitalized  interest   Total  other  income  (expense)   Investment  income,  including  net  income  from  equity   INCOME  (LOSS)  FROM  CONTINUING  OPERATIONS   BEFORE  INCOME  TAXES  (BENEFITS)   INCOME  TAXES  (BENEFITS)   INCOME  (LOSS)  FROM  CONTINUING  OPERATIONS   Discontinued  operations  (net  of  income  taxes  of  $70)   —   3,920   2,767   790   19   10   72   7,578   (1,588  )   (3  )   791   2   (12  )   (53  )   —   725   (863  )   (619  )   (244  )   —   1,055   —   4   269   90   119   31   1,568   334   (1  )   8   4   (6  )   (101  )   4   (92  )   242   87   155   116   NET  INCOME  (LOSS)   $   (244  )   $   271   $   505   $   (776  )   $   STATEMENTS  OF  COMPREHENSIVE  INCOME  (LOSS)   NET  INCOME  (LOSS)   $   (244  )   $   271   $   505   $   (776  )   $   (244  )   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)   Other  comprehensive  income  (loss),  net  of  tax   COMPREHENSIVE  INCOME  (LOSS)   (6  )   (10  )   21   5   2   3   (5  )   —   —   (5  )   (2  )   (3  )   $   (241  )   $   268   $   518   $   5   —   (21  )   (16  )   (6  )   (10  )   (786  )   $   (3,920  )   —   —   49   —   (3  )   —   (3,874  )   (46  )   —   (799  )   —   15   60   —   (724  )   (770  )   6   (776  )   —   198   271   —   527   188   193   25   1,402   770   (2  )   61   —   (4  )   (52  )   30   33   803   298   505   —   —   —   21   21   8   13   1,253   271   2,771   1,635   297   319   128   6,674   (530  )   (6  )   61   6   (7  )   (146  )   34   (58  )   (588  )   (228  )   (360  )   116   (244  )   (6  )   (10  )   21   5   2   3   (241  )   CONDENSED  CONSOLIDATING  STATEMENTS  OF  INCOME  (LOSS)  AND  COMPREHENSIVE  INCOME  (LOSS)   FIRSTENERGY  SOLUTIONS  CORP.   For  the  Year  Ended  December  31,  2014   FES   FG   NG   Eliminations   Consolidated   REVENUES   $   5,990   $   1,902   $   2,172   $   (3,920  )   $   6,144   REVENUES   $   6,068   $   2,399   $   1,634   $   (3,928  )   $   6,173   (In  millions)   For  the  Year  Ended  December  31,  2013   FES   FG   NG   Eliminations   Consolidated   STATEMENTS  OF  INCOME   (In  millions)   FIRSTENERGY  SOLUTIONS  CORP.   CONDENSED  CONSOLIDATING  STATEMENTS  OF  INCOME  AND  COMPREHENSIVE  INCOME   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   Total  operating  expenses   OPERATING  INCOME  (LOSS)   OTHER  INCOME  (EXPENSE):   Loss  on  debt  redemptions   Investment  income,  including  net  income  from  equity   investees   Miscellaneous  income   Interest  expense  —  affiliates   Interest  expense  —  other   Capitalized  interest   Total  other  income  (expense)   INCOME  (LOSS)  FROM  CONTINUING  OPERATIONS   BEFORE  INCOME  TAXES  (BENEFITS)   INCOME  TAXES  (BENEFITS)   INCOME  FROM  CONTINUING  OPERATIONS   Discontinued  operations  (net  of  income  taxes  of  $8)   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   —   4,148   2,326   635   (8  )   6   80   7,187   (1,119  )   (103  )   847   4   (13  )   (63  )   1   673   (446  )   (506  )   60   —   1,056   —   7   275   (37  )   127   34   1,462   937   —   1   24   (5  )   (104  )   2   (82  )   855   365   490   14   206   266   —   529   (36  )   178   24   1,167   467   —   25   —   (6  )   (54  )   36   1   468   135   333   —   —   (3,928  )   —   48   —   (5  )   —   (3,885  )   (43  )   —   (857  )   —   14   61   —   (782  )   (825  )   12   (837  )   —   60   $   504   $   333   $   (837  )   $   60   $   504   $   333   $   (837  )   $   (15  )   (6  )   (8  )   (29  )   (11  )   (13  )   —   —   (13  )   (5  )   —   —   (8  )   (8  )   (3  )   $   (18  )   42   $   (8  )   496   $   (5  )   328   $   13   —   8   21   8   13   (824  )   $   1,262   486   2,333   1,487   (81  )   306   138   5,931   242   (103  )   16   28   (10  )   (160  )   39   (190  )   52   6   46   14   60   60   (15  )   (6  )   (8  )   (29  )   (11  )   (18  )   42   134   135                   FIRSTENERGY  SOLUTIONS  CORP.   CONDENSED  CONSOLIDATING  BALANCE  SHEETS   FIRSTENERGY  SOLUTIONS  CORP.   CONDENSED  CONSOLIDATING  BALANCE  SHEETS   As  of  December  31,  2015   FES   FG   NG   (In  millions)   Eliminations   Consolidated   ASSETS   (In  millions)   As  of  December  31,  2014   FES   FG   NG   Eliminations   Consolidated   ASSETS   CURRENT  ASSETS:   Cash  and  cash  equivalents   Receivables-­   Customers   Affiliated  companies   Other   Notes  receivable  from  affiliated  companies   Materials  and  supplies   Derivatives   Collateral   Prepayments  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   Customer  intangibles   Goodwill   Property  taxes   Derivatives   Other   LIABILITIES  AND  CAPITALIZATION   CURRENT  LIABILITIES:   Currently  payable  long-­term  debt   Short-­term  borrowings-­   Affiliated  companies   Other   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   Accumulated  deferred  income  taxes   Asset  retirement  obligations   Retirement  benefits   Derivatives   Other   2   275   451   59   11   470   154   70   66   1,558   14,311   5,765   8,546   1,157   9,703   1,327   —   10   1,337   —   61   23   40   79   384   587   13,185   512   —   8   542   139   76   104   181   1,562   5,605   2,527   8,132   791   600   831   332   38   899   3,491   13,185   $   —   $   2   $   —   $   —   $   —   403   4   1,210   204   —   —   18   1,841   6,367   2,144   4,223   249   4,472   —   —   10   10   16   —   —   12   —   318   346   6,669   $   229   $   389   8   146   118   93   1   61   1,045   2,944   2,122   5,066   —   —   191   305   1   61   558   6,669   $   —   461   19   805   213   —   —   —   1,498   8,233   3,775   4,458   878   5,336   1,327   —   —   1,327   —   —   —   28   —   21   49   8,210   $   308   $   —   —   368   —   62   —   9   747   4,476   847   5,323   —   697   640   —   —   803   2,140   8,210   $   —   (846  )   —   (2,410  )   —   —   —   —   (3,256  )   (382  )   (194  )   (188  )   —   (188  )   —   (7,452  )   —   (7,452  )   (316  )   —   —   —   —   12   (304  )   (11,200  )   $   (25  )   $   (2,410  )   —   (856  )   —   (86  )   —   45   (3,332  )   (7,420  )   (1,136  )   (8,556  )   791   (103  )   —   —   —   —   688   (11,200  )   $   275   433   36   406   53   154   70   48   1,475   93   40   53   30   83   —   7,452   —   7,452   300   61   23   —   79   33   496   9,506   $   —   $   2,021   —   884   21   7   103   66   3,102   5,605   694   6,299   —   6   —   27   37   35   105   9,506   $   136   $   $   $   CURRENT  ASSETS:   Cash  and  cash  equivalents   Receivables-­   Customers   Affiliated  companies   Other   Materials  and  supplies   Derivatives   Collateral   Prepayments  and  other   Notes  receivable  from  affiliated  companies   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   Customer  intangibles   Goodwill   Property  taxes   Derivatives   Other   Unamortized  sale  and  leaseback  costs   LIABILITIES  AND  CAPITALIZATION   CURRENT  LIABILITIES:   Currently  payable  long-­term  debt   Short-­term  borrowings-­   Affiliated  companies   Other   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   Accumulated  deferred  income  taxes   Asset  retirement  obligations   Retirement  benefits   Derivatives   Other   $   —   $   2   $   —   $   —   $   —   487   21   838   202   —   —   19   1,569   6,217   2,058   4,159   206   4,365   —   —   10   10   98   —   —   14   —   —   277   389   321   9   197   202   62   —   56   1,011   2,561   2,215   4,776   —   —   189   288   —   69   546   —   674   20   272   223   —   —   —   1,189   7,628   3,305   4,323   801   5,124   1,365   —   —   1,365   —   —   —   27   —   —   7   34   28   —   219   —   161   —   9   765   4,014   859   4,873   —   678   652   —   —   744   (1,120  )   (1,449  )   —   —   —   —   —   1   (2,568  )   (382  )   (191  )   (191  )   —   (191  )   (6,607  )   —   —   (6,607  )   (382  )   —   —   —   —   —   13   (1,449  )   —   (1,068  )   —   (123  )   —   47   (2,617  )   (6,575  )   (1,161  )   (7,736  )   824   (207  )   —   —   —   1   618   2   415   525   107   —   492   147   229   68   1,985   13,596   5,208   8,388   1,010   9,398   1,365   —   10   1,375   —   78   23   41   —   52   331   525   13,283   506   35   99   416   248   102   166   184   1,756   5,585   2,608   8,193   824   484   841   324   14   847   3,334   13,283   $   $   471   8,973   $   6,333   $   7,712   $   (369  )   (9,735  )   $   18   $   164   $   348   $   (24  )   $   $   8,973   $   6,333   $   2,074   7,712   $   (9,735  )   $   415   484   66   339   67   147   229   48   133   36   97   3   100   1,795   —   6,607   —   6,607   284   78   23   —   —   52   34   1,135   90   1,068   46   2   166   72   2,597   5,585   695   6,280   —   13   —   36   14   33   96   137                 FIRSTENERGY  SOLUTIONS  CORP.   CONDENSED  CONSOLIDATING  BALANCE  SHEETS   As  of  December  31,  2015   FES   FG   NG   Eliminations   Consolidated   (In  millions)   $   —   $   2   $   —   $   —   $   LIABILITIES  AND  CAPITALIZATION   CURRENT  LIABILITIES:   Currently  payable  long-­term  debt   $   $   496   9,506   $   6,669   $   8,210   $   (304  )   (11,200  )   $   13,185   —   $   229   $   308   $   (25  )   $   ASSETS   CURRENT  ASSETS:   Cash  and  cash  equivalents   Receivables-­   Customers   Affiliated  companies   Other   Materials  and  supplies   Derivatives   Collateral   Prepayments  and  other   Notes  receivable  from  affiliated  companies   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   Customer  intangibles   Goodwill   Property  taxes   Derivatives   Other   Short-­term  borrowings-­   Affiliated  companies   Other   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   Accumulated  deferred  income  taxes   Asset  retirement  obligations   Retirement  benefits   Derivatives   Other   —   403   4   1,210   204   —   —   18   1,841   6,367   2,144   4,223   249   4,472   —   —   10   10   16   —   —   12   —   318   346   389   8   146   118   93   1   61   1,045   2,944   2,122   5,066   —   —   191   305   1   61   558   —   461   19   805   213   —   —   —   1,498   8,233   3,775   4,458   878   5,336   1,327   —   —   1,327   —   —   —   28   —   21   49   —   —   368   —   62   —   9   747   4,476   847   5,323   —   697   640   —   —   803   —   (846  )   —   (2,410  )   —   —   —   —   (3,256  )   (382  )   (194  )   (188  )   —   (188  )   (7,452  )   —   —   (7,452  )   (316  )   —   —   —   —   12   (2,410  )   —   (856  )   —   (86  )   —   45   (3,332  )   (7,420  )   (1,136  )   (8,556  )   791   (103  )   —   —   —   —   688   2   275   451   59   11   470   154   70   66   1,558   14,311   5,765   8,546   1,157   9,703   1,327   —   10   1,337   —   61   23   40   79   384   587   512   —   8   542   139   76   104   181   1,562   5,605   2,527   8,132   791   600   831   332   38   899   3,491   13,185   105   9,506   $   $   6,669   $   2,140   8,210   $   (11,200  )   $   275   433   36   406   53   154   70   48   1,475   93   40   53   30   83   —   7,452   —   7,452   300   61   23   —   79   33   2,021   —   884   21   7   103   66   3,102   5,605   694   6,299   —   6   —   27   37   35   136   FIRSTENERGY  SOLUTIONS  CORP.   CONDENSED  CONSOLIDATING  BALANCE  SHEETS   As  of  December  31,  2014   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   Prepayments  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   Customer  intangibles   Goodwill   Property  taxes   Unamortized  sale  and  leaseback  costs   Derivatives   Other   LIABILITIES  AND  CAPITALIZATION   CURRENT  LIABILITIES:   Currently  payable  long-­term  debt   Short-­term  borrowings-­   Affiliated  companies   Other   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   Accumulated  deferred  income  taxes   Asset  retirement  obligations   Retirement  benefits   Derivatives   Other   2   415   525   107   —   492   147   229   68   1,985   13,596   5,208   8,388   1,010   9,398   1,365   —   10   1,375   —   78   23   41   —   52   331   525   13,283   506   35   99   416   248   102   166   184   1,756   5,585   2,608   8,193   824   484   841   324   14   847   3,334   13,283   $   —   $   2   $   —   $   —   $   —   487   21   838   202   —   —   19   1,569   6,217   2,058   4,159   206   4,365   —   —   10   10   98   —   —   14   —   —   277   389   6,333   $   164   $   321   9   197   202   62   —   56   1,011   2,561   2,215   4,776   —   —   189   288   —   69   546   6,333   $   —   674   20   272   223   —   —   —   1,189   7,628   3,305   4,323   801   5,124   1,365   —   —   1,365   —   —   —   27   —   —   7   34   7,712   $   348   $   28   —   219   —   161   —   9   765   4,014   859   4,873   —   678   652   —   —   744   2,074   7,712   $   —   (1,120  )   —   (1,449  )   —   —   —   1   (2,568  )   (382  )   (191  )   (191  )   —   (191  )   —   (6,607  )   —   (6,607  )   (382  )   —   —   —   —   —   13   (369  )   (9,735  )   $   (24  )   $   (1,449  )   —   (1,068  )   —   (123  )   —   47   (2,617  )   (6,575  )   (1,161  )   (7,736  )   824   (207  )   —   —   —   1   618   (9,735  )   $   415   484   66   339   67   147   229   48   1,795   133   36   97   3   100   —   6,607   —   6,607   284   78   23   —   —   52   34   471   8,973   $   18   $   1,135   90   1,068   46   2   166   72   2,597   5,585   695   6,280   —   13   —   36   14   33   96   8,973   $   137   $   $   $                 FIRSTENERGY  SOLUTIONS  CORP.   CONDENSED  CONSOLIDATING  STATEMENTS  OF  CASH  FLOWS   FIRSTENERGY  SOLUTIONS  CORP.   CONDENSED  CONSOLIDATING  STATEMENTS  OF  CASH  FLOWS   For  the  Year  Ended  December  31,  2015   FES   FG   NG   Eliminations   Consolidated   (In  millions)   NET  CASH  PROVIDED  FROM  (USED  FOR)   OPERATING  ACTIVITIES   $   (637  )   $   551   $   1,261   $   (24  )   $   1,151   For  the  Year  Ended  December  31,  2014   FES   FG   NG   Eliminations   Consolidated   (In  millions)   NET  CASH  PROVIDED  FROM  (USED  FOR)   OPERATING  ACTIVITIES   $   (600  )   $   408   $   785   $   (22  )   $   571   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   —   796   (17  )   —   (70  )   —   709   (5  )   —   10   —   —   (10  )   (67  )   —   45   67   (70  )   —   —   (5  )   37   (223  )   —   3   —   —   —   (372  )   4   296   —   (348  )   (28  )   —   (1  )   (81  )   (399  )   (190  )   —   733   (791  )   —   (533  )   —   —   (863  )   24   (98  )   —   —   (937  )   —   —   —   —   —   —   961   —   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   $   (72  )   —   —   —   $   (588  )   —   2   2   $   (1,180  )   —   —   —   $   961   —   —   —   $   341   —   (411  )   (126  )   (70  )   (6  )   (272  )   (627  )   (190  )   13   733   (791  )   (10  )   (11  )   4   (879  )   —   2   2   Other   activities   Net  cash  provided  from  (used  for)  financing   745   264   CASH  FLOWS  FROM  FINANCING  ACTIVITIES:   New  Financing-­   Long-­term  debt   Short-­term  borrowings,  net   Equity  contribution  from  parent   Redemptions  and  Repayments-­   Long-­term  debt   Short-­term  borrowings,  net   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   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   —   247   500   (1  )   —   (1  )   (8  )   —   —   —   —   (136  )   (1  )   (145  )   —   —   431   114   —   (269  )   —   (12  )   (169  )   —   307   —   —   (815  )   5   (672  )   —   2   447   —   —   (568  )   (123  )   (2  )   (246  )   (662  )   (233  )   —   1,163   (1,219  )   412   —   (539  )   —   —   —   (361  )   —   22   (178  )   —   (517  )   —   —   —   —   —   539   —   539   —   —   878   —   500   (816  )   (301  )   (15  )   246   (839  )   (233  )   307   1,163   (1,219  )   (817  )   —   4   —   2   2   Cash  and  cash  equivalents  at  end  of  period   $   —   $   2   $   —   $   —   $   138   139                         FIRSTENERGY  SOLUTIONS  CORP.   CONDENSED  CONSOLIDATING  STATEMENTS  OF  CASH  FLOWS   FIRSTENERGY  SOLUTIONS  CORP.   CONDENSED  CONSOLIDATING  STATEMENTS  OF  CASH  FLOWS   For  the  Year  Ended  December  31,  2015   FES   FG   NG   Eliminations   Consolidated   (In  millions)   NET  CASH  PROVIDED  FROM  (USED  FOR)   OPERATING  ACTIVITIES   $   (637  )   $   551   $   1,261   $   (24  )   $   1,151   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   activities   Net  cash  provided  from  (used  for)  financing   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   $   —   $   —   796   (17  )   —   (70  )   —   709   (5  )   —   10   —   —   (10  )   (67  )   —   (72  )   —   —   45   67   (70  )   —   —   (5  )   37   (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  )   (6  )   (272  )   (627  )   (190  )   13   733   (791  )   (10  )   (11  )   4   (879  )   —   2   2   For  the  Year  Ended  December  31,  2014   FES   FG   NG   Eliminations   Consolidated   (In  millions)   NET  CASH  PROVIDED  FROM  (USED  FOR)   OPERATING  ACTIVITIES   $   (600  )   $   408   $   785   $   (22  )   $   571   CASH  FLOWS  FROM  FINANCING  ACTIVITIES:   New  Financing-­   Long-­term  debt   Short-­term  borrowings,  net   Equity  contribution  from  parent   Redemptions  and  Repayments-­   Long-­term  debt   Short-­term  borrowings,  net   Other   —   247   500   (1  )   —   (1  )   431   114   —   (269  )   —   (12  )   Net  cash  provided  from  (used  for)  financing   activities   745   264   447   —   —   (568  )   (123  )   (2  )   (246  )   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   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   $   (8  )   —   —   —   —   (136  )   (1  )   (145  )   —   —   —   $   (169  )   —   307   —   —   (815  )   5   (672  )   —   2   2   $   (662  )   (233  )   —   1,163   (1,219  )   412   —   (539  )   —   —   —   $   —   (361  )   —   22   (178  )   —   (517  )   —   —   —   —   —   539   —   539   —   —   —   $   878   —   500   (816  )   (301  )   (15  )   246   (839  )   (233  )   307   1,163   (1,219  )   —   4   (817  )   —   2   2   138   139                         FIRSTENERGY  SOLUTIONS  CORP.   CONDENSED  CONSOLIDATING  STATEMENTS  OF  CASH  FLOWS   18.  SEGMENT  INFORMATION   For  the  Year  Ended  December  31,  2013   FES   FG   NG   Eliminations   Consolidated   FirstEnergy's  reportable  segments  are  as  follows:  Regulated  Distribution,  Regulated  Transmission  and  CES.   (In  millions)   Financial  information  for  each  of  FirstEnergy’s  reportable  segments  is  presented  in  the  tables  below.  FES  does  not  have  separate   reportable  operating  segments.   NET  CASH  PROVIDED  FROM  (USED  FOR)   OPERATING  ACTIVITIES   $   (1,429  )   $   753   $   776   $   (22  )   $   78   CASH  FLOWS  FROM  FINANCING  ACTIVITIES:   New  Financing-­   Short-­term  borrowings,  net   Equity  contribution  from  parent   Redemptions  and  Repayments-­   Long-­term  debt   Short-­term  borrowings,  net   Tender  premiums   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   Loans  to  affiliated  companies,  net   Other   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   $   864   1,500   (770  )   (244  )   (67  )   (4  )   1,279   (12  )   —   —   —   —   163   (1  )   150   —   —   —   $   371   —   (364  )   (505  )   —   (5  )   (503  )   (256  )   —   21   —   —   (15  )   (1  )   (251  )   (1  )   3   2   $   150   —   (90  )   —   —   —   60   (449  )   (250  )   —   940   (1,000  )   (77  )   —   (836  )   —   —   —   $   (954  )   —   22   749   —   —   (183  )   —   —   —   —   —   205   —   205   —   —   —   $   431   1,500   (1,202  )   —   (67  )   (9  )   653   (717  )   (250  )   21   940   (1,000  )   276   (2  )   (732  )   (1  )   3   2   During  the  fourth  quarter  of  2015,  management  concluded  that  FEV's  33-­1/3%  equity  investment  in  Global  Holding  was  no  longer  a   strategic  asset  to  CES.  Because  of  this  decision,  the  segment  reporting  was  modified  to  reflect  how  management  now  views  and   makes  investment  decisions  regarding  CES  and  Global  Holding.  The  external  segment  reporting  is  consistent  with  the  internal   financial  reports  used  by  FirstEnergy's  Chief  Executive  Officer  (its  chief  operating  decision  maker)  to  regularly  assess  performance  of   the  business  and  allocate  resources.  Disclosures  for  FirstEnergy's  reportable  operating  segments  for  2014  and  2013  have  been   reclassified  to  conform  to  the  current  presentation  reflecting  the  activity  of  FEV's  investment  in  Global  Holding  in  Corporate/Other.   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  includes  regulated  electric  generation  facilities  located  primarily  in  West  Virginia,  Virginia  and  New   Jersey  that  MP  and  JCP&L,  respectively,  own  or  contractually  control.  The  segment's  results  reflect  the  commodity  costs  of  securing   electric  generation  and  the  deferral  and  amortization  of  certain  fuel  costs.  This  business  segment  currently  controls  3,790  MWs  of   generation  capacity.     The  Regulated  Transmission  segment  transmits  electricity  through  transmission  facilities  owned  and  operated  by  ATSI,  TrAIL,  and   certain  of  FirstEnergy's  utilities  (JCP&L,  ME,  PN,  MP,  PE  and  WP).  This  segment  also  includes  the  regulatory  asset  associated  with   the  abandoned  PATH  project.  The  segment's  revenues  are  primarily  derived  from  rates  that  recover  costs  and  provide  a  return  on   transmission  capital  investment.  Except  for  the  recovery  of  the  PATH  abandoned  project  regulatory  asset,  these  revenues  are   primarily   from   transmission   services   provided   pursuant   to   its   PJM   Tariff   to   LSEs.   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,  Illinois,  Michigan,  New  Jersey  and   Maryland,  and  the  provision  of  partial  POLR  and  default  service  for  some  utilities  in  Ohio,  Pennsylvania  and  Maryland,  including  the   Utilities.  This  business  segment  currently  controls  13,162  MWs  of  capacity.    The    CES  segment’s  net  income  is  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.     Corporate  support  and  other  businesses  that  do  not  constitute  an  operating  segment,  interest  expense  on  stand-­alone  holding   company   debt   and   corporate   income   taxes   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,  2015,  Corporate/Other  had  $4.2  billion  of  stand-­alone  holding  company  long-­term  debt,  of  which  28%  was  subject  to   variable-­interest  rates  and  $1.7  billion  was  borrowed  under  the  FE  revolving  credit  facility.     140   141                               FIRSTENERGY  SOLUTIONS  CORP.   CONDENSED  CONSOLIDATING  STATEMENTS  OF  CASH  FLOWS   18.  SEGMENT  INFORMATION   For  the  Year  Ended  December  31,  2013   FES   FG   NG   Eliminations   Consolidated   FirstEnergy's  reportable  segments  are  as  follows:  Regulated  Distribution,  Regulated  Transmission  and  CES.   (In  millions)   Financial  information  for  each  of  FirstEnergy’s  reportable  segments  is  presented  in  the  tables  below.  FES  does  not  have  separate   reportable  operating  segments.   NET  CASH  PROVIDED  FROM  (USED  FOR)   OPERATING  ACTIVITIES   $   (1,429  )   $   753   $   776   $   (22  )   $   78   CASH  FLOWS  FROM  FINANCING  ACTIVITIES:   New  Financing-­   Short-­term  borrowings,  net   Equity  contribution  from  parent   Redemptions  and  Repayments-­   Long-­term  debt   Short-­term  borrowings,  net   Tender  premiums   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   Loans  to  affiliated  companies,  net   Other   activities   Net  cash  provided  from  (used  for)  investing   Net  change  in  cash  and  cash  equivalents   Cash  and  cash  equivalents  at  beginning  of  period   Cash  and  cash  equivalents  at  end  of  period   $   —   $   864   1,500   (770  )   (244  )   (67  )   (4  )   1,279   (12  )   —   —   —   —   163   (1  )   150   —   —   371   —   (364  )   (505  )   —   (5  )   (503  )   (256  )   —   21   —   —   (15  )   (1  )   150   —   (90  )   —   —   —   60   (449  )   (250  )   —   940   (1,000  )   (77  )   —   (251  )   (836  )   (1  )   3   2   $   —   —   —   $   (954  )   —   22   749   —   —   (183  )   —   —   —   —   —   205   —   205   —   —   —   $   431   1,500   (1,202  )   —   (67  )   (9  )   653   (717  )   (250  )   21   940   (1,000  )   276   (2  )   (732  )   (1  )   3   2   During  the  fourth  quarter  of  2015,  management  concluded  that  FEV's  33-­1/3%  equity  investment  in  Global  Holding  was  no  longer  a   strategic  asset  to  CES.  Because  of  this  decision,  the  segment  reporting  was  modified  to  reflect  how  management  now  views  and   makes  investment  decisions  regarding  CES  and  Global  Holding.  The  external  segment  reporting  is  consistent  with  the  internal   financial  reports  used  by  FirstEnergy's  Chief  Executive  Officer  (its  chief  operating  decision  maker)  to  regularly  assess  performance  of   the  business  and  allocate  resources.  Disclosures  for  FirstEnergy's  reportable  operating  segments  for  2014  and  2013  have  been   reclassified  to  conform  to  the  current  presentation  reflecting  the  activity  of  FEV's  investment  in  Global  Holding  in  Corporate/Other.   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  includes  regulated  electric  generation  facilities  located  primarily  in  West  Virginia,  Virginia  and  New   Jersey  that  MP  and  JCP&L,  respectively,  own  or  contractually  control.  The  segment's  results  reflect  the  commodity  costs  of  securing   electric  generation  and  the  deferral  and  amortization  of  certain  fuel  costs.  This  business  segment  currently  controls  3,790  MWs  of   generation  capacity.     The  Regulated  Transmission  segment  transmits  electricity  through  transmission  facilities  owned  and  operated  by  ATSI,  TrAIL,  and   certain  of  FirstEnergy's  utilities  (JCP&L,  ME,  PN,  MP,  PE  and  WP).  This  segment  also  includes  the  regulatory  asset  associated  with   the  abandoned  PATH  project.  The  segment's  revenues  are  primarily  derived  from  rates  that  recover  costs  and  provide  a  return  on   transmission  capital  investment.  Except  for  the  recovery  of  the  PATH  abandoned  project  regulatory  asset,  these  revenues  are   primarily   from   transmission   services   provided   pursuant   to   its   PJM   Tariff   to   LSEs.   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,  Illinois,  Michigan,  New  Jersey  and   Maryland,  and  the  provision  of  partial  POLR  and  default  service  for  some  utilities  in  Ohio,  Pennsylvania  and  Maryland,  including  the   Utilities.  This  business  segment  currently  controls  13,162  MWs  of  capacity.    The    CES  segment’s  net  income  is  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.     Corporate  support  and  other  businesses  that  do  not  constitute  an  operating  segment,  interest  expense  on  stand-­alone  holding   company   debt   and   corporate   income   taxes   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,  2015,  Corporate/Other  had  $4.2  billion  of  stand-­alone  holding  company  long-­term  debt,  of  which  28%  was  subject  to   variable-­interest  rates  and  $1.7  billion  was  borrowed  under  the  FE  revolving  credit  facility.     140   141                               On  February  12,  2014,  certain  of  FirstEnergy's  subsidiaries  sold  eleven  hydroelectric  power  stations  to  a  subsidiary  of  LS  Power  for   approximately  $394  million  (FES  -­  $307  million).  The  carrying  value  of  the  assets  sold  was  $235  million  (FES  -­  $122  million),  including   goodwill  of  $29  million  (FES  -­  $1  million).  Pre-­tax  income  for  the  hydroelectric  facilities  of  $155  million  and  $26  million  (FES  -­  $186   million  and  $22  million)  for  the  years  ended  December  31,  2014  and  2013,  respectively,  was  included  in  discontinued  operations  in   the  Consolidated  Statement  of  Income.  Included  in  income  for  discontinued  operations  in  the  year  ended  December  31,  2014,  was  a   pre-­tax  gain  on  the  sale  of  assets  of  $142  million  (FES  -­  $177  million).  Revenues  for  the  hydroelectric  facilities  of  $5  million  and  $33   million  (FES  -­  $5  million  and  $31  million)  for  years  ended  December  31,  2014  and  2013,  respectively,  were  included  in  discontinued   operations  in  the  Consolidated  Statement  of  Income.     Segment  Financial  Information   19.  DISCONTINUED  OPERATIONS   For  the  Years  Ended  December  31,   Regulated   Distribution   Regulated   Transmission   Competitive   Energy   Services   Corporate /  Other   Reconciling   Adjustments   Consolidated   (In  millions)   2015   External  revenues   Internal  revenues   Total  revenues   Depreciation   Amortization  of  regulatory  assets,  net   Impairment  of  long-­lived  assets   Investment  income  (loss)   Impairment  of  equity  method  investment   Interest  expense   Income  taxes  (benefits)   Income  (loss)  from  continuing  operations   Discontinued  operations,  net  of  tax   Net  income  (loss)   Total  assets   Total  goodwill   Property  additions   2014   External  revenues   Internal  revenues   Total  revenues   Depreciation   Amortization  of  regulatory  assets,  net   Impairment  of  long-­lived  assets   Investment  income  (loss)   Impairment  of  equity  method  investment   Interest  expense   Income  taxes  (benefits)   Income  (loss)  from  continuing  operations   Discontinued  operations,  net  of  tax   Net  income  (loss)   Total  assets   Total  goodwill   Property  additions   2013   External  revenues   Internal  revenues   Total  revenues   Depreciation   Amortization  of  regulatory  assets,  net   Impairment  of  long-­lived  assets   Investment  income  (loss)   Impairment  of  equity  method  investment   Interest  expense   Income  taxes  (benefits)   Income  (loss)  from  continuing  operations   Discontinued  operations,  net  of  tax   Net  income  (loss)   Total  assets   Total  goodwill   Property  additions   $   $   $   9,625   $   —   9,625   672   261   8   42   —   586   342   618   —   618   27,876   5,092   1,108   9,102   $   —   9,102   658   1   —   56   —   589   227   465   —   465   28,085   5,092   972   8,720   $   —   8,720   606   529   322   57   —   543   301   501   —   501   27,683   5,092   1,272   1,011   $   —   1,011   156   7   —   —   —   161   174   298   —   298   7,439   526   952   769   $   —   769   127   11   —   —   —   131   121   223   —   223   6,252   526   1,329   731   $   —   731   114   10   —   —   —   93   129   214   —   214   5,247   526   461   4,698   $   686   5,384   394   —   34   (16  )   —   192   50   89   —   89   16,365   800   588   5,470   $   819   6,289   387   —   —   54   —   189   (223  )   (417  )   86   (331  )   16,518   800   939   5,728   $   770   6,498   439   —   473   14   —   222   (140  )   (235  )   17   (218  )   16,782   800   827   (168  )   $   —   (168  )   60   —   —   (9  )   362   193   (262  )   (427  )   —   (427  )   507   —   56   (146  )   $   —   (146  )   48   —   —   2   —   168   (178  )   (58  )   —   (58  )   793   —   72   (121  )   $   —   (121  )   43   —   —   6   —   148   (105  )   (105  )   —   (105  )   712   —   78   (140  )   $   (686  )   (826  )   —   —   —   (39  )   —   —   11   —   —   —   —   —   —   (146  )   $   (819  )   (965  )   —   —   —   (40  )   —   (4  )   11   —   —   —   —   —   —   (166  )   $   (770  )   (936  )   —   —   —   (44  )   —   10   10   —   —   —   —   —   —   15,026   —   15,026   1,282   268   42   (22  )   362   1,132   315   578   —   578   52,187   6,418   2,704   15,049   —   15,049   1,220   12   —   72   —   1,073   (42  )   213   86   299   51,648   6,418   3,312   14,892   —   14,892   1,202   539   795   33   —   1,016   195   375   17   392   50,424   6,418   2,638   142   143               Segment  Financial  Information   19.  DISCONTINUED  OPERATIONS   For  the  Years  Ended  December  31,   Regulated   Distribution   Regulated   Transmission   Energy   Services   Corporate /  Other   Reconciling   Adjustments   Consolidated   Competitive   (In  millions)   $   9,625   $   1,011   $   4,698   $   On  February  12,  2014,  certain  of  FirstEnergy's  subsidiaries  sold  eleven  hydroelectric  power  stations  to  a  subsidiary  of  LS  Power  for   approximately  $394  million  (FES  -­  $307  million).  The  carrying  value  of  the  assets  sold  was  $235  million  (FES  -­  $122  million),  including   goodwill  of  $29  million  (FES  -­  $1  million).  Pre-­tax  income  for  the  hydroelectric  facilities  of  $155  million  and  $26  million  (FES  -­  $186   million  and  $22  million)  for  the  years  ended  December  31,  2014  and  2013,  respectively,  was  included  in  discontinued  operations  in   the  Consolidated  Statement  of  Income.  Included  in  income  for  discontinued  operations  in  the  year  ended  December  31,  2014,  was  a   pre-­tax  gain  on  the  sale  of  assets  of  $142  million  (FES  -­  $177  million).  Revenues  for  the  hydroelectric  facilities  of  $5  million  and  $33   million  (FES  -­  $5  million  and  $31  million)  for  years  ended  December  31,  2014  and  2013,  respectively,  were  included  in  discontinued   operations  in  the  Consolidated  Statement  of  Income.     2015   External  revenues   Internal  revenues   Total  revenues   Depreciation   Amortization  of  regulatory  assets,  net   Impairment  of  long-­lived  assets   Investment  income  (loss)   Impairment  of  equity  method  investment   Interest  expense   Income  taxes  (benefits)   Income  (loss)  from  continuing  operations   Discontinued  operations,  net  of  tax   Net  income  (loss)   Total  assets   Total  goodwill   Property  additions   2014   External  revenues   Internal  revenues   Total  revenues   Depreciation   Net  income  (loss)   Total  assets   Total  goodwill   Property  additions   2013   External  revenues   Internal  revenues   Total  revenues   Depreciation   Amortization  of  regulatory  assets,  net   Impairment  of  long-­lived  assets   Investment  income  (loss)   Impairment  of  equity  method  investment   Interest  expense   Income  taxes  (benefits)   Income  (loss)  from  continuing  operations   Discontinued  operations,  net  of  tax   Amortization  of  regulatory  assets,  net   Impairment  of  long-­lived  assets   Investment  income  (loss)   Impairment  of  equity  method  investment   Interest  expense   Income  taxes  (benefits)   Income  (loss)  from  continuing  operations   Discontinued  operations,  net  of  tax   Net  income  (loss)   Total  assets   Total  goodwill   Property  additions   $   9,102   $   769   $   5,470   $   —   9,625   672   261   8   42   —   586   342   618   —   618   27,876   5,092   1,108   —   9,102   658   1   —   56   —   589   227   465   —   465   28,085   5,092   972   606   529   322   57   —   543   301   501   —   501   27,683   5,092   1,272   —   1,011   156   7   —   —   —   161   174   298   —   298   7,439   526   952   —   769   127   11   —   —   —   131   121   223   —   223   6,252   526   1,329   —   731   114   10   —   —   —   93   129   214   —   214   5,247   526   461   686   5,384   394   —   34   (16  )   —   192   50   89   —   89   800   588   16,365   819   6,289   387   —   —   54   —   189   (223  )   (417  )   86   (331  )   16,518   800   939   770   6,498   439   —   473   14   —   222   (140  )   (235  )   17   (218  )   16,782   800   827   (168  )   $   —   (168  )   (146  )   $   —   (146  )   60   —   —   (9  )   362   193   (262  )   (427  )   —   (427  )   507   —   56   48   —   —   2   —   168   (178  )   (58  )   —   (58  )   793   —   72   43   —   —   6   —   148   (105  )   (105  )   —   (105  )   712   —   78   (140  )   $   (686  )   (826  )   —   —   —   (39  )   —   —   11   —   —   —   —   —   —   —   (4  )   11   —   —   —   —   —   —   (146  )   $   (819  )   (965  )   —   —   —   (40  )   (166  )   $   (770  )   (936  )   —   —   —   (44  )   —   10   10   —   —   —   —   —   —   15,026   —   15,026   1,282   268   42   (22  )   362   1,132   315   578   —   578   52,187   6,418   2,704   15,049   —   15,049   1,220   12   —   72   —   1,073   (42  )   213   86   299   51,648   6,418   3,312   14,892   —   14,892   1,202   1,016   539   795   33   —   195   375   17   392   50,424   6,418   2,638   $   8,720   $   —   8,720   731   $   5,728   $   (121  )   $   —   (121  )   142   143               20.  SUMMARY  OF  QUARTERLY  FINANCIAL  DATA  (UNAUDITED)   The  following  summarizes  certain  consolidated  operating  results  by  quarter  for  2015  and  2014.   FirstEnergy   CONSOLIDATED  STATEMENTS  OF  INCOME   (In  millions,  except  per  share  amounts)   2015   2014   Positions  Held  During  Past  Five  Years   Dates   Revenues   Other  operating  expense   Pension  and  OPEB  mark-­to-­market  adjustment   Provision  for  depreciation   Operating  Income  (Loss)   Income  (loss)  from  continuing  operations   before  income  taxes  (benefits)   Income  taxes  (benefits)  (1)   Income  (loss)  from  continuing  operations   Discontinued  operations  (net  of  income  taxes)   Net  Income  (Loss)   Earnings  (loss)  per  share  of  common  stock-­(2)   Basic  -­  Continuing  Operations   Basic  -­  Discontinued  Operations  (Note  19)   Basic  -­  Earnings  Available  to  FirstEnergy   Corp.   Diluted  -­  Continuing  Operations   Diluted  -­  Discontinued  Operations  (Note  19)   Diluted  -­  Earnings  Available  to  FirstEnergy   Corp.   952   242   313   236   (396  )   (170  )   (226  )   —   (226  )   (0.53  )   —   (0.53  )   (0.53  )   —   (0.53  )   Dec.  31   Sept.  30   June  30   $   3,541   $   4,123   $   850   —   328   908   Mar.  31   Dec.  31   Sept.  30   June  30   Mar.  31   4,182   1,182   —   294   391   3,897   $   3,483   $   1,057   —   319   594   3,888   $   858   —   308   716   3,496   $   1,021   —   302   292   901   835   316   (337  )   3,465   $   916   —   322   554   621   226   395   —   395   0.94   —   0.94   0.93   —   302   115   187   —   187   0.44   —   0.44   0.44   —   366   144   222   —   222   0.53   —   0.53   0.53   —   0.93   0.44   0.53   (574  )   (268  )   (306  )   —   (306  )   (0.73  )   —   (0.73  )   (0.73  )   —   (0.73  )   485   152   333   —   333   0.79   —   0.79   0.79   —   90   26   64   —   64   0.16   —   0.16   0.15   —   170   48   122   86   208   0.29   0.21   0.50   0.29   0.20   0.79   0.15   0.49   (1)      During  the  fourth  quarter  of  2014,  income  tax  benefits  of  $16  million  were  recorded  that  related  to  prior  periods.  The  out-­of-­period              adjustment  primarily  related  to  the  correction  of  amounts  included  in  the  Company’s  tax  basis  balance  sheet.  Management  determined  that              this  adjustment  was  not  material  to  2014  or  any  prior  period.   (2)      Total  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  4.  Stock-­Based  Compensation  for  additional  information.   FES   CONSOLIDATED  STATEMENTS  OF  INCOME   (In  millions)   2015   2014   Revenues   Other  operating  expense   Pension  and  OPEB  mark-­to-­market  adjustment   Provision  for  depreciation   Operating  Income  (Loss)   Income  (loss)  from  continuing  operations   before  income  taxes  (benefits)   Income  taxes  (benefits)   Income  (loss)  from  continuing  operations   Discontinued  operations  (net  of  income  taxes)   Net  Income  (Loss)   Dec.  31   Sept.  30   June  30   Mar.  31   Dec.  31   Sept.  30   June  30   Mar.  31   1,829   $   1,171   $   452   —   74   (148  )   1,521   $   356   —   83   90   1,338   $   246   —   79   240   1,452   $   468   —   79   (151  )   1,119   $   353   —   81   —   359   297   83   (321  )   329   57   84   25   413   —   80   12   1,377   $   1,342   $   (13  )   1   (14  )   —   (14  )   190   70   120   —   120   (25  )   (4  )   (21  )   —   (21  )   (5  )   (2  )   (3  )   —   (3  )   (347  )   (133  )   (214  )   —   (214  )   72   28   44   —   44   (154  )   (67  )   (87  )   —   (87  )   (159  )   (56  )   (103  )   116   13   144   145   Executive  Officers  as  of  February  16,  2016   Name   G.  D.  Benz   L.  M.  Cavalier   Age   56   Senior  Vice  President,  Strategy  (B)   Vice  President,  Supply  Chain  (B)   64   Chief  Human  Resources  Officer  (B)   Senior  Vice  President,  Human  Resources  (B)   D.  M.  Chack   65   Senior  Vice  President,  Marketing  and  Branding  (B)   President,  Ohio  Operations  (B)   Vice  President  (C)   Regional  President  (M)   Senior  Vice  President,  External  Affairs  (B)   Vice  President,  External  Affairs  (B)   M.  J.  Dowling   B.  L.  Gaines   51   62   Senior  Vice  President,  Corporate  Services  and  Chief  Information  Officer  (B)   Vice  President,  Corporate  Services  and  Chief  Information  Officer  (B)   Vice  President,  Shared  Services,  Administration  and  Chief  Information  Officer  (B)   C.  E.  Jones   60   President  and  Chief  Executive  Officer  (A)(B)   Chief  Executive  Officer  (F)   Executive  Vice  President  &  President,  FirstEnergy  Utilities  (A)(B)   Senior  Vice  President  &  President,  FirstEnergy  Utilities  (B)   President  (H)(I)   President  (C)(D)(L)   J.  H.  Lash   65   Executive  Vice  President  &  President,  FE  Generation  (A)(B)   Senior  Vice  President  &  President,  FirstEnergy  Utilities  (A)   C.  D.  Lasky   53   President,  FE  Generation  (B)   President  (G)(J)   Chief  Nuclear  Officer  (F)   President  and  Chief  Nuclear  Officer  (F)   President,  FirstEnergy  Nuclear  Operating  Company  (B)   Senior  Vice  President,  Human  Resources  (B)   Vice  President,  Fossil  Operations  (J)   Vice  President,  Fossil  Operations  &  Engineering  (J)   Vice  President  (G)   Vice  President,  Fossil  Fleet  Operations  (J)   Vice  President  (J)   Vice  President,  Fossil  Operations  (E)   J.  F.  Pearson   61   Executive  Vice  President  and  Chief  Financial  Officer  (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)   Senior  Vice  President  and  Chief  Financial  Officer  (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)   Senior  Vice  President  and  Treasurer  (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)   Vice  President  and  Treasurer  (A)(B)(C)(D)(E)(F)(J)(L)   Vice  President  and  Treasurer  (G)(H)(I)   D.  R.  Schneider   S.  E.  Strah   54   52   President  (E)   Senior  Vice  President  &  President,  FirstEnergy  Utilities  (B)   K.  J.  Taylor   42   Vice  President,  Controller  and  Chief  Accounting  Officer  (A)(B)   Vice  President  and  Controller  (C)(D)(E)(F)(G)(H)(I)(J)(L)   Vice  President  and  Assistant  Controller  (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)   President  (C)(D)(H)(I)(L)   Vice  President,  Distribution  Support  (B)   Regional  President  (K)   Assistant  Controller  (A)(B)(C)(D)(L)   Assistant  Controller  (H)(I)   Assistant  Controller  (E)(F)(G)(J)   2015-­present   2012-­2015   2015-­present   *-­2015   2015-­present   2011-­2015   2011-­2015   *-­2011   2011-­present   *-­2011   2012-­present   2011-­2012   *-­2011   2015-­present   2015-­present   2014   *-­2013   2011-­2015   *-­2015   *-­2011   2015-­present   2011-­2015   2011-­present   2011-­2012   *-­2011   *-­2011   2015-­present   2014-­2015   2014   2011-­2015   2011-­2013   *-­2011   *-­2011   2015-­present   2013-­2015   2012   *-­2012   2011-­2012   *-­present   2015-­present   2015-­present   2011-­2015   *-­2011   2013-­present   2013-­present   2012-­2013   *-­2012   2011-­2012   2012   2014-­present   *-­2013   2011-­2013   L.  L.  Vespoli   56   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)(J)(L)   Executive  Vice  President  and  General  Counsel  (G)(H)(I)   *  Indicates  position  held  at  least  since  January  1,  2011   (E)  Denotes  executive  officer  of  FES   (A)  Denotes  executive  officer  of  FE   (B)  Denotes  executive  officer  of  FESC   (F)  Denotes  executive  officer  of  FENOC   (G)  Denotes  executive  officer  of  AGC   (J)  Denotes  executive  officer  of  FG   (K)  Denotes  executive  officer  of  OE   (L)  Denotes  executive  officer  of  ATSI   (C)  Denotes  executive  officer  of  OE,  CEI  and  TE   (H)  Denotes  executive  officer  of  MP,  PE  and  WP   (M)  Denotes  executive  officer  of  CEI   (D)  Denotes  executive  officer  of  ME,  PN  and  Penn   (I)  Denotes  executive  officer  of  TrAIL  and  FET                 Executive  Officers  as  of  February  16,  2016   Name   G.  D.  Benz   Age   56   L.  M.  Cavalier   D.  M.  Chack   M.  J.  Dowling   B.  L.  Gaines   C.  E.  Jones   64   65   51   62   60   J.  H.  Lash   65   C.  D.  Lasky   53   (1)      During  the  fourth  quarter  of  2014,  income  tax  benefits  of  $16  million  were  recorded  that  related  to  prior  periods.  The  out-­of-­period              adjustment  primarily  related  to  the  correction  of  amounts  included  in  the  Company’s  tax  basis  balance  sheet.  Management  determined  that     J.  F.  Pearson   61            this  adjustment  was  not  material  to  2014  or  any  prior  period.   (2)      Total  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  4.  Stock-­Based  Compensation  for  additional  information.   D.  R.  Schneider   S.  E.  Strah   54   52   K.  J.  Taylor   42   L.  L.  Vespoli   56   20.  SUMMARY  OF  QUARTERLY  FINANCIAL  DATA  (UNAUDITED)   The  following  summarizes  certain  consolidated  operating  results  by  quarter  for  2015  and  2014.   FirstEnergy   CONSOLIDATED  STATEMENTS  OF  INCOME   (In  millions,  except  per  share  amounts)   2015   2014   Dec.  31   Sept.  30   June  30   Mar.  31   Dec.  31   Sept.  30   June  30   Mar.  31   $   3,541   $   4,123   $   3,465   $   3,897   $   3,483   $   3,888   $   3,496   $   1,021   4,182   1,182   Revenues   Other  operating  expense   Provision  for  depreciation   Operating  Income  (Loss)   Pension  and  OPEB  mark-­to-­market  adjustment   Income  (loss)  from  continuing  operations   before  income  taxes  (benefits)   Income  taxes  (benefits)  (1)   Income  (loss)  from  continuing  operations   Discontinued  operations  (net  of  income  taxes)   Net  Income  (Loss)   Earnings  (loss)  per  share  of  common  stock-­(2)   Basic  -­  Continuing  Operations   Basic  -­  Discontinued  Operations  (Note  19)   Basic  -­  Earnings  Available  to  FirstEnergy   Corp.   Corp.   Diluted  -­  Continuing  Operations   Diluted  -­  Discontinued  Operations  (Note  19)   Diluted  -­  Earnings  Available  to  FirstEnergy   952   242   313   236   (396  )   (170  )   (226  )   —   (226  )   (0.53  )   —   (0.53  )   (0.53  )   —   (0.53  )   850   —   328   908   621   226   395   —   395   0.94   —   0.94   0.93   —   916   —   322   554   302   115   187   —   187   0.44   —   0.44   0.44   —   1,057   —   319   594   366   144   222   —   222   0.53   —   0.53   0.53   —   901   835   316   (337  )   (574  )   (268  )   (306  )   —   (306  )   (0.73  )   —   (0.73  )   (0.73  )   —   (0.73  )   858   —   308   716   485   152   333   —   333   0.79   —   0.79   0.79   —   —   302   292   90   26   64   —   64   0.16   —   0.16   0.15   —   —   294   391   170   48   122   86   208   0.29   0.21   0.50   0.29   0.20   0.93   0.44   0.53   0.79   0.15   0.49   FES   (In  millions)   CONSOLIDATED  STATEMENTS  OF  INCOME   Revenues   Other  operating  expense   Provision  for  depreciation   Operating  Income  (Loss)   Pension  and  OPEB  mark-­to-­market  adjustment   Income  (loss)  from  continuing  operations   before  income  taxes  (benefits)   Income  taxes  (benefits)   Income  (loss)  from  continuing  operations   Discontinued  operations  (net  of  income  taxes)   Net  Income  (Loss)   2015   2014   Dec.  31   Sept.  30   June  30   Mar.  31   Dec.  31   Sept.  30   June  30   Mar.  31   $   1,171   $   1,338   $   1,119   $   1,377   $   1,342   $   1,521   $   1,452   $   329   57   84   25   (13  )   1   (14  )   —   (14  )   246   —   79   240   190   70   120   —   120   353   —   81   —   (25  )   (4  )   (21  )   —   (21  )   413   —   80   12   (5  )   (2  )   (3  )   —   (3  )   359   297   83   (321  )   (347  )   (133  )   (214  )   —   (214  )   356   —   83   90   72   28   44   —   44   468   —   79   (151  )   (154  )   (67  )   (87  )   —   (87  )   1,829   452   —   74   (148  )   (159  )   (56  )   (103  )   116   13   Positions  Held  During  Past  Five  Years   Senior  Vice  President,  Strategy  (B)   Vice  President,  Supply  Chain  (B)   Chief  Human  Resources  Officer  (B)   Senior  Vice  President,  Human  Resources  (B)   Senior  Vice  President,  Marketing  and  Branding  (B)   President,  Ohio  Operations  (B)   Vice  President  (C)   Regional  President  (M)   Senior  Vice  President,  External  Affairs  (B)   Vice  President,  External  Affairs  (B)   Senior  Vice  President,  Corporate  Services  and  Chief  Information  Officer  (B)   Vice  President,  Corporate  Services  and  Chief  Information  Officer  (B)   Vice  President,  Shared  Services,  Administration  and  Chief  Information  Officer  (B)   President  and  Chief  Executive  Officer  (A)(B)   Chief  Executive  Officer  (F)   Executive  Vice  President  &  President,  FirstEnergy  Utilities  (A)(B)   Senior  Vice  President  &  President,  FirstEnergy  Utilities  (B)   President  (H)(I)   President  (C)(D)(L)   Senior  Vice  President  &  President,  FirstEnergy  Utilities  (A)   Executive  Vice  President  &  President,  FE  Generation  (A)(B)   President,  FE  Generation  (B)   President  (G)(J)   Chief  Nuclear  Officer  (F)   President  and  Chief  Nuclear  Officer  (F)   President,  FirstEnergy  Nuclear  Operating  Company  (B)   Senior  Vice  President,  Human  Resources  (B)   Vice  President,  Fossil  Operations  (J)   Vice  President,  Fossil  Operations  &  Engineering  (J)   Vice  President  (G)   Vice  President,  Fossil  Fleet  Operations  (J)   Vice  President  (J)   Vice  President,  Fossil  Operations  (E)   Executive  Vice  President  and  Chief  Financial  Officer  (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)   Senior  Vice  President  and  Chief  Financial  Officer  (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)   Senior  Vice  President  and  Treasurer  (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)   Vice  President  and  Treasurer  (A)(B)(C)(D)(E)(F)(J)(L)   Vice  President  and  Treasurer  (G)(H)(I)   President  (E)   Senior  Vice  President  &  President,  FirstEnergy  Utilities  (B)   President  (C)(D)(H)(I)(L)   Vice  President,  Distribution  Support  (B)   Regional  President  (K)   Vice  President,  Controller  and  Chief  Accounting  Officer  (A)(B)   Vice  President  and  Controller  (C)(D)(E)(F)(G)(H)(I)(J)(L)   Vice  President  and  Assistant  Controller  (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)   Assistant  Controller  (A)(B)(C)(D)(L)   Assistant  Controller  (H)(I)   Assistant  Controller  (E)(F)(G)(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)(J)(L)   Executive  Vice  President  and  General  Counsel  (G)(H)(I)   Dates   2015-­present   2012-­2015   2015-­present   *-­2015   2015-­present   2011-­2015   2011-­2015   *-­2011   2011-­present   *-­2011   2012-­present   2011-­2012   *-­2011   2015-­present   2015-­present   2014   *-­2013   2011-­2015   *-­2015   *-­2011   2015-­present   2011-­2015   2011-­present   2011-­2012   *-­2011   *-­2011   2015-­present   2014-­2015   2014   2011-­2015   2011-­2013   *-­2011   *-­2011   2015-­present   2013-­2015   2012   *-­2012   2011-­2012   *-­present   2015-­present   2015-­present   2011-­2015   *-­2011   2013-­present   2013-­present   2012-­2013   *-­2012   2011-­2012   2012   2014-­present   *-­2013   2011-­2013   *  Indicates  position  held  at  least  since  January  1,  2011   (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   144   145                 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 www.amstock.com/company/firstenergy.asp. 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 www.amstock.com/company/firstenergy.asp 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 Rhonda S. Ferguson, Vice President and Corporate Secretary, 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. PRESORTED STD U.S. POSTAGE PAID AKRON, OH PERMIT No. 561 76 South Main Street, Akron, Ohio 44308-1890 

Continue reading text version or see original annual report in PDF format above