L-16-334, Beaver Valley, Unit 2 - Supplemental Information Regarding Pending Application for Order Consenting to Transfer of Licenses and Approving Conforming License Amendments

Beaver Valley, Unit 2 - Supplemental Information Regarding Pending Application for Order Consenting to Transfer of Licenses and Approving Conforming License Amendments

ML16350A077
Person / Time
Site:	Beaver Valley
Issue date:	12/15/2016
From:	Harden P A FirstEnergy Nuclear Operating Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CAC MF78066, L-16-334
Download: ML16350A077 (126)

Text

FENOC ,nffi 341 White Pond Drive Alcron. Ohio 44320 PauI A. Harden Sr. Vice President & Chief Operating Officer December 15, 2016 L-16-334 330-436-1 36010 cFR 50.8010 cFR 50.90 ATTN. Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001

SUBJECT:

Beaver Valley Power Station, Unit No. 2 Docket No. 50-412, License No.

NPF-73 Supplemental Information Resardinq Pendino Application for Order Consentinq to Transfer of Licenses and Approvinq Conforminq License Amendments (CAC No. MF 78066)

By letter dated June 24,2016 (Accession No. ML1 6182A155) and supplemented by letter dated September 13,2016 (Accession No. ML1 6257A235), FirstEnergy Nuclear Operating Company (FENOC) acting as agent for and on behalf of FirstEnergy Nuclear Generation, LLC (FENGen), The Toledo Edison Company (TE), and the Ohio Edison Company (OE), submitted an application to the Nuclear Regulatory Commission (NRC)requesting consent to the transfer of the leased interests in Beaver Valley Power Station,Unit No. 2 (BVPS 2) and approval of an administrative amendment to conform the license to reflect the proposed transfer.On November 4,2016, FirstEnergy Corp. released a combined quarterly financial report, Form 10-Q, for the quarter ending on September 30,2016, for FirstEnergy Solutions Corp. (FES) and itself. FES provides energy-related products and services to retail and wholesale customers through its subsidiaries, FirstEnergy Generation, LLC and FENGen. The report states that FES expects to have more than sufficient cash flow from operations in 2017 and 2018 to fund anticipated capital expenditures with no equity contributions from FirstEnergy Corp. However, given exposure to market price volatility and operational risks, FES faces significant financial risks that could impact its anticipated cash flow and liquidity. With a potential lack of viable financial alternative strategies, FES could take one or more of the following actions: (i) restructuring of debt Beaver Valley Power Station, Unit No. 2 L-16-334 Page 2and other financial obligations, (ii) additional borrowings (refer to the following descriptionof a $700 million credit facility), (iii) further asset sales or plant deactivations, or (iv) seek protection under bankruptcy laws. In the event FES seeks such protection, FENOC may similar$ seek protection under bankruptcy laws. A copy of the Form 10-Q (without exhibits) is enclosed.Moody's Investor Service and Standard and Poors each downgraded their ratingof the senior unsecured debt of FES on November 4,2016. Moody's Investor Services downgraded the debt to Caa1, while Standard and Poors downgradedthe debt to B. Standard and Poors further downgraded FES from B to CCC+ on December 1, 2016.FENOC has not identified any adverse material changes to the FENGen Pro Formaf ncome Statement that was enclosed in FENOC's June 24,2016 letter.FENOC's September 13,2016 letter stated that FES and Allegheny Energy Supply Company, LLC (AES) have a $1.5 billion credit facility, with FES having a sublimit of$900 million. As stated in a FES Form 8-K filed on December 6,2016, this credit facility has been terminated and replaced with a

$700 million two-year secured credit facility which includes a $500 million revolving credit facility and a

$200 million of surety credit support among FES as borrower, FirstEnergy Generation, LLC and FENGen as guarantors, and FirstEnergy Corp. as the lender. As stated in the most recent Form 10-Q for the quarter ending on September 30, 2016, FES had approximately

$3.+ billion in revenue, with a stockholder's equity of approximately

$3.0 billion. Therefore, FES continues to have the capability to meet its obligations under both the power supply agreement and the $400 million financial support agreement with FENGen.

Additionally, there have been a number of Director and Executive Personnel changes that have occurred in FirstEnergy Corp., FirstEnergy Solutions Corp.,and FirstEnergy Nuclear Generation, LLC since the June24,2016 (Accession No. ML16182A155) letter. The Directors and Executive Personnel forthe aforementioned three companies are United States citizens.There are no regulatory commitments contained in this letter. lf there are any questions, or if additional information is required, please contact Mr. Thomas A. Lentz, Manager - Fleet Licensing, at 330-315-6810.

Beaver Valley Power Station, Unit No. 2 L-16-334 Page 3 I declare under penalty of perjury that the foregoing is true and correct. Executed on December /f,,2016.

Enclosure:

FirstEnergy Corp. and FirstEnergy Solutions Corp. 10-Q for Quarter Ending September 30, 2016 (Without Exhibits)cc: Director, NRR NRC Region I Administrator NRC Resident Inspector NRR Project Manager Director BRP/DEP Site BRP/DEP Representative Enclosure L-16-334 FirstEnergy Corp. and FirstEnergy Solutions Corp. 10-Q for Quarter Ending September 30, 2016 (Without Exhibits)(122 Pages Follow)

UNITED STATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C.20549 FORM 1O.Q (Mark One)g QUARTERLY REPORT PURSUANT TO SECTTON 13 OR 1s(d) OF THE SECURTTTES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2016 ORtr TRANSTTION REPORT PURSUANT TO SECTTON 13 OR 15(d) OF THE SECURTTTES EXCHANGE ACT OF 1934For the transition period from CommissionFile Number Registrant; State of Incorporation;Address; and Telephone Number l.R.S. Employer ldentification No.333-21011 ooo-53742FIRSTENERGY CORP.(An Ohio Corporation) 76 South Main Street Akron, OH 44308 Telephone (800)736-3402FI RSTENERGY SOLUTIONS CORP.(An Ohio Corporation) c/o FirstEnergy Corp.76 South Main Street Akron, OH 44308 Telephone (800)736-3402 34-1843785 31-1560186 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or '15(d) of the Securities ExchangeAct of 1 934 during the preceding 12 months (or for such shorter period that the registrant was requiled to file such reports), and (2) has been subject to such filing requiremenls for the past 90 days.Yes EI No tr FirstEnergy Corp. and FirstEnergy Solutions Corp.

Indicate by check mark whether the registrant has submitted eleclronically and posted on its corporate Web site, it any, everyInteractive Data File required to be submitted and posted pursuant to Rule 405 ot Regulation S-T (5232.405 oI this chapteo during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes El No tr FirstEnergy Corp. and FirstEnergy Solutions Corp.Indicate by check mark whether the registrant is a large accelerated filer, an accelerated tiler, a non-accelerated filer, or a smallerreporting company. See the definitions of

large accelerated tiler,"'accelerated filsi'and "smaller reporting company'in Rule 12b'2 of the Exchange Act.Large Accelerated Filer EI Accelerated Filer tr Non-accelerated Filer (Do not check if a smaller reporting company) EI Smaller Reporting Company tr lndicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes tr No M FirstEnergy Corp. and FirstEnergy Solutions Corp.FirstEnergy Corp.N/A FirstEnergy Solutions Corp.

N/A Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: CLASS OUTSTANDING AS OF SEPTEMBER 30, 2016 FirstEnergy Corp., $0.10 par value FirstEnergy Solutions Corp., no par value FirstEnergy Corp. is the sole holder of FirstEnergy Solutions Corp. common stock.

425,743,282 7This combined Form 10-O is separately filed by FirstEnergy Corp. and FirstEnergy Solutions Corp.

Informalion contained herein relating to any individual registrant is filed by such registrant on its own behalt. No registrant makes any representation as lo information relating to the other registrant, except that information relating to FirstEnergy Solutions Corp. is also attributed lo FirstEnergy Corp.FlrctEnergy Web Slte and Olher Soclal M6dla Slte3 and AppllcatlonsEach of the registrants' Annual Reports on Form 10-K, Quarterly Reports on Form 10-O, Current Reporls on Form 8-K, and amendments to those reports filed with orfurnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchangs Acl ol'1934 are also made available tree of charge on orthrough the'lnvestors'page ot FirstEnsrgys web site at wvrw.firsteneryycorp.com.

These SEC filings are posted on the web site as soon as reasonably practicable after they are electronically filed with the SEC.Additionally, the registrants routinely post additional important infomation including press releases, investor presentiations and nolices of upcoming evenb, under the 'lnvestors" section of FirstEnergy's web site and recognize FirslEneqy's web site as achannelof distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosuteobligations under SEC Regulation FD. Investors may b* notilied of postings to the web site by signing up tor email alerts and RSS feeds on the 'lnvestor' page of FirstEnergys web site or through push alerb lrom FirstEnergy Investor Relations apps tor AppleInc.'s iPad@ and iPhone@

devices, which can be installed for free at the Appl@

App Store. FirstEnergy also uses Twitter@ and Facebool@ as additionalchannels of distribution to reach public investors and asa supplementalmeans of disclosing materialnon-public intormation for complying with ib disclosure obligations underSEC Regulation FD. Infomation contained on FiEtEnergy's website, Twitter@ handle or Facebook@

page, and any conesponding applications of those sites, shall not be deemed incorporated into,or to be part ot, this report.OIIIISSION OF CERTAIN INFORMATION FirstEnergy Solutions Corp. meeb the conditions set lorth in General Instruction H(1Xa) and (b) of FoIm 10'Q and is therefore tilingthis Form 10-Q with the reduced disclosure format specifi*d in General Instruction H(2) to Form 10-Q.

Foru/ard-Looking Statements: This Form 1O-Q includes forward-looking statements based on information currently available to management. Such siatemenb are subject to certain risks and uncertainties.

These stiatements include declarations regardingmanagement's intents, beliefs and current e)eectations. These statements typically contain, but ars not limited to, the lerms

'anticipate," "potential," "aeect,'"forecast," "target,' 'will,' 'intend," "belie\re,'"proiecl," "estimate,'

'plan" and similar $rords. FoMaI+

looking statements involve estimates, assumptions, known and unknown dsks, uncertainties and otherfactors hal may cause aclual results, performance or achievements to be materially difierent from any tuture results, performance or achievemenb expressed or implied by such forward{ookng 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 oarticular.. The ability to eperience growth in the Regulated Distribution and Regulated Transmission s*gments.. The accomplishment ofour regulatory and operational goals in connection with ourtransmission investnent plan, iltduding, but not limited to, the proposed transmission asset transfer to MAII and the etfeciiveness of our strategy to reflect a more regulated business prof ile.. Changes in assumptions regading economic corditions within our territories, assessmefi of the reliability of our transmission system, or the availability of capital or other resources supponing identified transmission investment opportunities.

The impact of the regulatory process and resulting outcomes on the matters at the federal level and in the various states in which we do business including, but not limited to, matters related to rates and the ESP lV.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-jurisdictionalwholesale 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 weatherevents, and all associated regulatory events or actions.

Changing energy, capacity and commodity market prices including, but not limited to, coal, naturalgas and oil prices, andtheir availability and impact on margins and asset valuations, including without limitation impairments thereon.The risks and uncertainties at the CES segment, including FES and its subsidiaries and FENOC, related to continued depressed wholesale energy and capacity markets, and the viability and/or success of strategic business alternatives, such as potential CES generating unit asset sales, the potential conversion of the remaining generation fleet from competitive operations to a regulated or regulated-like construct or the potential need to deactivate additional generating units.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 effectsof the EPA's CPP, CCR, CSAPR and MATS programs, including our estimated costs of compliance, GWA waste watereffluent 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 older regulated and competitive units, including the impact on vendor commitments, such as long{erm fuel and transportation agreements, and as it relates to the reliability of the transmission grid, the timing thereof.

The impact of other future changes to the operational status or avaihbility 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 N RC or as a result of the incident at Japan's Fukushima Daiichi Nuclear Plant).

lssues 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 limitedto, any such proceedings related to vendor commitments, such as long-term fuel and transportation agreements.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, theability to continue to reduce costs and to successfully execute our financial plans designed to improve our credit metrics andstrengthen our balance sheet through, among other actions, our cash flow improvement plan and other proposed capitalraising 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.

Changing market conditions that could affect the measurement of certain liabilities and the value of assets held in our NDTs, pension trusts and other trust funds, and cause us and/or our subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated.

The impact of changes to significant accounting policies.The 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 capitat and credit markets affecting us and our subsidiaries.

Further actions that may be taken by credit rating agencies that could negatively affect us and/or our subsidiaries' access to financing, increase the costs thereof, increase requirements to post additionalcollateralto support, oraccelerate payments under outstanding commodity positions, LOCs and other financial guarantees, and the impact of these events on the financialcondition and liquidity of FirstEnergy and/or its subsidiaries, specifically the subsidiaries within the CES segment.The risks and uncertainties surrounding FirstEnergy's need to obtain waivers from its bank group under FirstEnergy's credit facilities caused by a debt to total capitalization ratio, as defined under each of the revolving credit facilities, in excess of65% resulting from impairment charges or other events at CES.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.lssues 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 FEs common stockduring 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 actualdeclarations.

A security ]ating is not a recommendationto buy or hold securitiss and is subiecl to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.The foregoing factors should not be construed as exhaustive and should be read in conjunction with the other cautionary statements and risks that are included in FirstEnergys and FES'filings with the SEC, including but not limited to the most recenl An nual Report on Form 1 0-K and any subsequent Quarterly Reports on Form 1 0-Q. New factors emerge from time to time, and it is not possible lormanagement to predict all such factors, nor assess the impact of any such factor on FirstEnergryrs business or the e)dent to which any factor, or combination of factoF, may

@use results to differ materially from those contained in any forward-looking statements.

The registranb expressly disclaim any cunent intention to update, except as required by law, any foMardiooking statements contained herein as a result of new inlormation. ftJture events or otherwise.

TABLE OF CONTENTS Part l. Financial Information Glossary of TermsItem 1. Financial Statements FirstEnergy Corp.Consolidated Statements of Income (Loss)Consolidated Statements of Comprehensive Income (Loss)Consolidated Balance Sheets Consolidated Statements of Cash Flows FirstEnergy Solutions Corp.Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)Consolidated Balance Sheets Consolidated Statements of Cash FlowsCombined Notes To Consotidated Financial StatementsItem 2. Management's Discussion and Analysis of Registrant and Subsidiaries FirstEnergy Corp. Management's Discussion and Analysis of Financial Condition and Results of Operations Management's Narrative Analysis ol Results of Operations FirstEnergy Solutions Corp.Item 3. Quantitative and Qualitative Disclosures About Market RiskItem 4. Controls and ProceduresPart ll. Other InformationItem 1. Legal ProceedingsItem 1A. Risk Factors Item 2. Unregistered Sales of Equity Securities and Use of Proceeds Item 3. Defaults Upon Senior SecuritiesItem 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits 1 2 3 4 5 6 7 8 57 57 108 108 110 110 110 110 111 GLOSSARY OF TERMSThe tollowing abbreviations and acronyms are used in this report to identily FirstEnergy Corp. and iF current and lormersubsidiaries:

Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy onFebruary 25,2011. As of January 1,20'14, AE merged with and into FirstEnergy Corp.

AESC Allegheny Energy Service Corporation, a subsidiary of FirstEnergy Corp.AE Supply Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary AGC Allegheny Generating Company, a generation subsidiary of AE Supply and equity method investee of MP.ATSI 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, CEI The Cleveland Electric llluminating Company, an Ohio electric utility operating subsidiary CES Competitive Energy Services, a reportable operating segment of FirstEnergy FE FirstEnergy Corp,, a public utility holding company FENOC FirstEnergy Nuclear Operating Company, which operates NG's nuclear generating facilities FES 5ifi,$$l3lrsolutions Corp., together with its consolidated subsidiaries, which provides energy-related products FESC FirstEnergy Service Company, which provides legal, financial and other corporate support services FET FirstEnergy Transmission, LLC, formerly known as Allegheny Energy Transmission, LLC which is the parent of ATSI, TrAIL and MAIT, and has a joint venture in PATH, FEV FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures FG t,lj[ili.;gt Generation, LLC, a wholly owned subsidiary of FES, which owns and operates non-nuclear generating FirstEnergy FirstEnergy Corp., together with its consolidated subsidiaries Global Holding O'"Jrfl Mining Holding Company, LLC, a joint venture between FEV WMB Marketing Ventures, LLC and Pinesdale Global Rai! A subsidiary of Global Holding that owns coaltransportation operations near Roundup, Montana JCP&L Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary MAIT Mid-Atlantic lnterstate Transmission, LLC, a subsidiary of FET, formed to own and operate transmission facilities ME Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary MP Monongahela Power Company, a West Virginia electric utility operating subsidiary NG FirstEnergy Nuclear Generation, LLC, a subsidiary of FES, which owns nuclear generating lacilities OE Ohio Edison Company, an Ohio electric utility operating subsidiaryOhio Companies CEl, OE and TE PATH Potomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP PATH-Allegheny PATH Allegheny Transmission Company, LLC PATH-WV PATH West Virginia Transmission Company, LLC PE The Potomac Edison Company, a Maryland and West Virginia electric utility operating subsidiary Penn Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE Pennsylvania Companies ME, PN, Penn and WP PN Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary PNBV PNBV Capital Trust, a special purpose entity created by OE in 1996 Signal Peak An indirect subsidiary of Global Holding that owns mining operations near Roundup, Montana TE The Toledo Edison Company, an Ohio electric utility operating subsidiary TrAIL Trans-Allegheny Interstate Line Company, a subsidiary of FET, which owns and operates transmission facilities Utilities OE, CEl, TE, Penn, JCP&L, ME, PN, MP, PE and WP WP West Penn Power Company, a Pennsylvania electric utility operating subsidiaryThe following abbreviations and acronyms are used to identify frequently used terms in this report: AAA American Arbitration Association AEP American Eleciric Power Company, Inc.AFS Availablejor-sale AFUDC Allowance for Funds Used During Construction ALJ Administrative Law Judge AOCI Accumulated Other Comprehensive lncome Apple@ Apple@, iPad@

and iPhone@ are registered trademarks of Apple Inc.

ARO ARR ASU BGS BNSF BRA CAA ccR CDWR CERCLA CFIP CFR COz CPP CSAPR CSX CTA CWA DCR DMR DR DSIC DSP EDC EE&C EGS ELPC EmPOWER Maryland ENEC EPA ERO ESP IV ESP IV PPA Facebook@FASB FERC Fitch FMB FPA FTR GAAP GHG GWH H8554 HCI tcE IRP IRS rso KV KWH LOC LSE LTllPsAsset Retirement ObligationAuction Revenue Right Accounting Standards Update Basic Generation Service BNSF Railway Company PJM RPM Base ResidualAuctionClean Air ActGoal Combustion ResidualsCalifornia Department of Water ResourcesComprehensive Environmental Response, Compensation, and Liability Act of 1980Cash Flow lmprovement Project Code of Federal RegulationsCarbon Dioxide EPA's Clean Power PlanCross-State Air Pollution Rule CSX Transportation, Inc.Consolidated Tax AdjustmentClean WaterAct Delivery Capital RecoveryDistribution Modernization RiderDemand Response

Distribution System lmprovement Charge Default Service PlanElectric Distribution Com panyEnergy Efficiency and Conservation Electric Generation SupplierEnvironmental Law

& Policy CenterEmPower Maryland Energy Efficiency Act Expanded Net Energy CostUnited States Environmental Protection Agency Electric Reliability Organization Electric Security Plan lV Unit Power Agreement entered into on April 1 , 2016 by and between the Ohio Companies and FES Facebook is a registered trademark of Facebook, Inc.Financial Accounting Standards BoardFederal Energy Regulatory CommissionFitch Ratings First Mortgage Bond Federal PowerAct Financial Transmission RightAccounting Principles Generally Accepted in the United States of AmericaGreenhouse Gases

Gigawatt-hourOhio House Bill No. 554Hydrochloric Acid Intercontinental Exchange, lnc.

Integrated Resource PlanInternal Revenue ServiceI ndependent System Operator Kilovolt Kilowatt-hourLetter of Credit Load Serving Entity Long-Term I nf rastructu re lmprovement Plans MATS MDPSC MISO MLP Mercury and Air Toxics StandardsMaryland Public Service CommissionMidcontinent Independent System Operator, Inc.Master Limited Partnership One Million British Thermal Units Moody's Investors Service, Inc.Minimum Offer Price RuleMulti-Value Project

Megawatt Megawatt-hourNational Ambient Air Quality Standards Nuclear Decommissioni ng Trust North American Electric Reliability CorporationUnited States Court of Appeals for the Ninth Circuit New Jersey Board of Public UtilitiesNon-Market Based Northwestern Ohio Aggregation Coalition Net Operating Loss Notice of Violation Nitrogen OxideNational Pollutant Discharge Elimination System Nuclear Regulatory Commission New Source ReviewNon-Util ity GenerationNew York State Public Service Commission Ohio Consumers' CounselOther Post-Employment Benef its Other Than Temporary lmpairmentsOhio Valley Electric CorporationPennsylvania Department of Environmental Protection Polychlorinated Biphenyl Pollution Control Revenue BondPJM Interconnection, L.L.C.The aggregate of the zones within PJM PJM Open Access Transmission TariffParticulate Matter

Provider of Last Resort Purchase of ReceivablesPurchase Power AgreementParts Per BillionPennsylvania Public Utility Commission Power Supply Agreement Prevention of Significant Deterioration Public Utilities Commission of Ohio Public Utility Regulatory Policies Act of 1978 Resource Conservation and Recovery ActRenewable Energy CreditReal Estate Investment TrustReliabil ity Frrsf CorporationRequest for Proposal Regional Greenhouse Gas Initiative Return on EquityReliability Pricing Model Retail Rate Stability mmBTU Moody's MOPR MVP MW MWH NAAQS NDT NERC Ninth Circuit NJBPU NMB NOAC NOL NOV NOx NPDES NRC NSR NUG NYPSC occ OPEB OTTI OVECPA DEP PCB PCRB PJM PJM Region PJM Tariff PM POLR POR PPA PPB PPUC PSA PSD PUCO PURPA RCRA REC REIT RFC RFP RGGI ROE RPM RRS iv RSS RTEP RTO S&P S8221SB31 O SB32O SBC SEC Rich Site Summary Regional Transmission Expansion PlanRegional Transm ission OrganizationStandard & Poor's Ratings Service Amended Substitute Ohio Senate Bill No. 221 Substitute Ohio Senate BillNo.310Ohio Senate Bill No.

320Societal Benef its ChargeUnited States Securities and Exchange Commission SEC Regulation FD SEC Regulation Fair DisclosureSeventh Circuit United States Court of Appeals for the Seventh Circuit SIP State lmplementation Plan(s) Under the Clean Air Act SOz Sulfur DioxideSixth Circuit United States Court of Appeals for the Sixth Circuit SOS Standard Offer Service SPE Special Purpose Entity SREC Solar Renewable Energy Credit SSO Standard Service Offer TDS Total Dissolved Solid TMI-2 Three Mile lsland Unit 2 TO Transmission Owner Twitter@ Twitter is a registered trademark of Twitter, lnc.

' ?;$H of.Appeals for United states court of Appears for the District of columbia circuir VIE Variable Interest Entity VSCC Virginia State Corporation Commission WVDEP West Virginia Department of Environmental Protection WVPSC Public Service Commission of West Virginia PART I. FINANCIAL INFORMATIONITEM I.Financial Statements (ln millions, except per share amounts)REVENUES: Regulated Distribution Regulated Transm ission Unregulated businessesTotal revenues*

OPERATING EXPENSES: Fuel Purchased powerOther operating expenses Provision for depreciation Amortization of regulatory assets, net Generaltaxes lmpairment of assets (Note 2)Total operating expensesOPERATING INCOMEOTHER TNCOME (EXPENSE):

Investment income (loss)Interest expenseCapitalized f inancing costs Total other expense TNGOME (LOSS) BEFORE TNCOME TAXESINCOME TAXESNET TNCOME (LOSS)EARNTNGS (LOSSES) pER SHARE OF COMMON STOCK: Basic DilutedWEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:

Basic DilutedDIVIDENDS DECLARED PER SHARE OF COMMON STOCK FIRSTENERGY CORP.CoNSoLTDATED STATEMENTS OF INCOME (LOSS)(Unaudited)

For the Three Months Ended For the Nine Months Ended September 30 September 30 2016 2015 2016 2015 824 755 930 1,251 2,940 3,305 3,917 4,123 11,187 11,485$ 2,702 $285 450 979 953 311 98 265 7,423 $7,425482 1,269 1,378 2,624 $248 1,209 842 328 110 236 2,992 3,311 2,835 2,799 974 969 222 201 786 747_ I 1,447 24 3,056 3,215 10,525 9,429 861 908 2,056 28 (286)28 (285)26 (863)79 (14)(846)93 (28) 75 (230) Q87t (70e) v67l 621 226 631 251 380 (47\ 1,289 334 485 3s5 $(3e1) $804 0.89 0.89 425 427 0.72 $0.94 0.93 0.72 $(0.e0)

(0,e0)1.91 1.90 422 423 1.44$

$$$$$423 425 424 425 1.44 $* Includes excise tax collections of $111 million and

$109 million in the three months ended September 30, 2016 and 2015, respectively, and $310 million and $320 million in the nine months ended September 30, 2016 and 2015, respectively.

The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.

FIRSTENERGY CORP.CoNSoLTDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)(Unaudited)

For the Three Months Ended September 30 2016 2015 2016 2015 For the Nine Months Ended September 30 (ln millions)NET TNCOME (LOSS)OTHER COMPREHENSTVE TNCOME (LOSS): Pension and OPEB prior service costs Amortized losses on derivative hedges Change in unrealized gains on available-for-sale securitiesOther comprehensive income (loss)Income taxes (benefits) on other comprehensive income (loss)Other comprehensive income (loss), net of tax GoMPREHENSlVE TNCOME (LOSS)380 $(381) $(18)2 4 (12)(5)

(7)(31)2 (11)(40)

(15)(25)(54)6 67 (e4)4 (21)6 (42)19 (111 )13 (6e)373 $370 $(368) $ 735 The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.

FIRSTENERGY CORP.CONSOLIDATED BALANCE SHEETS (Unaudited)(ln millions, except share amounts)

September 30, December 31, 2015 ASSETSCURRENT ASSETS:

Cash and cash equivalents Receivables-Customers, net of allowance for uncollectible accounts of

$61 in 2016 and

$69 in 2015Other, net of allowance for uncollectible accounts of

$3 in 2016 and $5 in 2015 Materials and supplies Prepaid taxes Derivatives Collateral Other PROPERil PLANT AND EQUIPMENT In service Less - Accumulated provision for depreciationConstruction work in progress INVESTMENTS:

Nuclear plant decommissioning trusts Other DEFERRED CHARGES AND OTHER ASSETS:

Goodwill (Note 2)Regulatory assets OtherLIABILITIES AND CAPITALIZATIONCURRENT LIABILITIES:

Currently payable long-term debt Short-term borrowings Accounts payable Accrued taxes Accrued compensation and benefits Derivatives Other CAPITALIZATION:Common stockholders' eq uity-Common stock, $0.10 par value, authorized 490,000,000 shares - 425,743,282 and 423,560,397 shares outstanding as of September 30, 2016 and December 31 , 2015, respectively Other paid-in capital Accumulated other comprehensive income Retained earnings Total common stockholders' equity Noncontrolling interest Totalequity Long-term debt and other long-term obligationsNONCUR RENT LIABILITIES :

Accumulated deferred income taxes Retirement benefitsAsset retirement obligations Deferred gain on sale and leaseback transaction Adverse power contract liability Other COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 12)551 1,470 159 699 204 152 89 156 131 1 ,415 180 785 135 157 70 167 3,480 3,040 50,889 15,450 49,952 15,160 35,439 2,394 34,792 2,422 37,833 37.214-2,502 533 3,035 2,788-2,282 506 5,618 1,088 907 6,418 1,348 1,286 7.613 9.052 1 ,166 1,708 1,075 519 334 106 694 42 9,952 171 2,256 11,503 12,421 1 11,503 18,532 12,422 19,099 30.035 31.521-7,136 4,080 1,459 765 174 1,269 6,773 4,245 1 ,410 791 197 1,555 14,883$ 51,961 14,971$ s2,094$_51,gq]-

$ saqq_1,216 2,975 944 537 365 91 915 7,043 5.602-43 10,012 184 1,264 The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.

(ln millions)FIRSTENERGY CORP.CONSOLIDATED STATEMENTS OF CASH (Unaudited)

FLOWSFor the Nine Months Ended September 30 2016 2015 CASH FLOWS FROM OPERATING ACTIVITIES:

Net Income (loss)Adiustments to reconcile net income (loss) to net cash from operating activities-Depreciation and amortization, including nuclear fuel, regulatory assets and customer intangible asset amortization Deferred purchased power and other costs Deferred income taxes and investment tax credits, net lmpairment of assets (Note 2)I nvestment im pairm ents Deferred costs on sale leaseback transaction. net Retirement benefits, net of payments Pension trust contributions Commodity derivative transactions, net (Note 9)Lease payments on sale and leaseback transactionChanges in current assets and liabilities-Receivables Materials and supplies Prepayments and other current assets Accounts payable Accrued taxesAccrued interest Accrued compensation and benefitsOther current liabilities Cash collateral, net Other Net cash provided from operating activitiesCASH FLOWS FROM FINANCING AGTIVITIES:New Financing-Long-term debt Short-term borrowings, net Redemptions and Repayments-Long-term debtCommon stock dividend payments Other Net cash provided from (used for) financing activitiesCASH FLOWS FROM INVESTING ACTIVITIES:

Property additionsNuclear fuel Sales of investment securities held in trusts Purchases of investment securities held in trustsAsset removalcosts Other Net cash used for investing activitiesNet change in cash and cash equivalentsCash and cash equivalents at beginning ol periodCash and cash equivalents at end of period (2,476\ (2,287)420 1 131 85--(381)1,440 (34)318 1,447 13 36 45 (2e7)(10)(s4)(34)45 (28)(17)(81)36 2 17 25 132 804 1,383 (73)428 24 70 37 (18)(143)(64)(102)7 32 (43)(285)(68)37 16 26 59 190 2.580 2,317 1,094 134 (781)(455)(11)(2s)521 1,275 (1 ,017)(458)(s)316 (2,156)(1e5)1,361 (1,437\(101 )52 (2,025)(101)1,126 (1 ,213)(111)37 The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.

FIRSTENERGY SOLUTIONS CORP.coNsoLrDATED STATEMENTS OF TNCOME (LOSS) AND COMPREHENSTVE TNCOME (LOSS)(Unaudited)(ln millions)STATEMENTS OF INCOME (LOSS)REVENUES: Electric sales to non-affiliates Electric sales to affiliates OtherTotal revenues OPERATING EXPENSES: Fuel Purchased power from affiliates Purchased power from non-affiliatesOther operating expensesProvision for depreciation Generaltaxes lmpairment of assets (Note 2)Total operating expenses oPERATTNG TNCOME (LOSS)OTHER TNCOME (EXPENSE):

Investment income (loss)Miscellaneous income lnterest expense - affiliates lnterest expense - other Capitalized interest Total other expense rNcoME (LOSS) BEFORE TNCOME TAXES (BENEFTTS)rNcoME TAXES (BENEFTTS)

NET TNCOME (LOSS)STATEMENTS OF COMPREHENSIVE INCOME (LOSS)NET TNCOME (LOSS)OTHER COMPREHENSTVE TNCOME (LOSS): Pension and OPEB prior service costsAmortized losses (gains) on derivative hedges Change in unrealized gains on available-for-sale securitiesOther comprehensive income (loss)Income taxes (benefits) on other comprehensive income (loss)Other comprehensive income (loss), net of taxGoMPREHENSTVE TNCOME (LOSS)For the Three Months For the Nine MonthsEnded September 30 Ended September 30 ffiffi$ 952 $ 1,157 $ 2,917 $3,146 111 37 135 46 360 547 124 141 1 ,100 1,338 3,401 3,834 202 245 191 103 186 401 316 246 83 79 21 24 595 440 829 925 250 66 540 666 250 1,336 996 240 78 16 999 1,098 3,645 3,582 240 (244)252 101 24 1 (3)(36)I (s)(21)1 (2)(36)8 (50)190 56 4 (6)(10e)27 (28)(272)(5)(7)5 (6)(110)26 (e2)96 160 70 40$120 $(267) $96 40$120 $(267) $96 (3) (4)(10) (12)1-(2)5 (11) 61 (20)3 -11o 51 1 (6) 20 (13)-- s1 -- al 9__ 42 !____ 111 g_gqq !____ ?5 The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.

FIRSTENERGY SOLUTIONS CORP.CONSOLIDATED BALANCE SHEETS (Unaudited)(ln millions, except share amounts)

September 30, December 31, 2016 2015 ASSETSCURRENT ASSETS:Cash and cash equivalents Receivables-Customers, net of allowance for uncollectible accounts of

$6 in 2016 and

$8 in 2015 Affiliated companiesOther, net of allowance for uncollectible accounts of $3 in 2016 and 2015Notes receivable from affiliated companies Materials and supplies Derivatives Collateral Prepayments and other PROPERTY, PLANT AND EQUIPMENT:

ln service Less - Accumulated provision for depreciationConstruction work in progress INVESTMENTS:

Nuclear plant decommissioning trusts Other DEFERRED CHARGES AND OTHER ASSETS:Customer intangibles Goodwill (Note 2)Property taxes Derivatives OtherLIABILITIES AND CAPITALIZATIONCURRENT LIABILITIES:

Currently payable long-term debt Short-term borrowings-Affiliated companies Other Accounts payable-Affiliated companies Other Accrued taxes Derivatives Other CAPITALIZATION:

Common stockholder's equity-Common stock, without par value, authorized 750 shares - 7 shares outstanding asof September 30, 2016 and December 31 ,2015 Accumulated other comprehensive income Retained earnings Total common stockholder's equity Long-term debt and other long-term obligations NONCURRENT LIABILITIES:

Deferred gain on sale and leaseback transaction Accumulated deferred income taxes Retirement benefitsAsset retirem ent obligations Derivatives Other COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOIE 12)2$2 275 451 59 11 470 154 70 66 225 482 55 26 403 146 85 72 1,496 1,558 14,100 14,311 5,822 5,765 8,278 8,546 1,048 1j57 9,326 9,703-1,542 10 1,327 10 1.552 1,337-11 10 98 374 61 23 40 79 367 493 570$ 12,867 $ 13,168 182 $'1 393 89 72 89 182 512 8 542 139 76 104 181 1,108 1 ,562 3,653 77 3,613 46 1,679 1,946 5,409 5,605 2,815 2,510 8.224 8,115 791 600 332 831 38 899 765 734 219 887 50 880 3.535 3,491--$ 12,86r_ $ 13,168 The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.

FIRSTENERGY SOLUTIONS CORP.CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) fln millions)CASH FLOWS FROM OPERAilNG AGTIVITIES:Net income (loss)Adjustments to reconcile net income (loss)to net cash from operating activities-Depreciation and amortization, including nuclear fuel and customer intangible asset amortization Deferred costs on sale and leaseback transaction, netDelerred income taxes and investment tax credits, net Investment impairments Pension trust contributionCommodity derivative transactions, net (Note 9)Lease payments on sale and leaseback transaction lmpairment of assets (Note 2)Changes in current assets and liabilities-Receivables Materials and supplies Accounts payable Accrued taxes Accrued compensation and benefitsOther current liabilitiesCash collateral, net OtherNet cash provided trom operating activitiesCASH FLOWS FROM FINANCING ACTIVITIES:New financing-Long-term debtShort-term borrowings, net Redemptions and repayments-Long-term debtShort-term borrowings, net Other Net cash provided from (used for)financing activitiesCASH FLOWS FROM INVESTING ACTIVITIES:

Property additionsNuclear fuelSales of investment securities held in trusts Purchases o{ investment securities held in trusts Cash investmentsLoans to affiliated companies, net OtherNet cash used for investing activities Net change in cash and cash equivalentsCash and cash equivalents at beginning of periodCash and cash equivalents at end of period For the Nine Months Ended September 30 2016 2015;6 (16)604 (267) $463 36 90 12 (138)(10)(e4)540 19 25 (6e)(6)422 37 139 63 (6s)(102)16 171 (1)(241)(28)2 24 107 (4)471 101 (503)(7)-'1 (382)

(10e)(5)(1s7)(432)

(1e5)576 (61e)10 (15)I (341)(101)503 (546)(10)16 (666) @7s)$2 The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.

2; FIRSTENERGY CORP. AND SUBSIDIARIESCOMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note Number 1 2 3 4 5 6 7 8 I 10 11 12 13 14Organization and Basis of PresentationAsset lmpairments Earnings Per Share of Common Stock Pension and Other Postemployment Benefits Accumulated Other Comprehensive Income Income Taxes Variable Interest EntitiesFair Value MeasurementsDerivative I nstrumentsAsset Retirement Obligations Regulatory MattersCommitments, Guarantees and ContingenciesSupplemental Guarantor lnformation Segment Information Page Number 9 12 13 13 15 18 19 21 26 33 33 41 46 55 COMBINED NOTES TO CONSOLIDATED FINANCIAL STATE ENTS (Unaudlbd)

1. ORGANIZATION AND BASIS OF PRESENTATION Unless otheru/ise indicated, defined terms and abbreviations used herein have the meanings set brth in the accompanying Glossaryof Terms.FirstEnergy Corp. was organized under the laws of the State ot Ohio in 1996. FE's principal business is the holding, dkectly or indirectly, of all of the outstanding common stock of its principal subsidiaries: OE, CEl, TE, Penn (awholly owned subsidiary of OE), JCP&L, ME, PN, FESC, FES and its principalsubsidiaries (FG and NG), AE Supply, Me PE, We FET and its principalsub*idiaries (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 Allegheny Ventures, Inc.FE and its subsidiarles are principally involved in the generation, transmission, and distribution of electricity. FirstEnergys ten utilityoperating companies compdse one of the nation's laeest investoFowned etectric systems, based on seMng six million customeF in the Midwsst and Mid-Atlantic regions. lts regulated and unregulated generation subsidiaries control nearly 17,000 l W of capacity lrom a diverse mix of non-emitting nuclear, scrubbed coal, naturat gas, hydroelectric and other renewables.

FirstEnergy's transmission operations include approximately 24,000 miles of lines and two regionaltransmission operation centers.These interim tinancial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports onForm 10-Q.

Certain information and disclosures normally included in tinancial statements and notes prepared in accordance with GAAP have been condensed or omifted pursuanl to such rules and regulations. These interim linancialstatements should be read inconjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2015. These Notes to the Consolidated Financial Stalemenis are combined lor FirstEnergy and FES.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 accompanyinginterim tinancialstatements are unaudited, but reflect alladjustments, consisting of normalrecurring adjustments, that, in fieopinionof management, are necessary fora fairstatement of the financial statements.

The preparation of financialstatements in conformity with GAAP requires managementto make periodic estimates and assumptions that affect the reported amounts oI assets, liabilities, revenues and expenses and disclosure ot contingent assets and liabilities. Actual results could ditfer from these estimates.

Thereported results ofoperations are not necessarily indicative ol results of operations for any future period. FEand its subsidiaries haveevaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued.FE and its subsidiaries consolidate allmajority-owned subsidiaries overwhich they exercise controland, 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 beneticiary (see Note 7, VariableInterest Entities). Investments in afiiliates overwhich FE and its subsidiaries have the abilityto exercise significant influence, butdonot have a controlling financial interest, followthe equity method ot accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE s ownership share of the entity's earnings isreported in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss).Forthe three months ended September 30, 2016 and 2015, capitalized tinancing costs on FirstEnergy's Consolidated Statements of Income (Loss) include $11 million and $ 10 million, respectively, of allowance for equitylunds used during construction and $ 17 million and $16 million, respectively, of capitalized interest. For the nine months ended September 30, 2016 and 2015, capitalized financingcosts on FirstEnergy's Consolidated Statements ot Income (Loss) include $28 million and

$40 million, respectively, of allowance forequity funds used during conslruction and

$51 million and

$53 milljon, respectively, of capitalized interest.

During the third quarter of 2016, a reduciion io depreciation of $21 million ($19 million prior to Januayl, 2016) was recorded that related to prior periods. The out-of-period adjustment related to the utilization of an accelerated useful life for a mmponent of a certain power siation. Management has detemined this adjustment is not material to the current period or any prior periods.Sl/ategic Review of Competitive Operations FirstEnergy's strategy is to be a fully regulated utility focusing on stable and predictable earnings and cash fiow from its regulated business units. In order to execute on this strategy, FirstEnergy has begun a strategic review of its competitive operations focused onthe sale of gas and hydroelectric units as well as exploring allaltematives forthe remaining generation assets at FES and AE Supply.These include, but are not limited to, legislative efforts to convert generation from competitive operations to a regulated or regulated-like construct such as a regulatory restructudng in Ohio, offering generation into any process designed to address MP's generationshortfall included in its lRP, andor a solution for nuclear generation that recognize their environmental benefits.

Managementanticipates that the viability of these alternatives will be determ ined in the near term with a target to implement lhese strategic optionswithin the next 12 to 18 months and could result in material asset impairments.

Based on current market forwards, CES, including FES, expects to have more than sufiicient cash flow from operations in 2017 and2018 to fund anticipated capital expenditures with no equity contributions from FirstEnergy. However, in addition to exposure lo market price volatility and operational risks, CES, including FES, faces signilicant financial risks that could impact its anticipated cash flow and liquidity, including, bul not limited to, the following:. Requests to post additional collateral or accelerated payments of up to $355 million resulting from current credit ralings atFES, including Moodys downgrade of the Senior Unsecured debt rating for FES to Caal as well as S&P's downgrade of the Senior Unsecured debt raling at FES to B, both of which occurred on November 4, 2016.. Adverse outcomes in the previously disclosed disputes regarding long-term coal transportation contracls. The inability to extend or refinance debt maturities at CES, including at FES subsidiaries, in 2017 and 2018 of$130 million and $515 million, respectively.

Asignificant collateralcallor the inability to refinance 2017 debt maturities at FES subsidiaries is sxpected to be addressed by FESthrough a combination of cash on hand, additional capital expenditure reductions, asset sales, and/or borrowings under theunregulated money pool. However, adverse outcomes in the coal transportation contracts disputes, the inability to refinance 2018 debt maturities, or lack of viable alternative strategies could cause FES lo take one or more of the following actions: (i) restructuring of debt and other financial obligations, (ii) additional borrowings under the unregulated money pool, (iii) further asset sales or plantdeactivations, and/or (iv) seek protection under bankruptcy laws. In the event FES seeks such proteclion, FENOC maysimilarly seek protection under bankruptcy laws.

Materialasset impairments resulting from the sale ordeactivation of generation assets orfrom a determination by management of its intent to exit competitive generation assets before the end of their estimated useful lite resulting from the inability lo implementalternative strateg ies d iscussed above, adverse iudgments or a FES bankruptcy tiling could result in an event of default under various agreements related to the indebtedness of FE. Although management expecG to successlully resolve any FE defaults through waivers or other actions on acceptable terms and conditions, the failure to do so would have a material and adverse impact onFirstEnergy's linancial condition, and FirstEnergy cannot provide any assurance that itwillbe able to successfully resolve any suchdefaults on satisfactory terms.l,lew Ac@unting Prcnou ncen}?'nlsIn May 2014, the FASB issued ASU 2014-09, 'Revenue from Contracts with Customers'. Subs*quent accounting standards updates have been issued which amend and/or clarify the application ofASU 2014-09.

The core principle of the new guilance is that an entityrecognizes revenue to depictthe transfer ot promised goods or services to cuslomers in an amount that refrects the consaderation to which the entity expecb to be entitled in exchange for those goods or services. More detailed disclosures will also be required toenable users offinancialslatemenb to understand the nature, amount, timing and uncertainty ot revonue and cash flows arising ftom contracts with customers. For public business entities, the new revenue recognition guidancewill be efiective for annual and intedm reporting periods beginning after December 15, 2017. Earlier adoption is pemitted forannualand interim reporting periods beginning after December 15, 2016. The standards shall be applied retrospectively to each period presented or as a cumulati\*-etfectadiustment as of lhe date of adoption. FirstEneEy is currently evaluating the impact on its financial siatements of adopting these standads.In February 2015, the FASB issued ASU 201+02, 'Consolidations: Amendments to the Consolidation Analysis', which amendscurent consolidation guidance including changes to both the variable and voting interest models used by companies to e\raluate whetheran entity should be consolidated. A reporting entity must apply the amendments using a modified retospective approach by recoding a cumulative-effect adjustment to equity as ol the beginning of the period of adoption or apply the amendments retrospectively.

FirstEnergys adoption ofASU 2015-02, on January 1 , 2016, did not result in a change in the consolilation of VlEs by FE or its subsidiaries.In April 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt lssuance Costs", which requires debt issuancecosts to be presented on the balance sheet as a direct deduction from the carrying value ofthe associated debt liability, consistent with the presentation of a debt discount. In addition, inAugust 2015, the FASB issued ASU 2015-15, "Presentation and Subsequert Measurementot Debt lssuance Costs Associated with Lineot-Credit Arrangements', which allows debt issuance costs related to lineof credit arrangements to be presented as an asset and amortized ratably over the term of the arrangement, regardless otwhetherthere are any outstanding borrowings on the line-ot-credit. FirstEnergy adopted ASU 2015-15 and ASU 2015-03 beginning January 1,2016. As of December 31, 2015, FirstEnergy and FES reclassified

$93 million and

$17 million of debt issuance costs included in Deferred charges and otherassetsto Long-term debt and Other long-term obligations. FirstEnergy has elected to continue presenting debt issuance costs relating to its revolving credil tacilities as an asset.

In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities", which primarily atfects the accounting lor equity investments, financial liabilities under the fair valueoption, and the presentation and disclosure requirements forfinancial instruments. In addition, the FASB clarif ied guidance related to the valuation allowance assessmenl when recognizing deferred tax assets resulting from unrealized losses on available{oFsaledebt securities. The ASU will be efiective in fiscal years beginning atter December 15, 2017, including interim periods within those fiscal years. Eady adoption for certain provisions can be elected for all financial statements offiscalyears and inlerim periods that have not yet been issued orthat have not yet been made available for issuance. FirstEnergy is currently evaluating the impact on ils financialstatements of adopting this standard.

10 In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease asseb with leaseterms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on theirbalance sheets. In addition, new qualitative and quantitative disclosures ofthe amounts, timing, and uncertainty ofcash flows arisingftom leases will be required. The ASU will be elfective for liscal years, and interim periods within those fiscal years, beginning atter DecembelI 5, 201 8, with early adoption pmitted. Lessors and lessees will be required to apply a modified retospeciive lransitionappoach, which requires adjusting the accounting tor any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require anyaccounting adiustrnent. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.In March of2016, the FASB issued ASU 2016-09, "lmprovements to Employee ShareBased Payment Accounting', wfiich simplifiesseveralaspecG of the accounting foremployee sharebased payment. The new guidancewillrequire allincome tax efiects of awardsto be recognized in the income statement when the awards vest or are settled. lt also will not require liability accounting when anemployer repurchases more of an employee's shares for iax withholding purposes. The ASU will be etfective lor tiscal years, and interim periods within those fiscalyears, beginning atter December 15,2016, with early adoption permitted. FirslEnergy is curlenlly evaluating the impact on its financial statements of adopting this standard.In June 2016, the FASB issued ASU 2016-13, 'Financial Instrumenls - Credit Losses (Topic 326): Measurement of Credit Losses onFinancial Instruments,' which removes all recognition thresholds and will require companies to recognize an allowance tor creditlosses lor the ditference belween the amortized cost basis ot a tinancial instrument and the amount of amortized cost that the company expects to collect over the instrument's contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December'15,2019.

Early adoption is permitted forfiscalyears beginning after December 15,2018. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.In August 2016, the FASB issued ASU 2016-l5, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments".

The standard is intended to eliminate diversity in practice in how certain cash receipls and cash payments are presented and classified in the statement of cash flows. The guidance is ellsctive lor fiscal yea]s, and for interim periods within lhose fiscal years, beginning after December 15, 2017. Early adoption is permitted for allentities. FirstEnergy does not oQect thisASU tohave a material effect on its financial statements.In October 2016, the FASB issued ASU 2016-16, 'AccountirE for Income Taxes: Intra-Entity Asset Transfers of AsseB Olher thanInventory." ASU 201S16 eliminates the exception for all intra-entity sales ol assets other than invenlory which allows companies to defer the tax effects of intra-entity asset transters. As a result, a repoding entity would recognize lhe tax expense from the sale ofthe asset in the seller's tax jurisdiction when the intra-entity transfer o@urs, even though the pre-tax etfects of that transaction are eliminaled in consolidation. Any delerred tax asset that arises in the buyer's iurisdiction would also be recognized atthetime of the transfer.

The guidance is etfective tor fiscal years, and for interim periods within those fiscal years, bginning after December 15,2017. Early adoption is permitted andthe modified retmspective approach willbe required tor transition tothe newguidance, with acumulative-effect adjustment recorded in retained eamings as of the beginning of the period of adoption.

FirstEnergy is currentlyevaluating the impact on its financial statements of adopting this standard.

Additionally, dudng 2016, the FASB issued the following ASUS: ASU 2016-05, "Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships," ASU 2016-06, "Contingent Put and Call Options in Debt lnstruments (a consensus of the FASB Emerging lssues Task Force),"ASU 2016-07, "Simplifying the Transition to the Equity Method of Accounting," andASU 2016-17, "Consolidation (Topic 810): lnterests Held through Related Parties That Are under Common Control." FirstEnergy does not expect these ASUs to have a material effect on its financial statements.

11

2. ASSET IMPAIRMENTSPlant lmDaimenE FirstEnergy reviews longlived assets for impairmenl whenever events or changes in circumstances indicate thatthe carryirE value otsuch assets may not be recoverable. The recoverability ol a longlived asset is measured by comparing its carrying value to the sumof undiscounted future cash flows expected to resuh from the use and eventual disposition of the asset. tt the carryirE value is greatsrthan the undiscounted cash flows, an impairment exists and a loss is recognized for the amount by u,hich the carrying value of the longiived asset exceeds its estimated fair value. FirstEnergy utilizes the income approach, based upon discounted cash flows bestimate fairvalue.On July 19, 2016, FirstEnergy and FES committed to exit operations of the Bay Shore Unit 1 generatirE station (136 l"fw) by frober1, 2020, through either sale or deactivation and to deactivate Units 1-4 of the W. H. Sammis genorating siation (720 lvfw) by May31,2020. As a result, FirstEnergy recorded a non-cash pre-tax impai.ment charge of

$647 million ($517 million - FES) in the second quarter of 2016, which is included in lmpairment ot assets on the Consolidated Statement of Income (Loss) and included within the results of the CES segment. PJM has approved the W.H Sammis Units 1-4 and Bay Shore Unit 1 deactivations pending revia f by theIndependent Market Monitor. In addition, FirstEnergy and FES recorded termination and settlement cosb on luel contracb ol approximately

$58 million (pre-tax) in the second quarter of 2016 resulting from plant retirements and deactivations.During the first nine months of 2015, FirstEnergy and FES recognized impairment charges ot

$24 million and

$16 million, respectively, associated with certain transportation equipment and tacilities.

In order to confotm to cunent year presenlation, thecharge was reclassified from Other operating expenses in the Consolidated Statement of Income (Loss) to lmpairment of assets.

Goodwi In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy's reporting units are consistent with ib reportable segments and consist of RegulatedDistribution, Regulated Transmission, and CES. The lollowing table presents the changes in the carrying value ofgoodwillforlhe ninemonths ended September 30, 2016: Goodwill Regulated Regulated Distribution Transmission Competitive Energy ServiCes Gonsolidated Balance as of December 31. 2015 lmpairment Balance as of September 30, 2016 5,092 $(ln millions)526 $800 $ 6,418 (800)(800)5,092 $526 $5,618FirstEnergy tests goodwill for impairment annually as of July 31 and considers more frequent testing if indicators of potentialimDairment arise.

As a result of low capacity pdces associated with the 2019/2020 PJM Base ResidualAuction in May A)16, as well as its annualupdate to its tundamental long-term capacity and en*rgy price forecast, FirstEnergy deiermined that an intedm impairment analysis ofthe CES reporting unit's goodwill was necessary during the second quarter of 2016.Consistentwith FirstEnergy's annualgoodwillimpairment test, a discounled cash flow analysis was used to determine tho fairvalueof the CES reporting unitfor purposes of step one of the interim goodwill impairment test. Key assumptions incorporated inb the CESdiscounted cash flow analysis requiring significant management judgment included the tollowing:. FutuB Energy and Capaclty Prlces: Observable market information for near-term forward pow*r prices, PJM auctionresults for nearterm capacity pricing, and a longer-term fundamental picing modelfor energy and capacity that consideredthe impact of key factors such as load groMh, plant retirements, carbon and other environmentalregulations, and naturalgas pipeline construction, as well as coal and natural gas pricing.. hefail Sates and Margln: CES' current retail targeted portfolio to estimate future retail sales volume as well as historical financial results to eslimate retail margins.. Operating and Capltal Costs: Estimated future operating and capital costs, including the estimated impact on costs of pending carbon and other envionmentalregulations, aswellas cosb associated with capacity performance reforms in he PJM markel.. Discount Rate: Adiscount rate of 9.50%. based on selected comparable companies'capiial structure, retum on debt and return on equity.

Terminal Value: A terminal value of 7.0x earnings before interest, taxes, consideration of peer group data and analyst consensus expectations.

12 and amortization based on Based on the impairment analysis, FirstEnergy determined that the carrying value of goodwillexceeded itsfairvalueand Iecognized a non-cash pre-tax impairment charge of

$8OO million ($23 million - FES) in the second quarter of 2016, which is included within the caption lmpairment ot assets in the Consolidated Slatemenl of Income (Loss).As of July 3'1, 2016, FirstEnergy performed a qualitative ass*ssment of the Regulated Distribution and Regulated Transmissionreporting units' goodwill, assessing economic, industry and market considorations in addition to the reporting units' overall tinancial performance. lt was determined that the fair value of these reporting units were, more likely than not, greater than theircarrying valueand a quantitative analysis was not necessaryTermination of Customer ContactDuring the third quarter of 2016, FES recorded a pre-tax charge of

$32 million associated with the termination ol a cuslomer contracl,which is included in Other operating expenses in the Consolidated Statement of Income (Loss).3. EARNINGS PER SHARE OF COMMON STOCKBasic earnings per share of common stock are computed using the weighted a\*rage number of common shares oulstanding during the relevant period as lhe denominator. The denominator for diluted earnings per share ol common sbck reflects the weightedaverage ot common shares outstanding plus the potentialadditionalcommon shares that could result ifdilutive securities and othelagreemenb to issue @mmon slock were exercised.The following taHe reconciles basic and diluted earnings per share ot common stock:

For the Three Months For the Nine Months (ln millions, except per share amounts)

Reconciliation of Basic and Diluted Earnings per Share of Common StockEnded September 30 Ended September 30 2016 2015 2016 2015Net income (loss)Weighted average number of basic shares outstanding Assumed exercise of dilutive stock options and awards(1)

Weighted average number of diluted shares outstanding Basic earnings (losses) per share of common stock Diluted earnings (losses) per share of common stock 380 $395 $(381) $804 425 2 423 1 425 422 1 424 425 423$$0.8e $0.8e $0_e4 $0.93 $(0.e0) $(0.e0) $1.91 1.90 (r) For the nine months *nded Seoternber 30. 201 6. three million shares were exclud*d lrom the calculation of diluted sharEs outstanding, as theirinclusion would be aniidilutive as a result ol lhe net loss for the period. For the thr*e months endod September 30, 201 6 and 201 5, ard lor thenine months ended September 30, 201 5, one m illion shares werc exclud*d from the calculation of diluted shargs outstanding, as their inclusion wodd be antidilutive.4. PENSION AND OTHER POSTEIIPLOYMEITT BENEFTS Through October 2016, FirstEnergy satisfied its minimum required funding obligations to its qualified pension plan for the year withcontributions of

$382 million ($85 million in October 2016), including

$138 million at FES. Depending on, among other things, market conditions, Fi6tEnergy expects to make additional conlributions to its qualified pension plan in 2016 of up to

$500 million of equity b address ib funding obligations for future years.13 The components of the consolidated net periodic cost (credits) for pension and OPEB (including amounts capitalized) were as follows:Components of Net Periodic Benefit Costs (Credits)For the Three Months Ended September 30Service costs Interest costs Expected return on plan assets Amortization of prior service costs (credits)Net periodic costs (credits)Gomponents of Net Periodic Benetit Costs (Credits)For the Nine Months Ended September 30 2016 2015 2016 Pension OPEB 2016 2015 2016 48 99 (100)2 4e$36$2 7 (e)(33)(33)(ln millions)4e$ 2 $967 (111) (7)2 (20)Pension (18) $OPEB Service costs Interest costs Expected return on plan assets Amortization of prior service costs (credits)Net periodic costs (credits)For the Three Months Ended September 30 For the Nine Months Ended September 30 Net Periodic Benefit Expense (Gredit)For the Three Months Ended September 30 144 $298 (2e7)6 (ln millions)145 $ 4 288 22 (333) (23)6 (60)4 21 (25)(100)$ (100)151 $106 $(57)FES' share of the net periodic pension and OPEB costs (credits) were as follows: Pension 2016 2015 2016 2015 Pension and OPEB obligations are allocated to FE s subsidiaries, including FES, employing he plan participants. The net periodic pension and OPEB costs (credits), net ot amounts capiialized, recognized in eamings by FirstEnergy and FES were as follows: (ln millions)6 $ 4 $ (4) $ (5)18 12 (12) (15)Pension OPEB 2016 2015 2016 FirstEnergy FESNet Periodic Benefit Expense (Credit)For the Nine Months Ended September 30 2016 2015 2016 35$5 Pension (ln millions)25$4 (11) $(4)OPEB (21)(4)FirstEnergy FES 107 $17 (ln millions)74$12 (41) $(12)(66)(12)14

5. ACCUMULATED OTHER COMPREHENSIVE INCOME The changes in AOCI, net of tax, in the three and nine months ended September 30, 2016 and 2015, for FirstEnergy are included in the following tables: FirstEnergyGains &Losses on Cash Flow Hedges UnrealizedGains on AFS Defined BenefitPension &Securities OPEB Plans (31) $(ln millions)58$164 $191 AOCI Balance as of July 1, 20'16Other comprehensive income before reclassifications Amounts reclassified from AOCIOther comprehensive income (loss)Income taxes (benefits) on other comprehensive income (loss)Other comprehensive income (loss), net of taxAOCI Balance as of September 30, 2016AOCI Balance as of July 1,2015 Other comprehensive loss before reclassificationsAmounts reclassified from AOCIOther comprehensive income (loss)Income taxes (benefits) on other comprehensive income (loss)Other comprehensive income (loss), net of taxAOCI Balance as of September 30, 2015AOCI Balance as of January 1, 2016Other comprehensive income before recl assif icationsAmounts reclassified from AOCIOther comprehensive income (loss)Income taxes (benefits) on other comprehensive income (loss)Other comprehensive income (loss), net of taxAOCI Balance as of September 30, 2016AOCI Balance as of January 1, 2015Other comprehensive loss before reclassificationsAmounts reclassified from AOCI Other comprehensive income (loss)Income taxes (benefits) on other comprehensive income (loss)Other comprehensive income (loss), net of taxAOCI Balance as of September 30, 2015 2 21 (17)(18)21 (33)(18)(7)(12)(5)(7)(11)(2e) $60$153 $184 (36) $1e$219 $202 2 (8)(3)(31)(8)(32)(40)(15)2 1 (11)(4)(31)(12)(7)(1e)(25)(35) $12$200 $177Gains &Losses on Cash Flow Hedges Unrealized Gains on Defined Benefit AFS Pension &Securities OPEB Plans (33) $(ln millions)18$186 $171 6 109 (42)(54)109 (e0)67 25 6 2 (54)(21)19 6 13 (33)(2e) $60$153 $184 (37) $25$258 $246 4 (1)(20)(e4)(1)(110)4 2 (21)(8)(e4)(36)(111)(42)(6e)(13)(58)15 (35) $12$200 $177 The following amounts were reclassified from AOCI for FirstEnergy in the three and nine months ended September 30, 2016 and 2015:Rec lassif ications f rom AOGI(2)

For the Three Months For the Nine Months Ended September 30 Ended September 30 2016 2015 2016 2015Affected Line ltem in Gonsolidated Statements of Income (Loss)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 $$2$6 (ln millions)$2 (2) Other operating expenses 6 Interest expense 2 2 (1)1$(3) $1 6 (2)4 Total before taxes (2) Income taxes2 Net of tax (20) lnvestment income (loss)7 Income taxes 2$(17) $7 4$(42) $16$ (11) $ (1e) $(1) These AOCI components are included in the computation of net Postemployment Benefits for additional details.(26)$ (13) Net of tax (94) (1)36 Income taxes (33) $ (58) Net of tax periodic pension cost. See Note 4, Pension and Other (10) $(18) $7 (2) $(31) $12 (54) $21 (z)Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.16 The changes in AOCI, net of tax, in the three and nine months ended September 30, 2016 and 2015, for FES are included in the following tables: FES Gains &Losses on Gash Flow Hedges Unrealized DefinedGains on Benefit AFS Pension &Securities OPEB Plans Total (10) $(ln millions)50$ 35$75AOCI Balance as of July 1 , 2016Other comprehensive income before reclassifications Amounts reclassified from AOCIOther comprehensive income (loss)Income taxes (benefits) on other comprehensive income (loss)Other comprehensive income (loss), net of taxAOCI Balance as of September 30, 2016AOCI Balance as of July 1 , 2015Other comprehensive loss before reclassificationsAmounts reclassified from AOCIOther comprehensive loss Income tax benefits on other comprehensive lossOther comprehensive loss, net of taxAOCI Balance as of September 30, 2015AOCI Balance as of January 1, 2016Other comprehensive income before reclassificationsAmounts reclassified from AOCIOther comprehensive income (loss)Income taxes (benefits) on other comprehensive income (loss)Other comprehensive income (loss), net of taxAOCI Balance as of September 30, 2016AOCI Balance as of January 1, 20'15Other comprehensive loss before reclassificationsAmounts reclassified from AOCIOther comprehensive loss lncome tax benefits on other comprehensive lossOther comprehensive loss, net of taxAOCI Balance as of September 30, 2015 10$35$Unrealized Defined Gains on Benefit AFS Pension &Securities OPEB Plans Total (3)1 5 2 1 22 (17)22 (1e)3 1 (3)(1)(2)(e) $53$33$(e) $16$38$45 (7)

(4)(4)(7)

(8)(15)(6)(11)(5)(4)

(1)(3)(6)(e)36 (e) $""in*Losses on Cash Flow Hedges (e) $(ln millions)16$3e$46 102 (41)(10)102 (51)51 20 61 24 (10)(4)37 31 (6)(e) $53$33$77 (7) $21 $43$(2)(2)(1)(1e)(12)(1)(33)(34)(13)(21)(20)(e)(12)(4)(8)(11 )(2)17 (e) $10$35$36 The following amounts were reclassified from AOCI for FES in the three and nine months ended September 30, 2016 and 2015:Reclassif ications f rom AOCI(2)

For the Three Months For the Nine Months Ended September 30 Ended September 30 2016 2015 2016 2015 Affected Line ltem in Consolidated Statements of Income (Loss)Gains & losses on cash flow hedges Commodity contracts Unrealized gains on AFS securities Realized gains on sales of securities

$Defined benefit pension and OPEB plans Prior-service costs $1$(z',)(ln millions)$Other operating expensesIncome taxesNet of tax 1$(17) $6 (11) $(3) $1$(3) $1$(41) $15 (2)(18) Investment income (loss)7 lncome taxes (2) $(4) $1 (26)$ (t 1) Net of tax (10) $4 (12) (1)4 Income taxes

$ (2) $(3) $(6) $(8) Net of tax (1) These AOCI comoonents are included in the comDutation of net Deriodic pension cost. See Note 4, Pension and OtherPostemployment Benefils for additional details.(2) Amounts in parenthesis represent credits to the Consolidated Statements of Operations from AOCI.6. INCOME TAXES FirstEnergy's and FES'interim efiective tax rates reflectthe estimated annualeffective tax rates for 2016 and 2015. These tax ratesare affected by estimated annual permanent items, such as AFUOC equity and other flow-through items, as well as discrete itemsthat may occur in any given period, but are not consistent from period to period.FirstEnergy's effective tax rate for the three months ended September 30, 2016 and 2015 was 39.8% and 36.4%, respectively.Changes in FirstEnergy's ellective tax rate forthe nine months ended September 30,2016 as compared tothesame period of 2015,resulted from the second quarter of 2016 impairment of $8OO million of goodwill (as described in Note 2), of which $433 million is non-deductible for tax purposes.

Additionally, $159 million of valuation allowances were recorded in the second quarter of 2016 againststate and local NOL carryforwards that manag*ment believes, more likelythan not, will not be realized based primarily on projecled taxable income rellecting updates to FirstEnergy's annual long-term fundamental pricing model for energy and capacity, as well ascertain statutory limitations on the utilization of stale and local NOL carMorwards.

FES'etfective tax rate forthe three months ended September 30,2016 and 2015was 58.3%and 36.8%, respectively. The increase in the effective tax rate is primarilydueto the impact ofestimated annualpermanent items onlorecasted lowel pre-tax incometorthe penoo.FES' effective tax rate tor the nine months ended September 30, 2016 and 2015 was 1 .8% and 40.0%, respectively. The change inthe ettective tax rate primarily resulted from

$65 million of valuation allowances recorded against state and localNOL carMorwardsthat management believes, more likelythan not, will not be realized as described above.

Additionally, FES recorded an impairment of goodwill (as described in Note 2) in the second quarter of 2016, of which $23 million is non-deductible for lax purposes.In March 2016, FirstEnergy recorded unrecognized tax benefits of

$69 million primarily related to protective retund claims filed withthe Commonwealth of Pennsylvania as a result of a recent ruling by the Commonwealth Court finding that the state's NOLcarryoverlimitation violated the unilormity clause and was unconstitutional.

The Commonwealth of Pennsylvania has appealed this ruling to thePennsylvania Supreme Court.As oI September 30, 2016, it is reasonably possible that approximately

$54 million of unrecognized tax benefits may be resolvedwithin the next twelve months as a result ot the statute of limitations expiring and expected resolution with respect to cenain claims, ofwhich approximately

$15 million would atfect FictEnergy's etfective tax rate 18 In February 2016, the IRS completed its examination ol FirstEnergy's 2014 federal income tax return and issued a fullacceptanceletter with no adjustments.7. VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary b*neficiary (a controlling financial interest) ot a VlE.

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 significantlyimpact the entity's economic performance, and (iD the obligation to absorlc losses ofthe entity that could potentially be signiticant tothe VIE or the rightto receive benefits from the entity that could potentially be signilicant to the VlE. FirstEnergy consolidates a VIEwhen it is determined that it is the primary beneficiary The caption "noncontrolling interest" within the consolidated financial statements is used to retlect the portion ol a VIE that FirstEnergy consolidates, but does not own.

In order to evaluate contracts for consolidation treatment and entities forwhich FirstEnergy has an interest, FirstEnergy aggregatesvariable interests into categories based on similar risk characteristics and significance.Consolldated VlEsVlEs in which FirstEnergy is the primary beneficiary consist ot the following (included in FirstEnergy's consolidated financial statements):. PNBV Trust -PNBV, a business trust established by OE in 1996, issued certain beneficial interests and notes to fund theacquisition of a portion ot 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 BeaverValley Unit 2. OE used debt and availablo fundsto purchase lhe notes issued by PNBV. The beneficial ownership of PNBV includes a 3% interest by unafiiliated third parlies.. Ohio Securrtlzat on-In September2O12, 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 cuslomer 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 generalcredit of FirstEnergy or any oftheOhio Companies. Each of the Ohio Companies, as seNicer ol its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remitlan@ of usagebased charges payable by retail electriccustomers. In the aggregate, the Ohio Companies are entitled to annual servicing tees of $445 thousand that are recoverable through the usage-based charges. The SPES are considered VlEs and each one is consolidated into itsapplicable utility. As ot September 30, 2016 and December 31, 2015, $339 million and

$362 million of the phase-in recovery bonds were outstanding, respectively.. JCP&L *curlthat on - In June 2002, JCP&LTransition Funding sold transition bonds b securitize the recoveryofJCP&USbondable stranded costs associated with the previously divested Oyster Creek NuclearGenerating Station. In August 2006,JCP&L Transition Funding ll sold transition bonds to securitize the recovery of deferred costs associated wilh JCP&LSsupply of BGS. JCP&Ldid notpurchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&LS Consolidated Balance Sheets. The transition bonds are the sole obligations ot JCP&LTransition Funding and JCP&L Transition Funding ll and are collateralized by each company's equity and assets, which consist primarily of bondable transition property. As of September 30,2016 and December 31, 2015, $97 million and

$128 million of the lransition bonds were outstanding, respectively.. MP and PE Environnl*nl*/t Fundlng Comrynles - The entities issued bonds, the proceeds of which were used toconstruct environmental control facilities. The specialpurpose limited liability companies own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive eleclric delivery service in MP's and PE s West Virginiaservice territories.

Principaland interest owed on the environmentalcontrolbonds is secured by, and payablesolely 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 otthe specialpurpose limited liability companies.

Asof September 30, 2016 and December 31, 2015, $407 million and $429 milljon of the environmental control bonds wereoutstanding, respectively.Unconsolldatod VlEg FirslEnergy is not the primary beneficiary of the following VlEs:. Gtobal Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in theSignal Peak mining and coal transportation operations with coal sales in U.S. and intemational markels. FEV is nol the primary beneficiary ofthe jointventure, as it does not have controloverthe significant activities atfecting thejoint venture's economic performance.

FEV'S ownership interest is subjecl to lhe equity method of accounting.

As discussed in Note l2, Commitments, Guarantees and Contingencies, FE is the guarantor underGlobal Holding's

$300 million term loan facility. Failure by Global Holding to meettheterms and conditions under its term loan facilitycould require FE to be obligated under the provisions of its guarantee, resulting in consolidation of Global Holding by FE.19 PATH WV -PAfrH 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.

Asubsidiary of FE owns 100o/" 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 subjectto the equity method of accounting.

Purchase Power Agreements - FirstEnergy evaluated its PPAs and determined that certain NUG entities at its Regulated Distribution segment may be VlEs to the extent that they own a plant that sells substantially all of its output tothe applicable utilities and the contract price for power is correlated with the plant's variable costs of production.

FirstEnergy maintains 14long{erm PPAswith NUG entities that were entered into pursuantto PURPA. FirstEnergywas not involved in the creation of, and has no equity or debt invested in, any of these entities.

FirstEnergy has determined that forall but one of these NUG entities, it does not have a variable interest or the entities do not meet the criteria to be considereda VlE. 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 tothe 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 during the three months ended September30,2016 and 2015 were $22 million and

$29 million, respectively, and $78 million and $86 million during the nine months ended September 30, 2016 and 2015, respectively.Sale and Leaseback Transactions - OE and FES have obligations that are not included on their Consolidated BalanceSheets related to the Beaver Valley Unit 2 and 2007 Bruce Mansfield Unit 1 sale and leasebackarrangements, respectively, which are satisfied through operating lease payments. FirstEnergy is not the primary beneficiary of these interests as it doesnot have control over the significant activities affecting the economics of the arrangements. As of September 30, 2016, FirstEnergy's leasehold interest was 2.60% of Beaver Valley Unit 2 and FES' leasehold interest was 93.83% of Bruce Mansfield Unit 1.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.Upon the completion of this transaction, NG will have obtained all of the lessor equity interests at Beaver Valley Unit 2.Therefore, upon the expiration of the Beaver Valley Unit 2 leases, NG will be the sole owner of Beaver Valley Unit 2 and entitled to 100o/o of the unit's output.On May 23,2016, NG completed the purchase of the 3.75%

lessor equity interests of the remaining non-affiliated leasehold interest in Perry Unit 1 for $50 million. In addition, the Perry Unit 1 leases expired in accordance with their terms on May 30, 2016, resulting in NG being the sole owner of Perry Unit 1 and entitled to 100% of the unit's output. Thereafter, OEtransferred its NDT assets and related ARO to NG associated with Perry Unit 1 . See Note 10, Asset Retirement Obligations, for additional information.

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 ofcasualty 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 September 30, 2016:Maximum Discounted LeaseExposure Payments, net Net Exposure (ln millions)1,137 $ 895 $1 ,110 887 FirstEnergy FES 242 223 20

8. FAIR VALUE IIEASUBE ENTSRECURRING FAIR VALUE IIEASUREIIENTS Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives be highest priority to Level 1 measurements and the lowest priority to Level 3 measuremenb. The three lsveb of thefair value hierarchy and a description of the valualion techniques are as tollows:Level 1Level 2 Quoted prices for identical instruments in active market Quoted prices for similar instruments in active market Quoted prices for identical or similar instruments in markets that are not activeModel-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 forcommodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.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 moredetailed description of FirstEnergy's valuation process for FTRs and NUGs follows: FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs'carrying values are periodically adjusted to fair value using a mark-to-model methodology, whichapproximates market.

The primary inputs into the model, which aregenerally less observablethan objective sources,are the most recent PJM auction clearing prices and the FTRs'remaining hours. The modelcalculates the fairvalue 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 9, Derivative Instruments, for additional information regarding FirstEnergy's FTRs.NUG contracts represent PPAs with third-party non-utility generators that are transacted to satisfy certain obligationsunder 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 intothe modelare regionalpower prices and generation MWH. 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 inputwhen prices are not defined by the contract.

Forecasted market prices are based on ICE quotes and management assumptions.Generation NrWH reflects data provided by conlractual arrangements and historical trends. The modelcalculates thefair value by multiplying the prices by the generation MWH. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement.

Level 3 FirstEnergy primarily applies the market approach for recuning tair value measurements using the best information available.Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were nochanges in valualion methodologies used as of September 30, 2016, from those used as of December 31,2015.

The determination of the fair value measures takes into consideration various factors, including but not limited to, nonpertormance risk, counterparty creditrisk and the impact of credit enhancements (such as cash deposits, LOCS and priority interests). The impact of these forms of riskwas not significant to the fair value measurements.

21 Transfers between levels are recognized at the end ot the reporting period. There were no transfers between levels duling the ninemor hs ended September 30, 2016. The following tables set forth the recurring assets and liabilities that are accounted for at fairvalue by levelwithin the fair value hierarchy:

FirstEnergyRecurring Fair Value Measurements Assets Corporate debt securities Derivative assets - commodity contractsDerivative assets - FTRs Derivative assets - NUG contracts(r)

Equity securities(2)

Foreign governm ent debt securities U.S. government debt securitiesU.S, state debt securities Other(g)Total assets LiabilitiesDerivative liabilities - commodity contracts Derivative liabilities - FTRsDerivative liabilities - NUG contracts(l)Total liabilitiesNet assets (l iabilities)t+l September 30,2016 December 31,2015Level 1 Level 2 Level 3 Total Level 1Level 2 Level 3Total 1,242 $230 77 173 255 551 126$ 1/66 $ 'J03 $ 13$ 3,582 $685$7$13$8 1 1,245 228 8 1 576 75 180 246 317 908 (ln millions)1,242 $ $237 4 13 908 576 77 173 255 677 105 1,245 224 75 180 246 212$ 2,182 g $ 2,976 (13)(13)$ (122) $ (150) $ (281)(e)$ 1,454 $ 1 ,e81 !_q2 !_3,313_

! 6?6 !__r,060_

!-(141) !_r,ses_(1)(?\(3)(4)NUG contracts are subject to regulatory accounting treatment and do not impact earnings,NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and PreferredSecurities REIT index.

Primarily consists of short-term cash investments.

Excludes $(8) million and $7 million as of September30,2016 and December31,2015, respectively, of receivables, payables, taxes andaccrued income associated with financial instruments reflected within the fair value table.22 Bollfotwatd of Level 3 fuleasuremenEThe following table provides a reconciliation ofchanges in the fair value of NUG contracts and FTRS that are classified as Level3 inthe fair value hierarchy for the periods ended September 30, 2016 and December 31, 2015: NUG Contracts(l)

FTRs Derivative Derivative Assets Liabllities Net Derivative Assets Derivative Liabilities NetJanuary 1, 2015 Balance Unrealized gain (loss)Purchases Settlements December 31, 2015 Balance Unrealized gain (loss)

Purchases Settlements September 30, 2016 Balance (ln millions)2 $ (1s3) $ (151) $: 'i' ':'(3) 65 62 1 $ (137) $ (136) $(14) $ 25(7) (12)22 (11) 11 (48) 1e (2e)I $ (13) $ (5)(8) 1 (7)3e$(5)17 (4)(17)(17)(1)NUG contracts are subject to regulatory accounting treatment and do not impact earnings.

Level 3 Quantitative InformationThe lollowing table provides quantitative information lor FTRS and NUG contracb that are classitied as Level 3 in the fair valuehierarchy for the period ended September 30, 2016: (1) 36 35 Significant Input Range Weighted AverageRTO auction clearing prices Generation Regional electricity prices$(2.20) to $7.60 400 to 3,207,000

$30.90 to $35.30 (8) e13 I$1.00 Dollars/MWH 661,000 MWH$32.10 Dollars/MWHFair Value. Net Valuation (ln milliohsl Technique Units FTRsNUG Contracts FES 6 (118)Model Model Recurring Fair Value Measurements AssetsCorporate debt securities Derivative assets - commodity contracts Derivative assets - FTRs Equity securities(1)

Foreign governm ent debt securities U.S. government debt securitiesU.S. state debt securities other(2)Total assets LiabilitiesDerivative liabilities - commodity contracts Derivative liabilities - FTRsTotal liabilities Net assets (liabilities)tslSeptember 30,2016December 31,2015Level 1 Level 2 Level 3 Total Level 1 Level2 Level3 Total (ln millions)$ 714$ $ sze$237 4 224 7 624 59 53 4 7 $ 1,787 $$ 1,172$ 714 230;53 4 87$ 1J4?;23 4 184$-7$7 624;378$ 678 228 5 378 59 23 4 184$ 155e (e)(e)$ 621 $ 1,025 $ 2 $ 1,648 $ sZs $ 1,050 $ (6)$ 1,417 I_23 (21 (3)NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP lndex or the Wells Fargo Hybrid and PreferredSecurities REIT index.

Primarily consists of short-term cash investments.

Excludes $1 million as of September 30, 2016 and December 31 , 2015, of receivables, payables, taxes and accrued income associated with thefinancial instruments reflected within the fair value table.Rollforward of Level 3 MeasurementsThe following table provides a reconciliation of changes in the fair value of FTRS held by FES and classified as Level 3 in the fairvalue hierarchy tor the periods ended September 30, 2016 and December 31, 2015:Derivative Asset Derivative Liability Net Asset (Liability)January 1, 2015 Balance Unrealized gain (loss)Purchases Settlements December 31, 2015 Balance Unrealized gain (loss)Purchases SettlementsSeptember 30, 2016 Balance Level 3 Quantitative lnformation 27$2 I (33)(ln millions)(13) $(5)(10)17 14 (3)(1)(16)5$(7)10 (1)(11) $1 (5)10 (6)(6)5 I$ (5) gThe following table provides quantitative information for FTRS held by FES that are classified as Level 3 in the fak value hierarchy for the period ended September 30, 2016:Fair Value.

Net Valuation (ln milliohs; Technique Significant Input Range Weighted Average Units FTRs $ 2 Model INVESTMENTSRTO auction clearing prices ($2.20) to $7.60$0.70 Dollars/MWHAll temporary cash investments purchased with an initial maturity ol three months or less are repolted as cash equivalenb on theConsolidated Balance Sheets at cost, which appmximates their fair market value. Investments other than cash and cash equivalenbinclude held-to-maturity securities and AFS securities.At the end ot each reporting period, FirstEnergy evaluates its investments lor OTTI. Investments classified as AFS securilies areevaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy considers its intentand abilityto hold an equity security until recoveryand then considers, among other factors, the duration andthe extent to which thesecurity's fair value has been less than its cost and the neaFterm tinancial prospects ol the security issuer when evaluating aninvestment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will berequired to sell the securities before recovery ot its cost basis and the likelihood of recovery ot the securities' entire amortized cost basis. ltthe decline in fair value is determined to be other than temporary the cost basis ol the securities is written down to fairvalue.Unrealizedgains and losses onAFS securities are recognized in AOCI. However, unrealized losses held in the NDTS of FES, OE and TE are recognized in earnings sincethe trust arrangements, as they are currently defined, do not meetthe required ability and intent to hold criteria in consideration of OTTI. The NDTs ofJCP&1, ME and PN aresubjectto regulatory accounting with unrealizsd gainsand losses offset against regulatory assets.The investment policy for the NDTfunds restricts or limib the trusts'ability to hold certain types of assets including private or direct placements, warrants, securities of FirtEnergy, investments in companies owning nuclear power plants, financial derivatives,securities convertible into common stock and securities of the trust funds'custodian or managers and their parents or subsidiaries.

AFS SecuntiesFirstEnergy holds debt and equity securities within its NDT and nuclearfueldisposaltrusts. These trust investments are consideGdAFS securities, recognized at fair market value. FirstEnergy has no securities held for trading purposes'24 The following table summarizes lhe amortized cost basis, unrealized gains (there were no unrealized losses) and fair values ofinvestments held in NDT and nuclear fuel disoosaltrusts as of Seotember 30. 2016 and December 31, 2015:September 30, 201601 December 31,2015(z)Cost Unrealized Gost Basis Gains Fair Value Basis Unrealized Gains Fair Value Debt securities FirstEnergy FES Equitv securities FirstEnergy

$FES (ln millions)1,797 $ 1,778 $879 801 1,728 $834 816 $561 6s$45 s2$63 908 $624 542 $354 16 $9 34$24 1,794 810 576 378 0) Excludes short-lerm cash investmenb: Fi6tEnergy - $50 million; FES - $39 million.e) Excludss short-tem cash investments: FirslEnergy - $157 million; FEs - $139 million.Proceeds from the sale of investmenB in AFS securities, realized gains and losses on those sales, OTTI and interest and dividendincome for the three and nine months ended September 30, 2016 and 2015 were as follows: For the Three Months Ended September 30,2016 Sale Proceeds Realized Gains Realized Losseslnterest and Dividend Income FirstEnergy FES September 30,2015 337 $135 Sale Proceeds (ln millions)$ (1s) $(6)Realized Losses 27 16lnterest and Dividend Income 36 23 (3) $(3)Realized Gains FirstEnergy FES 307 $127 (ln millions)33 $ (32) $28 (24)(46) $(41)25 14 For the Nine Months Ended September 30,2016 Sale Proceeds Realized Gains Realized Losseslnterest and Dividend Income FirstEnergy FES September 30, 2015 1,361 $576 Sale Proceeds (ln millions)131 $ (88) $s0 (4e)Realized Losses 75 42lnterest and Dividend lncome (13) $(12)Realized Gains FirstEnergy FES 1,126 $503 (ln millions)135 $ (121) $e8 (7s)(70) $(63)75 43 25 He WTo-Matu tW Seanities Unrealized gains (there were no unrealized losses) and approimate fair values of investments in held-to-maturity securities as ot September 30, 2016 and December 31, 2015 are immaterial to FiFtEnergy. Investments in employee benefit trusts and equitymethod investments totaling $276 million as of September 30, m16 and

$255 million as of December 31, 2015, are excluded fromthe amounts reported above.LONG-TERII DEBT AND OTHER LONG-TER OALIGATIOI{S All borrowings with initial maturities of less than one year are defined as short-term tinancial 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 olher long-tem obligations, excluding capitallease obligations a]d net unamortizeddebt issuance costs, premiums and discounts:September 30, 2016 December 31,2015 Carrying Fair GarryingValue Value Value Fair Value FirstEnergy FES 19,745 $3,003 (ln millions)21,465 $ 20,244 $2,662 3,027 21,519 3,121The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to thosesecurities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end ot each respective period. The yields assumed were based on securities with similar characteristics ofiered by corporations with credit ratings similarto those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-lerm obligationsas L*vel2 in the fak value hierarchy as of September 30, 2016 and December 31, 2015.9. DERIVATIVE INSTRUMENTSFirstEnergy is exposed to financialrisks resuhing from fluctuating interest rales and commodity prices, including prices for electricity, naturalgas, coaland energy transmission. To managethe volatility relatedtothese exposures, FirstEnergy's Risk Policy Committes, comprised ol senior management, provides general management oversight for risk management activities throughout FirstEnergy.The Risk Policy Committee is responsible lor promoting the elfective design and implementation ofsound riskmanagemenl programsand oversees compliance with corporate risk management policies and established riskmanagement practice. FirstEnergyalso uses a variety of derivative instruments tor risk management purposes including foMard contracts, options, futures conlracts and swaps.

FirstEnergy accounts for derivative inslruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as lollows:. Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded toAOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction afiects earnrngs,. Changes in the tair value of derivative instruments that are designated and qualify as fairvalue hedges are recorded as anadjustment to the item being hedged. When fairvalue hedges are discontinued, the adjustment recorded to the item beinghedged is amortized into earnings.. Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded ineamings 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 ofaccouniing with their effects included in earnings at the time of contract perlormance.FirslEnergy has contractual derivative agreements through 2020.Cash Flow HedgesFirstEnergy has used cash flow hedges lor risk management purposes to manage the volatility related to eposures associatedwith fluctuating commodity prices and interest rates.

Total pre-tax net unamortized losses included in AOClassociated with instrumenb previousv designated as cash flow hedges lotaled$11 mitlion as of September 30, 2016 and December 31, 2015. Since the forecasted transactions remain probable of occurring, theseamounts will be amortized into earnings over the life of the hedging instruments.

Less than $1 million of net unamortized losses isexpected to be amortized to income during the next twelve months.

26 FirstEnergy has used forward starting interest rate swap agreements to hedge a portion of the consolidated inleresl rate riskassociated with anticipated issuances offixed-rate, long-term debt securities ot its subsidiaries. These derjvatives were designatd as cash flow hedges, protecting against the risk of changes in future interest payments resulting trom 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

$35 million and $42 million as of September 30, 2016 andDecember 31,2015, respectively. Based on current estimates, approximately

$8 million otthese unamonized losses are expecled tobe amortized to interest expense during the next twelve months.

Reter to Note 5, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the three ard nine months endedSeptember 30, 2016 and 2015.As of September 30,2016 and December 31,2015, no commodity or interest rate derivatives were designated as cash flow hedges.

Fair Value HedgesFirstEnergy has used fixedJoFlloating interest rate swap agreements to hedge a porlion of the consolidated interest rate risk associated with the debt portfolio of ib subsidiaries.

As of September 30, 2016 and December 31 , 2015, no fixed-foFfloating ifieresl rate swap agreements were outstanding.

Unamortized gains included in long-term debt associated with prior fixed-for4oatirE inierest rate sutap agreements totaled $1 2 million and $20 million as of September 30, 2016 and December 31,2015, respectively. During the next twelve months, approximately

$8million of unamortized gains are e&ected to be amortized to interest expense. Amortization of unamortized gains included in long-term debt totaled appoximately

$2 million during the three months ended September 30,2016 and $3 million dudng the thrse monthsended September 30, 20 l5. Amonization ol unamortized gains included in long-term debt btaled approximately

$8 million during thenine months ended September 30, 2016 and $9 million during the nine months ended September 30, 2015.Commodity Deivalives FirstEnergy uses both physically and financially settled derivatives to manage its exposur* to

\,olatility 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 iorwards are used to balance expected sales with e)eected 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 Seplember 30, m16, FirtEnergy's net asset position under commodily derivative contracts was $103 million, which related to FES positions. Under these commodity derivative contracts, FES posted $9 million of collateraland recei\*d $22 million of collateral.Based on commodity derivati\re contracts held as of September 30, 2O'l6, an increase in commodity prices of 10% would decreasenet income by approximately

$37 million dudng the next twelve months.NUGS As of September 30, 2016, FirstEnergys net liability position under NUG contracts was $118 million, representing contracts held at JCP&L, ME and PN. Changes in the fair value of NUG contracts are subiect to regulalory accounting treatment and do not impact eamings.FTRs As ol September 30, 2016, FirstEnergy's and FES'net asset associated with FTRS was

$6 million and $2 million, respectively, and FES posted $7 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 annualauction through a self-scheduling process involving the use ofARRS allocated to member of PJM that have load serving obligations.The future obligations for the FTRS acquired at auction are reflected on the Consolidated Balance Sheets and have not bsen designated as cash flow hedge instruments. FirstEnergy initially records these FTRS at the auction price less the obligation due toPJM, and subsequently adjusts the carrying value of remaining FTRS to their estimated fair value at the end of each accountingperiod pdorto settlement. Changes in the fairvalue of FTRS held by FES andAE Supplyare included in other operating epenses as unrealized gains or losses. Unrealized gains or losses on FTRS held by the Utilities are recorded as regulatory assets or liabilities.Dkectly allocated FTRS are accounted tor underlhe accrual method ot accounting, and their elfects are included in earnings at thetime of contract Derformance.

27 FirstEnergy records the lair value of derivative instruments on a gross basis. The tollowing table summarizes the fair value andclassification of derivative instruments on FirstEnergy's Consolidated Balance Sheets:Derivative Assets Derivative LiabilitiesGurrent Assets

-Derivatives Commodity Contracts

$FTRs Deferred Gharges and Other Assets - Other Commodity Contracts FTRs\[JQsit)Derivative Assets Fair ValueSeptember 30, December 31, 2016 2015 (ln millions)139 $13 152Fair Value Current Liabilities

-Derivatives 150 Commodity Contracts7 FTRs 157 Noncurrent Liabilities

-Adverse Power Contract Liability NUGs(1)Noncurrent Liabilities

-78 other 1 Commodity Contracts1 FTRs September 30, December 31, 2016 2015 (ln millions)(84) $(7)(106)Fair Value (e4)(12)(e1)98 (118)(50)(137)(37)(1)98 80 (168)(175)250 $237 Derivative Liabilities (25e) $(281)(1) NUG comracts are subject to Jegulalory accounting treatrnent and do not impact *amingts.

FirstEnergy enters into contracls with counteparties that allow for the otfsetting of derivati\re assets and deriva$ve liabilities under ne$ing arrangements with the same counterparty. Certain ol these contracts contain margining provisions that require the use ofcollateral to mitigate credit exposure between FirstEnergy and these coufierparlies.

In situations where collatetal is pledged lomitigate exposures related to derivative and non-derivative instruments with the same counterparty, FirstEnergy allocates thecollateral based on the perconiage ol the net fair value of derivative instruments to the total fair value of the combined delivalive andnon-derivative instruments. The following tables summadze the fair value of derivative assets and derivative liabililies on FirstEnergy's Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Otfset in ConsolidatedBalance SheetSeptember 30, 2016Derivative Gash Collateral Net Fair Instruments (Received)/Pledged Value Derivative Assets Commodity contracts FTRs NUG contracts Derivative LiabilitiesCommodity contracts FTRs NUG contracts 237 13 (ln millions)(120) $(7)(22) $95 6 250 $(127) $(22)$ 101 (134) $(7)(118)120 7 8$ (6)(25e) $(118)9-(1'z41 28 127 $

December 31, 2015Fair Value Amounts Not Offset in ConsolidatedBalance Sheet Derivative Cash Collateral Net Fair Instruments (Received)/Pledged Value Derivative AssetsGommodity contracts FTRs NUG contracts Derivative LiabilitiesCommodity contracts FTRs NUG contracts Power Contracts FTRs NUGs Natural Gas .228 $I 1 (ln millions)(125) $(8)103 1 237 $(133) $$ 104 (131) $(13)(137)125 $8$ (3)(137)q ___(140)3 5 133 $Thefollowing table summarizes thevolumes associated with FirstEnergy's outsianding derivative transactions as of September 30, 2016: Purchases Sales Net Units (ln millions)49 (281) $9 42 3 49 (40) MWH 42 MWH 3 MWH 49 mmBTU 29 The effect of active derivative instruments not in a hedging relationship on the Consolidated Statements of lncome (Loss) duringthe three months and nine months ended September 30, 2016 and 2015, are summarized in the following tables:

For the Three Months Ended September 30-Conliictj rrns rotal (ln millions)2016Unrealized Gain (Loss) Recognized in:Other Operating Expense(t)

Realized Gain (Loss) Reclassified to: Revenues(1)Purchased Power Expense(t

)Other Operating Expense(t

)Fuel Expense (1) All amounts are associated with FES.For the Three Months Ended September 30 Commodity

, Contracts FTRs Total (ln millions)2015Unrealized Gain (Loss) Recognized in: Other Operating Expense(e)

Realized Gain (Loss) Reclassified to:

Revenues(2)

Purchased Power Expense(z)Other Operating Expense(z)

Fuel Expense (2)All amounts are associated with FES.le$(3) $$ 32 $ 1$(:) ., (2)16 33 (22)(6)(2)5e$41 $(1)(5)(2) $2$(11)57 43 (50)(11)(5)30 2016 Unrealized Gain Recognized in:

Other Operating Expense(t

)Realized Gain (Loss) Reclassified to: Revenues(1)

Purchased Power Expense(t

)Other Operating Expense(t

)Fuel Expense (1) All amounts are associated with FES.2015 Unrealized Gain (Loss) Recognized in:

Other Operating Expense(z)

Realized Gain (Loss) Reclassified to: Revenues(s)

Purchased Power Expense(+)

Other Operating Expense(s)Fuel Expense For the Nine Months Ended September 30 Commodity Contracts (ln millions)2 $ 8 $FTRs Total 162 $(rT)(e)5 (28)167 (105)(28)(e)For the Nine Months Ended September 30 Commodity Contracts (ln millions)81 $ (17) $4s $ 48 $(78)(38)(26)FTRs Total 96 (78)(38)(26)(2) lncludes $81 million for commodity contracts and

$(16) million for FTRs associated with FES.(3) Includes $48 million for commodity contracts and

$46 million for FTRs associated with FES.(a) All amounts are associated with FES.(s) Includes $(37) million for FTRs associated with FES.31 The following table provides a reconciliation ofchanges in lhefairvalue of FirstEnergys derivative instruments subject lo regulatoryaccaunting during the three and nine months ended September 30, 2016 and 2015. Changes in the value oI these instruments are deferred for future recovery from (or credil to) customers:

For the Three Months Ended September 30 Derivatives Not in a Hedging Relationship with Requlatory Offset Regulated FTRs NUGs TotalOutstanding net asset (liability) as of July 1 , 2016 Unrealized loss SettlementsOutstanding net asset (liability) as of September 30, 2016Outstanding net asset (liability) as of July 1, 2015Unrealized loss SettlementsOutstanding net asset (liability) as of September 30, 2015 Derivatives Not in a Hedging Relationship with Regulatory OffsetOutstanding net asset (liability) as of January 1 ,2016Unrealized loss Purchases SettlementsOutstanding net asset (liability) as of September 30, 2016Outstanding net asset (liability) as of January 1 , 2015Unrealized loss Purchases Settlements (ln millions)(124) $ 4 $(6)12$-111q $ (114)(120)(6)12$ (140) $(20)12$(4)(128)(24)14 17 (3)138For the Nine Months Ended September 30 NUGs Regulated FTRs Total (ln millions)(136) $ 1 $(17)35 (1)4 (135)(18)4 35$ (118) $_____l 114$ (151) $(36)44 11 $(3)12 (140)(3e)12 29 Outstanding net asset (liability) as of September 30, 2015 $_1119) $ 5_ $ (138)32 10.ASSET RETIRE ENT OBLIGATIONSFirstEnergy has recognized applicable legal obligations for AROS and their associated cost primarily for nudear power plantdecommissioning, reclamation of sludge disposalponds, closure ofcoalash disposal sites, undergound and aboveground storage tanks, wastewater treatment lagoons ard lransformers containing PCBS. ln addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remedialion.TheARO liabilities for FES primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Petry nuclear generatingfacilities, which are approximately

$701 million, as of September 30, 2016. FES uses an epected cash flouv approacfi b measuG thefair value of their nuclear decommissioning AROS.FirstEnergy and FES maintain NDTS that are legally restlicted tor purposes of settling the nuclear decommissioning ARO. The fair values of the decommissioning trust assets as ot September 30, 2016 and December 31, 2015 were as follows: 2016 2015 (ln millions)$ 2,502 $ 2,282$ 1,542 $ 1,327The following table summarizes the changes to the ARO balances during 2016:ARO Reconciliation FirstEnergy FES (ln millions)$ 1,410 $(25)4 70 1,459 $887 During the second quarter of 2016, in connection with NG purchasing the lessor equity interests of the remaining non-affiliatedleasehold interests from an owner participant in Perry Unit l, OE transferred theARO (included within the FES liabilitiss incurredabove) and related NDT assets associated with the leasehold interest to NG with the difference of

$28 million credit*d to the commonstock of FES. As ofJune 30, 2016, NG owns 100% of Perry Unit 1.Federal and state hazadous waste regulations have been promulgated as a result of the RCRA, as amended, and the ToxicSubstances Control Acl. Certain coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal requiremenb pending the EPA'S evaluation of the need for future regulation.In December 2014, the E PA finalized regulations forthe disposalof CCRS (non-haz ardous), establishing national standards regarding landfilldesign, 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 electdc generating plants.Based on an assessment ofthe finalized regulations, the future cost of compliance and eryected timing of spend had no significantimpact on FirstEnergys or FES existing AROS associated with CCRS.Although none are currefily e)eected, any changes intimingand closure plan requirements in the future could materially and adversely impact FirstEnelgys and FES'AROS.1 1. REGULATORY iIATTERSSTATE REGULATIONEach of the Utilities' retail rates, conditions otselice, issuance of securities and other matters are sublect to regulation in the siatesin which it operates - in Maryland bythe MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsytvania bythe PPUC,in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations ol PE in Virginia are subject to certainregulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to thePUCO if not acceptable to the utility.As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, lllinois, Michigan, New Jersey andMaryland, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliatecodes ot conduct that apply to FES, AE Supply and theirpublic utility affiliates. In addition, ilany ofthe FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, dependirE on the state, they may be required toobtain slate regulatory authorization to site, construct and operate the new transmission or generation facility.FirstEnergy FES Balance, December 31, 2015 Liabilities settledLiabilities incurred Accretion Balance, September 30, 2016 831 (17)32 41 33 MARYLAND PE provides SOS pursuant to a combination ot settlement agreements, MDPSC orders and regulations, and siatutory provisions.SOS supply is competitively procured in the torm ot rolling contracts ofvarying lengthsthough periodic auctions that are overseen bythe MDPSC and a third party monitor. Although settlements with respect to SOS supply for PE customers have expired, servicecontinues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return tor providing SOS.The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption anddemand 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

$68million, of which

$38 million was incurred through September 30, m16. On July 16, 2015, the MDPSC issued an order selting new incremental energy savings goals for 2017 and beyond, beginning with the level ot savings achieved under PE s currenl plan for 2016, and ramping up O.2o/o per fear thereatter to rcach 2o/o. PE continues to recover program costs subj*cl to a live-yearamortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy elficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE.On February 27, 2013,lhe MDPSC issued an oder (the Febuary 27 Orde0 requiring the Maryland electric utilities to submit analyses relating to the costs and benefits of making further system and staffing enhan@ments in orderlo attempt to reduce stormoutage durations. The orderfurther required the Stafi ofthe MDPSC to report on possible performance-based rate structures and to propose additionalrules relating to feeder performance standards, outage communication and reporting, and sharing olspecialneedscustomer information. PE's responsive filings discussed the steps needed to harden the utilitys system in order to attempt to achievevarious levels of storm response speed described in the February 27 Order, and projected that it would require approximately

$2.7billion in infrastructure investments over 15 years to attempt to achieve the quickest level of response forlhe largest storm projectedin the February 27 Order. On July 1, 2014, the Statf ot the MDPSC issued a set ot repons that recommended the imposition ofextensive additionalrequirements in the areas of storm response, fe*der performance, estimales ot restoration times, and regulatoryreporting. The Staff ofthe MDPSC also recommended the imposition of penalties, including customer rebates, for a utility's failure orinability tocomplywith the escalating standards of storm restoration speed proposed bythe Staffofthe MDPSC. In addition, the Stafiof the MDPSC proposed that the utilities be required to develop and implement system hardening plans, up to a rate impact cap oncost. The MDPSC conducted a hearing Septemberl5-18,2014, to consider certain otthese matters, and has not yet issued a rulingon any of those matters.

NEW JERSEY JCP&Lcurrently provides BGS lor reiailcustomers who do not choose a third party EGS and for customers of third party EGSS that failto provide the contracted service. The supply for BGS is comprised ot two components, procured through separate, annually helddescending clock auctions, the results of which are approved by the NJBPU. One BGS component reflects hourly real lime energy prices and is available lor 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.Pursuant to the NJBPU'S March 26, 2015 final order in JCP&L'S 2012 rate case proceeding dkecting that certain sludies be completed, on July 22,2015, the NJBPU approved the NJBPU staff's recommendation to implement such sludies, which includeoperational and financial components. The independent consultant conducting the review issued a final report on July 27, 2016, recognizing that JCP&L is meeting the NJBPU requirements and making various operational and financial recommendations.

TheNJBPU issued an Order on August 24,2016, that accepted the independent consultant's final report and directed JCP&L, the Division of Rate Counsel, and other interested parties to address the recommendations.

ln an Order issued Oclober 22,2014, in a generic proceeding to review its policies with respect to the use ol a CTA in base rate cases (Generic CTAproceeding), the NJBPU stated that it would continueto apply its current CTApolicy in base rate cases, subject to incorporating the tollowing modifications: (i) calculating savings using a five-year look back lrom the beginning ofhe test year; (ii)allocating savings with 75% retained by the company and 25% allocatsd to rate payers; and (iii) excluding transmission asssts ofelectric distribution companies in the savings calculation. On November 5, 2014, the Division of Rate Counselappealed the NJBPU Order regarding the Generic CTAproceeding to the New Jersey Superior Court andJCP&L has ftled to participate asa respondent in that proceeding. Briefing has been completed.

The oral argument was held on October 25, 2016.On April 28, 2016, JCP&L filed iariffs with the NJBPU proposing a general rate increase associated with ib distribulion operationsthat seeks to improve service and benetit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating torother business and operating expenses. The filing requested approvalto increaseannual operating Evenues by approximately

$142.1 million based upon a hybrid test year for the twelve months ending June 30, 2016. On July 13, 2016, this matter was submitted to the Office of Administrative Law for hearing and the issuance of an Initial Decision. On September 30, 2016, JCP&Ltiled an update to its filing, which inciudes actualdata for the twelve months ended June 30, 2016, requesting an increase to annual operating revenues by approximately

$146.6 million. On October 19, 2016, an order was received approving the agreed upon procedural schedule. Hearings are scheduled to occur in January 2017 thlough March 2017. OnNovember 2, 2016, JCP&L achieved a settlement-in-p nciple with all the intervening parties providing for an annual

$80 million 34 distribution revenue increase, which will take effect on January 1, 2017, subject to linalization, execution and NJBPU approval of aStipulation of Settlement.

On June 19, 2015, JCP&L, along with PN, ME, FET and MAIT made tilings with FERC, the NJBPU, and the PPUC lequesting authorization forJCP&L, PN and ME to contribute their transmission assets to MAII a newtransmission-only subsidiary of FET The procedural schedule was suspended while the NJBPU considered a motion on a legal issue regarding whether MAIT can bedesignated as a "public utility" in New Jersey. On February 24, 2016, the NJBPU issued an Order concluding that MAIT does notsatisfy the'electricity distribution" element necessary for "public utility" status because MAlTwould not own any electric distribution assets in New Jersey. On April 22, 2016, JCP&L and MAIT filed a supplemental petition and testimony seeking to include certainJCP&L distributions assets in the transfer to satisfy the "electricity distribution" element necessary for'public utility'status in accordance with the NJBPU'S February 24,2016 order. In order to allow MAlTto file its tormula transmission rate with an stfectivedate of January 1,2017, on September 8, 2016, JCP&L and MAIT submitted a letter to the NJBPU to withdraw their petition totransfer JCP&L assets into MAIT. The NJBPU adminisfa vely closed the matter on September 30, 2016. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion ot this transaction.

oHro On August 4, 2014, the Ohio Companies tiled an application with the PUCO seeking approvalottheir ESP lV e illed Powedng Ohb'sProgress. ESP lV included a proposed Rider RRS, which would flowthrough to customers either charges or credits represenling thenet result of the price paid to FES through an eight-year FERo-jurisdictional PPA, referred to as the ESP lV PPA, againsl therevenues received trom selling such output into the PJM markets. The Ohio Companies entered into stipulations which modified ESPlV and which included PUCO Staff as a signatory party, in addition to other signatories.

On March 31, 2016, lhe PUCO issued anOpinion and Orderadopting and approving the Ohio Companies'stipulated ESP lVwith modifications. FES and the Ohio Companies entered into the ESP lV PPA on April 1, 2016.On January 27,2016, certain parties filed a complaintwith FEBC against FES and the Ohio Companies requesling FERC reviewtheESP lV PPA under Section 205 of the FPA. On April 27,2016, FERC issued an order granting the complaint, prohibiting anytransactions under the ESP lV PPA pending future authorization by FERC, and directing FES to submit the ESP lV PPAfor FERC review if the parties desired to transact under the agreement.

FES and the Ohio Companies did not file the ESP lV PPA tor FERC review but rather agreed to suspend the ESP lV PPA. FES and the Ohio Companies subsequently advised FERC of this course of acton.On April 29, 2016 and May 2, 2016, several parties, including the Ohio Companies, liled applications for rehearing on the OhioCompanies'ESP lVwith the PUCO. The Ohio Companies'Application for Rehearing included a modified Rider RRS proposalbutdidnot include a FERC-jurisdiclional PPA. The PUCO accepted the applications for rehearing tor further consideration and provided parties an opportunity to comment on the Ohio Companies'Application for Rehearing and file an alternative proposal. PUCO Staff recommended that the PUCO deny the Ohio Companies' modified Rider RRS proposal and recommended a new Rider DMR providing for the collection of

$204 million annually (grossed up for income taxes) for three years with a possible extension for anadditional two years. The Ohio Companies recommended that the PUCO approve the proposed modified Rider RRS and that a properly designed Rider DMRwould be valued at $558 million annuallyfor 8 years, and include an additionalamount that recognizes the value of the economic impact of FirtEnergy maintaining its headquarters in Ohio.Several parties subsequently filed protests and comments with FERC alleging, among other things, that the modilied Rider RRSconstitutes a'virtual PPA". The filings and FirstEnergy's responses thereto are pending betore FERC.On September 6,2016, whilethe applications for rehearing were stillpending before the PUCO, the OCC and NOAC filed a notice ofappeal with the Ohio Supreme Court appealing various PUCO and Attorney Examiner Entries on lhe parlies' applications forrehearing. On September'16, 2016, the Ohio Companies intervened and filed a motion to dismiss the appeal. The appeal remains pending betore the Ohio Supreme Court.On October 12, 2016, the PUCO issued an opinion and oder ruling on the parties' applications for Iehearing and turther modifiedESP lV The PUCO orderdenied the Ohio Companies' modilied Rider RRS proposal, and instead approved a Rider DMR proposed by PUCO Statf, with modifications.As a result of the stipulations, the PUCO'S March 31, 2016 Opinion and Order and the PUCO'S Octobell2, 2016 order, the materialterms of ESP lV include:. An eight-year term (June 1,2016- May 31,2024J... The Rider DMR which provides for the Ohio Companies to collect

$132.5 million annually forftree years, with the possibilityof a two-year exlension. The Rider DMB will be grossed up for taxes, resulting in an approved amount of approximately

$204 million annually. Revenuesfrom the Rider DMR willbe excluded from the significantly excessive earnings test tor the initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension.. Three conditions tor continued recovery under the Rider DMR:

(1) retention of the corporate headquarters and nexus ofoperations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of s uffcient progr$s in the implementation of grid modernization programs approved by the PUCO.35 No restrictions on the Ohio Companies' use of funds collected under the Rider DMR. However, the PUCO directed the PUCO Staff to periodically review how the Ohio Companies and FE use the funds to ensure the funds are used, directly or indirectly, in support of grid modernization. Uses of funds to indirectly support grid modernization could include, e.9., reducing outstanding pension obligations or reducing debt.Continuation of a base distribution rate freeze through May 31 ,2024.Continuation of the supply of power to non-shopping customers at a market-based price set through an auction process.Continuation of 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, 2022through 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.Continuation of 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 such costs avoided by customers for certain types of products totals $360 million.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 customers.

An agreement to file a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29,2016).A goal across FirstEnergy to reduce COz emissions by 90% below 2005 levels by 2045.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.. A contribution ol $1 million per year ($8 million over the eight-year term) to establish a Customer Advisory Council b ensure preservation and growth of the competitive marlGt in Ohio.Finallt on March 21,2016, a number of generation owners liled with FERC a complaint against PJM requesting that FERC e{candthe MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in the PJM capacity markets by state-subsidized generation, in particular alleged price suppression that could resu lt from the ESP lV PPA and other simihr agreements.

The complaint requested that FERC direct PJM to initiate a siakeholder process to develop a long-term MOPR reform for existing resources that receive out-of-market revenue. This proceeding remains pending before FERC.UnderOhios energy efiiciency standards (58221 and S8310), and based on the Ohio Companies'amended energy efiiciency plans,the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of2,266 GWHS in 2015 and 2,288 GWHS in 2016, and then begin to increase by 1% each yea( in 2017, subject to legislativeamendments to the energy efiiciency standards discussed below. The Ohio Companies are also required to retain the 2014 peak demand reduction levellor 2015 and 2016 and then increase the benchmark by an additional0.T5%thereafErthrough 2020, subject to legislative amendments to the peak demand reduction standards discussed below.On SeptemberSo, 2015, the Energy Mandates Study Committee issued its report related to energy efficiency and renervable energymandates, recommending that the cunent level ol mandates remain in dace indefinitely. The report also recommended: (i) an expedited process for reviEw of utiliv propossd gnsrgy Efficiency plans; (ii) ensuring madmum crEdit fur all of Ohio's Energy Initiatives; (iii) a switch from sn*rgy mandabs to enorgy incentives; and (iv) a declaraton be made that the GeneralAss*mbly maydetermine the energy policy ot the state. Legislation was introduced lo address issues raised in the Energy Mandates SludyCommittee report, namely S8320 and H8554. SB320 proposes to freeze energy effciency and renewable energy requirements for anadditional four yea6 at 2014 levels, as well as addressing net metering issues.

HB554 proposes to freeze energy efficiency andrenewable energy requirements lhrough 2027 at 2014 levels.On September 24, 2014, the Ohio Companies filed an amendment to their eneqy efiiciency portfolio plan as contemplated by SBS l0, seeking to suspend certain programs for the 2015-2016 period in order to better align the plan with the new benchmarks under SB31O. On November 20, 2014, the PUCO approved the Ohio Companies'amended portfolio phn. Several applications for rehearingwere filed, and the PUCO granted those applications for further consideration of the matter specified in those applications and themalter remains pending before the PUCO.On April 15, ml6, the Ohio Companies ftled an application for approval of their three-year energy elficiency portfolio plans for the period fiom January 1,2017 through December 31, 2019. The plans as proposed comply with benchmarks contemplated by SB3'10 and provisions of the ESP lV, and include a portfolio of energy efficiency programs targeted to a variety of qrstomer segmenb,including residentialcustomers, low income customers, smallcommercialcustomers,large comrnercial and industrial customers and govemmental entities. The Ohio Companies anticipate the cost of the plans will be approximately

$323 million over the lfie of theportfolio plans and such costs are epected to be recovered through the Ohio Companies' existing rate mechanisms. The hearing is scheduled for November 21-23. 2016.

36 On September 16,2013, the Ohio Companies filed with the Supreme Court of Ohio a notioe of appealofthe PUCO'S July 17,2013 Entry on Rehearing related to energy efficiency, altemative energy, and long-tem 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 dismissthe appeal, which was denied. On August 9, 2016, upon a Joint Application for Dismissalfiled by the Ohio Companies, PUCO and the ELPC, the Ohio Supreme Court dismissed the appeal.

Ohio law requires electric utilities and electric seruice @mpanies in Ohio to serve part oftheir load from renewable energy resources measured byan annually increasing percentage amountthrough 2026, subject to legislative amendmenb discussed above, excspt 2015 and 2016 that remain at the 2014level. The Ohio Comoanies conducted RFPS in 2009,2010 and 2011 b 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 riderthrough which the Ohio Companies recover the costs of acquidng these RECS. The PUCO issuedan Opinion and Order on August 7, 2013, approving the Ohio Companies' acquisition process and their purchases of RECS to meetstatutory mandales in all instances except for certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount ol

$43.4 million, plus interest, on the basis that the Ohio Companies did not pro/e such purchases were prudent. On December 24,2013, following the denialoftheir application for rehearing, the Ohio Companies filed a notice ot appeal and a motion lor siay of the PUCO'S order with the Supreme Court of Ohio, which was granted. On February 18, 2014, the OCC and the ELPC also tiled appeals of the PUCO'S order. The Ohio Companies timely filed their merit brief with theSupreme Court of Ohio and the brieting 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 retailelectric service market, with a focus on the ma*eting of fixod-price or guaranteed percentoff SSO rate contracts where there is a provision that pemib the pass-through of new or additional charges. On November 18, 20'15, the PUCO ruled that on a going-foMad basis, pass-though clauses may not be included in lixed-price conlracts for all customer classes.

On De@mber 18, 2015, FES filed an Application ior Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers. On January

'13, 2016, the PUCO granted reconsideration for further consideration ol the matters specitied in the applications for rehearing.

PENNSYLVANIAThe Pennsylvania Companies currently operate under DSPS that expire on May 31, 2017, and pmvide for the competitive procu Ement of generation supply for customers lhat do not choose an alternative EGS or for customers of altemative EGSS that fail to provide the contracted service. The default seivice supply is currently provided by wholesale suppliers through a mix of long-termand short-term contracts procured through spot market purchases, quarterly descending clock auctions for 3-, 12- and 24-monthenergy contracts, and one RFP seeking 2-year contracts to serve SRECS for ME, PN and Penn.Following the expiration of the current DSPS, the Pennsylvania Companies willoperate under new DSPSfortheJune 1,2017 throughMay 31, 2019 delivery period, which would provide for lhe competitive procurement of generation supply for customers who do notchoose an alternative EGS or for customers of alternative EGSS that fail to provide the contracted seMce. Under the pmgrams, thesupply would b*

provided by wholesale suppliers through a mix ot'12 and 24-month energy contracts, aswellas one RFP for 2-yearSREC contracts for ME, PN and Penn. In addition, the plan includes modifications to the Pennsylvania Companies' existing POR programs in oder to reduce the level of uncollectible e)eense the Pennsyivania Companies expedence associated with altemativeEGS charges.

Pursuant to Pennsylvania s EE&C legislation (Acl 129 of 2008) and PPUC orders, Pennsylvania EDCS implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies'Phase ll EE&C Plans were eftective through May31, 2016.Total Phase ll costs of these plans were expected to be approximately

$175 million and recoverable through the Pennsylvania Companies' reconcilable EE&C riders. On June 19,2015, the PPUC issued a Phase lll Final lmplementation Order setting:demand reduction targeb, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at 1 .8% for ME, 1 .7yo for Penn, 1 .8%for wP, and 0% for PN; and energy consumption reduclion targeb, as a p*rcentage ofeach Pennsylvania Companies'historic 2010 forecasts (in lvlwH), at 4.0% tor ME, 3.9% tor PN,3.3% for Penn, and 2.6%forwP. The Pennsylvania Companies'Phase lll EE&C plans for the June 2016 through May 2021 period, which were appmved in March 2016, are designed to achieve the targets esiablished in the PPUC'S Phase lll Final lmplementation Order without recovery to implement the EE&C plans.Pu6uant to Act 1 l of A)12, Pennsylvania EDCS may establish a DSIC to recover costs of infrastructure implovemenB and cosls related to highway relocation projects with PPUC approval. Pennsylvania EDCS mustfile LTllPs otjllining infrastructure improvement plans for PPUC review and approval prior to approval of a DSIC. On October'19, 2015, each of the Pennsylvania Companies filedLTIIPS with the PPUC ior infrastructure impovement over the five-year period of 2016 to 2020 for the following costs:

WP $88.34million; PN

$56.74 million; Penn

$56.35 million;and ME

$43.44 million. On February 11,2016,ihe PPUC appo\*d the Pennsylvania Companies' LTllPs. On February 15, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery associated with the capital projects approved in the LTllPs. On June 9, 2016, the PPUC approved the Pennsylvania Companies'DSIC riders to be effective July 1, 2015, subiect to hearings and refund or reallocation among customels.

On April2S,2016, each ofthe Pennsytuania Companies filed tarifis with the PPUC proposing generalrate increases associated withlheir distribution operations that will benelit customers by modemizing the grid with smart technologies, increasing vegetation management activilies, and continuing other customer service enhancements. The lilings request approval to increase annualoperating revenues by approximately

$140.2 million at ME, $158.8 million at PN, $42.0 million at Penn, and

$98.2 million at We 37 based upon fully projected future test years for the twelve months ending December 31, 2017 at each of the PennsylvaniaCompanies. As a result of the enactment of Acl

/tO of 2016 that terminated the practice of making a CTAwhen calculating a utility'sfederal income taxes lor ratemaking purposes, the Pennsylvania Companies submitted supplemental testimony on July 7,2016, that quantified the value ol the elimination ofthe CTA and outlined their plan for investing 50 percent of that amount in rate base eligibleequipment as required by the new law Formal settlement agreements for each of the Pennsyfuania Companies werc fled on October14,2016, which provide increases in annualoperating revenues of approximately

$96 million at ME, $100 million at PN, $29 million at Penn, and $66 million atWP, and are subiect to PPUC approval. One item related b the calculation of DSIC rates was reserved for briefing, with briefs filed by two parties. The proposed new rates are expected to take effect in January 2017 pending regulatory approval, which is expected no later than January 26,2017.On June '19, 2015, ME and PN, along with JCP&I, FET and MAIT made tilings with FERC, the NJBPU, and the PPUC requesting aulhorization for JCP&1, PN and ME to contribute their transmission assets to MAIT, a newtransmission-only subsidiary of FET. OnMarch 4, 20'16, a Joint Petition for Full Settlement was submitted to the PPUC tor consideration and approval. On April 18, 2016, theALJS issued an Initial Decision approving the Joint Petition for Full Settlement without moditications. On July 21, 2016, the PPUCadopted a Motion approving the Joint Petition for Full Settlement with minor modifications. On August 24, 2016, lhe PPUC issued a FinalOrder approving theJoint Settlement consistent with the July 21, 2016 Motion. See Transter oI Transmission Assets to MAIT inFEBC Matters below for further discussion of this transaction.WEST VIRGINIA MP and PE provide electric service to all customers through traditionalcost-based, regulated utility ratemaking. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related exp*nses, net of related market sales revenuethrough the ENEC. MP's and PE's ENEC rale is updated annually.

MP and PE filed with the WVPSC on March 31, 2016 their Phase ll energy etficiency program proposalfor approval. MP and PE are proposing three energy efficiency programs to meet their Phase ll requirement of energy etficiency reduclions of 0.5% of 2013distribution sales for the January 1, 2O17 through May 31, 2018 period, as agreed to by MP and PE, and approved by the VWPSC inthe 2012 proceeding approving the transfer of ownership of Harrison Power Station to MP The costs forthe program are epected to be $10.4 million and will be eligible for recovery through the existing energy etficiency riderwhich is reviewed in the tuel (ENEC) case each year. A unanimous settlement was reached by the parties on all issues and presented to the WVPSC on August 18, 2016. Anorder approving the settlement in fullwithout modilication was issued by theWVPSC on September 23, 2016. Under lhe order, the programs may begin as of the date of such orde( but no later than January 1, 2017.The Staff of the WVPSC and the ConsumerAdvocate Division filed a Show Cause petition on August 5,2016, requesting the WVPSCorder MP and PE lo file and implement RFPS for allfuture capacity and energy requirements above l00 lvlws and that they complywith an RFP settlement provision from the Harrison asset acquisition.

MP and PE filed a timely response to the petition arguing fordismissal on September 7, 2016. On October

'17, 2016, the wvPSC denied the petition filed by the Stafi of the WVPSC and theConsumer Advocate Division and dismissed the case.

On August 16,2016, MP and PE filed their annual ENEC case proposing an approximate

$65 million annual increase in ralesetfective January 1 , 2017, which is a 4.7% overall increase over existing rates. The $65 million increase is comprised of $119 millionunder-recovered balance as ofJune 30, 2016, and a projected

$54 million over-recovery tor the 2017 rate effective period. Aheadnghas been set for November 9 and 10, 2016 with an order expected to be issued in the fourth quarter of 2016.On August 22, 2016, MP and PE liied an application for approval of a modernization and improvement plan torcoal-fired boilers at electric power plants and cost-recovery surcharge proposing an approximate

$6.9 million annual increase in rales proposed to beefiective May 1 , 2017, which is a 0.5% overall increase over existing rates. The tiling is in response to recent legislation by the WestVirginia Legislature session permitting accelerated recovery of cosls related to modernizing and improving coal-fired boilers, including costs related to meeting environmental requirements and reducing emissions. The filing was supplemented on Seplember2S, 2016,to add two additional projects, resulting in an approximate

$7.4 million annual increase in rates. The Statt ofthe WVPSC has filed amotion to dismiss the case arguing the new statute was not meant to recover these types of projects, but the WVPSC has set thecase lor hearing tor Feuuary 2'l-29,2017 -On December 30, 2015, MP filed an IRP identifying a capacity shortfall starting in 2016 and exceeding 700 tvfw by 2020 and 850lvfw W 2027. On June 3, 2016, the WVPSC accepted the IRP finding that lRPs are informational and that it must not approve ordisapprove the IRP MP Plans to issue a RFP to address its generation shortfall identified in the IRP by lhe end of the year.38 RELIABILIW MATTEBS Federally-enforceable mandatory reliability slandads apply b the bulk eleclric system and impose certain opeft ing, recod-keepillg and reporting requiremenB on the t tilities, FES, AE Supply, FG, FENOC, NG, ATSI and TrAlL. NERC is the ERO designated byFE RC to esiablish and enforce these reliability standads, although NERC has delegated day-tcday implemeniation and enbrcementof these reliability standards to eight regionalentities, including BFC. All of FirstEnergy's facilities are located within the RFC region.

FirstEnergy aclively padicipales inthe NERC and RFC stakeholder processes, and otherwise monitors and manages its companiesin responsetothe ongoing development, implementation and enforcement of the reliability standards implemented and eniorced by RFC.FirstEnergy believes that it is in compliance with all currently-etfective and enforceable reliability standards.

Nevertheless, in thecourse of operating its extensive electric utility systems and facilities, FirstEnergy occasionally leams of isolated lacts oIcircumstances that could be interpreted as excursions from the reliability standards.

ll a]d when such o@urences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific cilcumstances, induding inappropriate cases "self-reporting" an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue b refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergys patt to comply with the reliability standards for its bulk electric system could result in the imposition offinancial penalties, and obligations b upgradeor build transmission facilities. that muld have a material adverse effect on its financial condition, results of operations and cash flows.FERC IIATTERSOhio ESP lV PPAFor information regarding matters before FERC related to the ESP lV PPA between FES and the Ohio Companies, see'Regulatory Matters - Ohio' above.PJM Transmission Bates PJM and its stakeholders have been debating the proper melhod to allocate costs for newtransmission facilities. While FirstEnergy and other parties advocate fora traditional"beneficiary pays' (or usage based) approach, others advocate fol "socializing" the costson a load-ratio share basis, where each customer in the zone would pay based on its total usage of energywithin PJM. This questionhas been the subiect ot extensive litigation before FERC andthe appellate courts, including before the Seventh Circuit. On June 25, 2014, a divided three-judge panel ofthe Seventh Ckcuit ruled that FERC had not quantified the benelits that westem 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 maiority lound that eastem PJM utilities are the primary b*neficiaries of the lines,rvtrilet *stem PJM utilities areonly incidental beneficiaries, and that, while incidental beneficiaries should pay some share ofthe costs of the lines, that share should be proportionate to the benetit they derive from the lines, and not on load-ratio share in PJM as awhole. The court remanded the case toFERC, which issued an order setting the issue of cost allocation tor hearing and settlement proceedings. On June 15, 2016 various parties, including ATSI and the Utilities, filed a settlement agreement at FERC agreeing to apply a combind usagebased/socialization approach to cost allocation for charges to transmission customers in the PJM rogion br transmission proiec{soperating at or above 500 kV. Certain parties in the proceeding did not agree to the settlement and filed protests to the settlementseeking, among other issues, to strike certain of the evidence advanced by FirstEnergy and certain of the other settling parties in support of the settlement, as lr*ll as provided further comments in opposition to the settlement. The PJM TOs responded to theprotesting parties'vadous pleadings ard motions. The settlement is pending before FERC.In a series of orders in cerlain Order No. lOOO dockets. FERC asserted that the PJMtransmission owners do not hold an incumbent1ig ht of first refusal" to construct, own and operate lransmission projects within their respective botprints that are approved as patt of PJM'S RTEP process. FirstEnergy and other PJM transmission owners appealed these rulings to the U.S. Court of Appeals for the D.C. Circuitwhich, in a July 1, 2016 opinion, ruled that the PJM transmission owners failed to preserve their arguments in the legal proceedings betore FERC and, on that basis, d*nied the appeal. In a related case howht bythe Southwest Powel Pooltransmission owners and issued on the same day, the court ruled that the Mobile-Siena standard does not protect transmission owners' rights offirst refusal that may be provided for in RTO taritfs because, according to the coutt, the tariff language is designed to block competition. The Mob,7+Srbna standard presumes that rates negotiated by private parties at arm's length are jusl and reasonable and prohibits FERC from modifying such rates unless the public interest requires.The outcome of these proceedings and their impact, if any, on FirstEnergy cannot be predicted at this time.

BTO RealignnentOn June l, 2011, ATSI and the ATSI zone transferred lrom MISO to PJM. While many of the matters involvsd with the move have been resotved, 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 acost/benefit analysis demonstrating net benefits to customers from the transbr to PJM. Subs*quently, FERC reiected a poposed settlement ag reement to resohre the exit fee and lransmission cost allocation issues, stating that its action is without ptejudice to ATSI 39 submitting a cost/benefit analysis demonstrating that the benelits ot the RTO realignment decisions outweigh the exit tee andtransmission cost allocation charges. On March 17, 20'16, FERC denied FirstEnergy's request for rehearing of FERC's earlier order rejecting the senlement agreement and afiirmed its prior ruling that ATSI must submit the cosvbenefit analysis.

Separately, the question ot ATSI's responsibility for cenain costs for the "Michigan Thumb' transmission project continues to bedisputed. Potential responsibility arises under the MISO MVP taritf, which has been litigated in complex proceedings before FERCand certain Uniled States appellate courts. On October 29,2015, FERC issued an orderfinding thatATSl and theATSlzone do not have to pay MISO MVP charges for the Michigan Thumb transmission project. MISO and the MISO TOs filed a request for rehearing,which FERC denied on May 19, 2016. On July 15, 2016, the MISO TOs filed an appeal ot FERC'S orders with the Sixth Circuit.

FirstEnergy intervened in the proceedings and intendsto participate in theappeal. On a related issue, FirstEnergyjoinsd certain other PJM transmission owners in a protest of MISO'S proposalto allocate MVP costs to energy transactions that cross MISO'S borders intothe PJM Region. On July 13,2016, FERC issued its order finding it appropriate for MISO to assess an MVP usage charge fortransmission exports from MlSOto PJM. Various parties, including FirstEnergy andthe PJMTOs, requested rehearing or clarificationof FERC's order. These parties'request for rehearing remains pending before FERC.In addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission proiects 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 ofderived benefits, is pending betore FERC as a result of the Seventh Circuit's June 25,2014 order described above under PJMTransmission Rates.The outcome of the proceedings that address the remaining open issues relaled to costs for the "Michigan Thumb' transmission project and "legacy RTEP" transmission projects cannot be predicted at this lime.Transfer of Ttansmission Asseb to MAITOn 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 ot JCP&1, ME and PN lollowing the receipt oI all necessary state and federal regulatory approvals. On June 19, 2015, JCP&1, PN, ME, FET, and MAIT made filings with FERC, theNJBPU, and the PPUC requesting authorization forJCP&1, PN and ME to contributo theirtransmission assets to MAIT. Additionally, the filings requested approval trom the NJBPU and PPUC, as applicable, of: (i) a lease to MAIT ot real property and rights-of-wayassociated with the utilities' trsnsmission assets; (ii) a MutualAssistance Agreemsnt (iii) MAIT being deemed a public utility under state law: (iv) MAITS participation in FE's regulated companies' money pool; and (v) certain affiliated interestagreemenb. As initially proposed, it was expected that JCP&L, ME, and PN would contribute their transmission assets at net book value and an allocated portion of goodwill in a tax-tree exchange to MAIT, which would operate similar to FETS two existing siand-alone transmission subsidiaries, ATSI and TrAlL. MAITS transmission facilities will remain under the functional control of PJM, and PJM will providetransmission service using these facilities under the PJM Tariff.

FERC approved the transaction on February 18,2016. On August 24, 2016, the PPUC issued a Final Order approving the transaction.

In order to allow MAIT to file its formula transmission rate with anefiective date of January 1, 2017, on September 8, 2016, JCP&L and MAIT submitted a letterto the NJBPU lo withdraw their petitionto transfer JCP&L assets to MAIT. The NJBPU administratively closed the matter on September 30, 2016. See New Jersey andPennsylvania in State Regulation above for further discussion of lhis transaction.On October 14 and 28, 2016, MAIT submitted applications to FERC requesting authorization to issue equity, short-torm debt, and long-term debt. MAIT intends to issue membership interests to FET, PN, and ME in exchange for their respective cash and asset contributions. MAIT is epected to issue short-term debt and participate in the FirstEnergy Utility Money Poolfor working capital, to fund day-to-day operations, and forother general corporate purposes.

Overthe long-term, MAIT is expected lo issue long-termdebtto support capital investment and to establish an actual capital structure for ratemaking purposes. On October 28, 2016, MAITsubmitted an application to FERC requesting authorization to implement a formula transmission rate to recovel and earn a return ontransmission costs effective January'1,2017. On October 28,2016, MAlTand PJM submitted joint applications to FERC requesting authorization for (i) ME and PN to withdraw from the PJM Consolidated Transmission Owners Agreement as TOs, and (ii) MAIT tobecome a participating PJM TO. Acceptance of MAIT as a PJM TO would grant PJM tunctional control over MAITS transmissionassets, and would permit PJM to implement MAIT'S formula rate on MAIT'S behalf.JCP&L Ttansmission Formula RateGiven that JCP&Lwill not be hansferring its transmission assets to MAIT, there is a need forJCP&Lto update its transmission rate.Accordingly, on October 28, 2016, JCP&L submitted an application to FERC requesting authorization to implement a tormulatransmission rate to recover and earn a relurn on transmission costs etfeclive January 1, 2017.Cal itomi a Claims Litigatb nSince 2002, AE Supply has been involved in litigation and claims based on its power sales to the California Energy ResourceScheduling division ol the CDWR during 2001-2003. This litigation and claims are related to litigation and claims advanced by the Califomia Attorney Generaland certain California utilities regarding alleged market manipulation ofthewholesale energy markets inCalifornia during the 2000-2001 period. AE Supply negotiated a senlement with the Calitornia Atlorney General and lhe Californiautilities and, on August 24, 2016, filed the settlement agreement for FERC approval.

The settlement calls tor AE Supply to pay, 40 without admission of any liability, $3.6 million in settlement in principle of all remaining claims that are based on AE Supply's power sales in the westem energy markeb during the 2001-2003 time period. On October 27, 2016 FERC approved this settlemenl.PAT H Ttans mis sio n P roied On August 24, 2012, the PJM Board of Managers canceled the PATH project, a prcposed transmission line from West Virginia through Mrginia and into Maryland which PJM had previously suspended in February 2011. As a result of PJM canceling the project, approximately

$62 million and appmximately

$59 million in costs incurred by PATH-Allegheny and PATH-WV respectively, were reclassified from net property, plant and equipment to a regulatory asset for future reclery. PATH-Allegheny and PATH-WV requested authodzation 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 dsnying the 0.5% ROE adder for RTO membership andallowing the tariff changes enabling recovery of these costs to become eftective on December 1, 2012, subject to senbment proceedings and hearing if the parties could not agree to a settlement. On March 24,2014, the FERC Chief AU teminated 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 parlies addressing the application ol FERC'S Opinion No. 531,discussed below, to the PATH proceeding.

On September 1 4, 201 5, the ALJ issued his initial decision, disallowing recovery of certaincosts. The initialdecision and exceptions thereto remain before FERC for review and afinalorder FirstEnergy continues to believethe costs are re@verable, subject io final ruling ftom FERC.

FERC ODinion No-531On June 19, 2014, FERC issued Opinion No. 531, in which FERC revised its approach for calculating the discounted cash flowelement ot FERC'S ROE methodology, and announced the potential for a qualitative adiustment to the ROE methodology lesults.Under the old methodology, FERC used a five-year torecast for the dividend growth variable, whereas going iorward lhe growthvariable will consist ot t yo parts: (a) a fiv+year for*cast br dividend growlh (2,3 weight); and (b) a long-tem dividend growth torecastbased on a forecast for the U.S. economy (l/3 weight). Regading the qualitative adjustment, for single-utility rate cases FERC tormerly pegged ROE at the median of the '2one of reasonableness' that came out of the ROE formula, wtrereas going forward,FERC may rely on record evidence to make qualitative adiustments to the outcome of the ROE methodology in orderto reach a levelsufficient to attrac{ future investment. On October 16, 2014, FERC issued its Opinion No. 531-A, applying the revis*d ROE methodology to certain ISO New England transmission owners, and on March 3,2015, FERC issuedOpinion No.531-B affirmirE ib prior rulings. Appeals ot Opinion Nos. 531, 531-A and 531-B are pending before the U.S. Court ofAppeals for the D.C. Circuit.

MISO Capacity PotabilvOn June 11, 2012, in response to certain arguments advanced by MISO, FERC requested comments regalding whether sxisting rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM. FirstEnergy and other parties submitbd filings arguing that MISOS conoerns 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 PJIiUMlSO seam to assist FERC's understanding ofthe issues and rvhat, ifany, additional steps FERC should iake to improve the efiiciency of operations at the PJI,VMISO seam. Stakeholders, including FESCon behalf of certain of its afiiliates and as part of a coalition of certain other PJM utilities, filed responses to the RTO submissions.

The various submissions and resmnses remain before FERC for consideration.Changes lo the criteria and qualifications for participation in the PJM RPM capacity auctions could have a significant impacl on theoutcome of those auctions, including a negative impact on the prices at which those auctions would clear.12. COIIMITIIEiITS, GUARAI{TEES AND COiITINGEI{CIESGUAFANTEES AND OTHER ASSURANCESFirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course ofbusiness. These contracts include perbmance guarantees, stand-by letters of credit, debt gualantees, sur*ty bonds andindemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third panies by enhancing thevalue of the transaction to the third party.As of September 30, 2016, FirstEnergys outstanding guarantees and olher assurances aggregated approximately

$3.4 billion,consisting of parental guarantees

($584 million), subsidiaries' guarantees

($2.0 billion), othel guarantees ($300 million) and other assurances

($504 million).O{ this aggregate amount, substantially all relates to guarantees of wholly-owned consolidated entities of FirstEnergy. FES' debtobligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligatbns 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 piimary obligor is FES, FG or NG.41 COLLATERAL AND CONTINGENT-RELATED FEATURES In the normalcourse ot business, FE and its subsidiaries routinely enter into physical or tinancially settled contracts forthe sale and purchase of electric capacity, energy,Iuel, and emission allowances. Certain bilateralagreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral.

This collateral may be posted in lhe lorm of cash orcredit support withthresholds contingent upon FE's or its subsidiaries' credit rating trom each oI the major credit rating agencies. The collateral andcredit support requirements vary by contract and by counterparty. The incremental collateral requiremenl allows for the offsetting ofassets and liabilities with the same counterparty, where the contractual right of ofiset exists under applicable masler netting agreemenls.

Bilateralagreements and derivative instruments entered into by FE and its suboidiaries have margining provisions that require postingof collateral. Based on FES'power portfolio exposures as of September 30,2016, FES has posted collateralof

$193 million and AESupply has posted collateral of

$4 million.These credit-risk-related contingent teatures, orthe margining provisions within bilateralagreements, stipulate that itthe subsidiarywere to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), itwould be requiredto provide additional collateral. Depending on the volume of torward contracts and future price movements, higher amounts formargining, which is the ability to secure additional collateral when needed, could be required.As a result of the downgrades by Moody's and S&P on July 29, 2016 and August 1, 2016, CES posted additional collateral of

$53million. Additionally, on November 4, 2016, Moody's and S&P further downgraded FES. Given the downgrades, CES has further potential cotlateral posting obligations totaling

$81 million for which counterparties have not exercised their right to require CES to post collateral. Subsequent to the o@urrence of a senior unsecured credil rating downgrade below S&P's and Moody's current ratings, or a "material adverse event," the immediate posting of collateral or accelerated paymenls may be requked of FirstEnergy.The following table discloses the additionalcredit contingent contractual obligations that may be required undercertain events as ofNovember 4, 2016:

Potential Collateral Obligations CES Regulated Total (in millions)Contractual Obligations for Additional Collateral At Current Credit Rating Upon Further DowngradeUpon Material Adverse Event Surety Bonds (Collateralized Amount)Total Exposure from Contractual Obligations 81 $10 264$48 81 48 10 360 355 96$ 144 499Excluded from the preceding table are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment.

As of September 30, 2016, neither FES norAE Supply had any collateral posted wjth lheir affiliates.

OT}IER COMMITMENTS AND CONTINGENCIESFE is a guarantor under a syndicated senior secured term loan facility due March 3,2020, underwhich Global Holding bormwed

$300million. In addition to FE, Signal Peak, Global Rail, GlobalMining croup, LLC and GlobalCoalSales Group, LLC, each being a direct or indirect subsidiary of clobal Holding, continue to provide their loint and several guaranties of the obligations of Global Holdingunder the facility.In connection with the tacility, 69.99% ot Global Holding's direct and indirect membership interests in Signal Peak, Global Rail andtheir affiliates along with FEV'S and WMB Marketing Ventures, LLC'S respective 33- 1/3% membership interests in Global Holding, are pledged lo the lenders under the current facility as collateral.

ENVIRONMEiTIAL MATTERSVarious federal, state and local authorities regulate FirstEnergy with regard to airand waterquality and other environmentalmatters.

Compliance with environmental regulations could have a materialadverse eftect on FirstEnergys earnings and competitive position tothe extent that FirstEnergy competes with companies that are nol subject to such regulations and, therefore, do not bearthe risk ofcosts associated with compliance, or failure to comply, with such regulations.Clean Ah Act FirstEnergy complies with SO, 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 eleciricity from lower or non-emitting plants and/or usingemission allowances.

CSAPR requires reductions of NOx and SOz emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affectedstates to

2.4 million

tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emissionallowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. The U.S. Court ofAppeals for the D.C.

Circuit ordered the EPA on July 28, 20'15, to leconsiderthe CSAPR caps on NOxand SO2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S.Supreme Courl ruling generally upholding EPAs regulatory approach under CSAPR, but questioning whelher EPA required upwindstates to reduce emissions by more than their contribution to air pollution in downwind states. EPA issued a CSAPR updaie rule onSeptember 7,20'16, reducing summertime NOx emissions trom power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Depending on how the EPAand the states implement CSAPR, the future cost ofcompliance may be material and changes lo FirstEnergy's and FES'operations may result.

EPAtightened the primary and secondary NMQSfor ozone from the 2008 standard levels of75 PPBto 70 PPB on October 1,2015.EPA stated the vast majonty of U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and siate rules and programs but EPA will designate those counties that fail to attain the new 2015 ozone NMQS by October 1 , 2017. States will thenha\* roughly three years to develop implementation plans to attain the new 2015 ozone NMQS. Depending on how the EPA and thestates implement the new 2Ol 5 ozone NMQS, ltre future cost of compliance may be material and changes b FirstEnergys and FES'operations may result. In August 2016, the State of Delaware filed a CAA Section 126 petition wilh the EPAalleging that the Harison generating facilitys NOx emissions significantly contribute to Detaware's inabilityto attain the ozone NMQS. The petition seeks a sho term NOx emission rate limit of 0.125lb/mmBTU over an averaging pedod of no more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. On September 27,2016, EPA extended the time lrame for acting on the CAA Section 126 petition by six months to April 7, 2017. FirstEnergy is unable to predict the outcome of this matter or estimate the loss or range of loss.MATS imposes emission limits for mercury PM, and HClfor allexisting and new fossiltuelfired electric aenerating unib effective in April 2015 with averaging of emissions from multiple units located at a single plant. FirstEnergys totalcarital cost for compliance (over the 2012 to 2018 time priod) is currently expected to be approximately

$345 million (CES segment of $168 million and Regulated Distribution segment of

$177 million), of which $267 million has been spent through September 30, 2016 ($117 million at CES and $150 million at Regulated Distribution).OnAugust3,2O15, FG, asubsidiary ot FES, submitted to the AAA office in New York, N.Y., a demand for arbitration and staEment of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure event that excuses FG's p*rformanceu nder its coal transportation contract with these panies. Specifically, the dispute arises from a contract br the fanspodation by BNSF and CSX of a minimum of 3.5 million tons of coal annually through 2025 to cenain coal-fired power plants owned by FG that arelocated in Ohio. As a result of and in compliance with MATS, all plants covered by this

@ntracl were deactivated by April 16,2015. InJanuary 2012, FG notified BNSF and CSX that MATS constituted a torce majeure event underthe contracl that excused FG's lurth*r p*rformance. Separately, on August 4, 2015, BNSF ard CSX submitted to the AAA office in Washington, D.C., a demand for arbitration and statement of claim against FG alleging that FG breached the contract and that FG's declaration of a force majeure under the contract is not valid and seeking damages under the contract through 2025. On [,lay 31, a)16, the parties agreed to a stipulation that if FG's force majeuredefense is determinedto be wholly or partially invalid,liquidated damages are the sole remedy available to BNSFand CSX. The abitration Danelhas determined to consolidate the claims with a liability hearit* scheduled lo beginon November 28,2016, and, if necessary a damages hearing scheduled to begin on May 8,2017. The decision on liability is expected to be issued within sixty days from the end ofthe liabitity hearirE proceedings, which are scheduled to conclude February24, 2017. FirstEnergy and FES continue to believe that MATS constitutes a force maieure event urder the @firacl als it relates b the deactivated plants and that FG's periormance under the contract is thereiore excused. FG intends to vigorously assen its position inthe abitration proceedings. lf, however, the arbitration panel rules in favor ol BNSF and CSX, the resulb of operations andfinancial condition of both FirstEnergy and FES could be materially adversely impacted. Refer to the Strategic Review of CompetitiveOperations seciion of Note 1 , Organization arxd Basis ot Presentation, for possible actions that may be taken by FES in the avent ofan adverse outcome, including, withoul limitation, seeking protection under the bankruptcy laws. FirstEnergy and FES are unable toestimate the loss or range of loss.

FG is also a party to another coal transportation contract covering the delivery o12.5 million tons annually through 2025, a portion ofwhich is to be delivered to another coal-fired plant owned by FG that was deactivated as a result of MATS. FG has asserted adefense of force maieure in response to delivery shortFalls to such plant under this contract as well. lf FG fails to reach a resolutionwith the applicable counterpaniesto the contract, ard if it wsre 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 toestimate the loss or range of loss.As to both coal transportation agreements refersnced above, FG paid approximately

$70 million in the aggregate in liquidateddamages to settle delivery shortfalls in 2014 related to its deaclivated plants, which approximated fullliquidated damages undertheagreements for such year related to the plant deactivations. Liquidated damages for the p*rjod 2015-2025 remain in dispute.As to a specific coal supply agreement, AE Supply has asserted termination rights etfective in 2015. In response to notltication of thetermination, the coal supplier commenced litigation alleging AE Supply does not have sutlicient justificalion to terminate the agreement.

AE Supply has filed an answer denying any liability related to the termination.

This matter is currently in the discovery phase of litigation and no trialdate has been established.

There are approximately

5.5 million

tons remaining underthe conlract fordelivery At this time, AE Supply cannot estimate the loss or range of loss regarding the on-going litigation with respsct to this agreement, In September 2007, AE received an NOV from the EPAalleging NSR and PSD violations under the CAA, as wellas Pennsylvaniaand West Virginia state laws at the coal-fired Hatfeld's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin andWillow lsland plants in West Virginia. The EPA'S NOV alleges equipment r*placements during maintenance outages trigge*d the pre-construction permitting requirements underthe NSR and PSD programs.

On June 29, 2012, January 31, 2013, March 27,2013 ardOctober 18, 2017, EPA issued CM section 114 requesb ior the Harison coal-fired plant seeking infomation and documentationrelevant to its operation and maintenance, including capital pojecls underlaken since 2007. On December 12, 2014, EPA issued aCAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant lo its operation andmaintenance, including capitalprojects undertaken since 2009. FirstEnergy intends b 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-Clinate ChangeFirstEnergy has established a goal to reduce CO2 emissions by 907" below 2005 levels by 20/15. There are a number of initiatives to reduce GHG emissions at the state, federal and international level.

Certain northeaslern states are participating in the RGGI and westein states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions ot certain GHGS. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio stiandards and renewable subsidies have been imDlemented across the nation.The EPA released its final "Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act' inDecember 2009, concluding that concentrations of several key GHGS constitutes an "endangermenf and may be regulated as'air polluiants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including elecllicgenerating plants. The EPA released its tinal regulations in August 2015 (which have been stayed by the U.S. Supreme Cou]t), to reduce Co2 emissions from existing fossil fuel fired electric generating units that would rcquire each siate to develop SlPs bySeptember 6, 2016, lo meet the EPAS state specific CO2 emission rate goals. The EPAS CPP allows states to request a two-yearextension to finalize SlPs by September 6, 2018.

ff states failto develop SlPs,lhe EPA also proposed a federal implemenlafon planthat can be implemented by the EPA that included modelemissions trading rules which states can also adopt in their SlPs. The EPA also finalized sepaftrte regulations imposing COz emission limits for new, modified, and reconstructed fossil fuel fired eleclric generating units. On June 23, 2014, the United States Supreme Court decided that CO2 or olher GHG emissions alone cannot trigger permitting requiremenls under the CAA, but that air emission sou rces that need PSD permits due to other regulated air pollutants canbe rcquired by the EPAto install GHG control technologies.

Numerous siates and privato parties filed appeals and motions to stay theCPPwith the U.S. Court of Appeals for the D.C. Circuit in October2015. On January 21,2015, a panelofthe D.C. Circuit deniedthemotions lor stay and set an expedited schedule for briefing and argument. On February9,2016, 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 oubome of further appeals and how any final rules are ultimately implemented, the future cost ot compliance may be material.At the international tevel, the United Nations Framework Converfion on Climate Change resulted in the Kyoto Protocol requiring participating countdes, which does not include the U.S., to reduce GHGS commencing in 2008 and has been sxtended through 2020.The Obama Administration submitted in March 2015, a fomal pledge for the U.S. to reduce iF economy-wide greenhouse gasemissions by 26to 28 percent below2005levels by 2025 and joined in adoptng the agGement reached on December '12,2015 atthe United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement was raffied by the requisitenumber ot countries (i.e. at least 55 countries representing at least 55% of global GHG emissions) in October 2016 and iF non-binding obligations to limit globalwarming to wellbelow two degrees Celsius are effective on November 4,2016. FirstEnergy cannotcurrently eslimate the financial impact of climate change policies, although potentiallegislative or legulatory programs rcslricting CQemissions, or litigation alleging damages from GHG emissions, could require material capilal and other expenditures or result inchanges to its operations. The COz emissions per l(WH of electricity generated by FirstEnergy is lower than many of its regionalcompetitors due to its diversified generation sources, which include low or non-Co2 emitting gas-fired and nuclear generators.

Clem Wabt ActVarious water quality regulations, the majorityof which are the result of the federalCWAand its amendmenb, apply to FirstEhergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergys 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 Gduce tish impingement when aquatic organisms are pinned against screens or other parts ot a cooling water intake system toa 12% annualaverage and requiring cooling water intake structures e)ceeding 125 million gallons perday to conduct studies to determine site-specitic controls, if any, to reduce entrainment, which occuls when aquatic life is drawn into a facility's cooling water system. FirstEnergy is studying various conlroloptions and their costs and effectiveness, including pilot testing of reverse louvers in a portion ot the Bay Shore planfs cooling water intake channelto divert fish away from the plants cooling water intake system. Depending on the results otsuch studies and any finalaction taken bythe states based on those studies, the tuturecapital costs of compliance with these standards may be substantial.

44 On September 30, 2015, the EPAfinalized new, more stringent effluent limits for the Steam Electric Power Generating category (40CFR Part 423) for arsenic, mercury selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transpon wabr. The treatment obligations willphase-in as permits are renewed on a fiv+year cycle ftom 2018 to2023. The final rule also allows plants to commit to more stringent efiluent limits for wet scrubber systems based on evaporativetechnology and in return have untilthe end ot 2023 to meet the more stringent limits. Depending on the outcome ol app*als and ho,Yanyfinal rules are ultimately implemented, the future costs ofcompliance with these standads may be substantialand changes toFirstEnergys and FES' operations may result.

In October 2009, the WVDEP issued an NPDES water discharge permit tor the Fort Martin plant, which imposes TDS, sulfateconcentralions and other effluent limitations for heavy metals, as well as temperahire limitations. Concurrent with the issuance of theFort Martin NPDES permit, WVDEP also issued an administralive order setting deadlines for MP to meet certain ol the efiluent limitsthat were effective immediately undertheterms of the NPDES pemit. MP appealed, and a stay of certain @nditions of the NPDES pemit and ord*r have been granted pending a final decision on the appeal and subiect to WVDEP moving to dissolve the stay.

TheFort Martin NPDES permit could require an initial capital investment ranging from $150 million to

$300 million in order to installtechnology to meet the TDS and sultate limits, which technology may also meet certain ot 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 lhe appeal or estimate lhe 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 eslimate the loss or range of loss.Regulation ot 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 fulure regulation.In December 2014, the EPAfinalized regulations forthe disposalof CCRs (non-hazardous), establishing national standards regarding landfilldesign, structural integritydesign and assessmenl crileria tor surtace impoundments, groundwaler monitoring and protection procedures and other operational and reporting procedures to assure the sate disposal of CCRS trom electric generating plants.Based on an assessment ot the finalized regulations, the future cost ofcompliance and expected timing of spend had no significanlimpact on FirstEnergy's or FES' existing AROS associated with CCRs. Although none are currenlly expected, any chang*s in timingand closure plan requirements in the luture could materially and adversely impact FirstEnergy's and FES'AROS.Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring lhe Bruce Mansfield plant to cease disposal of CCRS by December 31, 2016 and FG to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FG to seek a permit modification based on"unexpected site conditions that have orwill slow closure progress.-

The permit does not require active dewatering of the CCRS, but does require a groundwaler 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 permittorthe Hatfield's Ferry CCR disposal facility and then modifiedthat permitto allowdisposalot Bruce Mansfield plantCCR.

OnJuly 6, 2015 and October 22, 2015, the Sierra Club tiled Notices of Appeal with the Pennsylvania Environmental Hearing Boardchallenging the renewal, reissuance and modification ot the permit for the Hattield's Ferry CCR disposal lacility.FirstEnergy or its subsidiaries have been named as potentially responsible panies at waste disposalsites, which may require cleanupunder the CERCLA.

Allegations of disposal of hazardous substances at historical sites and the liability involved are otten unsubstiantiated and subject to dispute; howgver, bderal law provides that all potentially responsible parties iora 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 SeDtember 30.2016 based on estimates ol thetotalcosts ol cleanup, FEs and its subsidiaries' proportionate responsibility for such costs and the financialability ot other unaffiliated entities b pay. Total liabilities ot approximately

$121 million have been accrued through September 30, 2016. Included in the totalare accrued liabilities ot approximately

$89 million for environmental remediation of lormer manufactured gas plants and gas holdertacilities in New Jersey, which are being reco\reredby JCP&L through a non-bypassable SBC. FirstEnergy or its subsidiaries could be found potentially responsible for additionalamounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.OTHER LEGAL PROCEEDINGSNudear Plant MattersUnder NRC regulations, FirstEnergy must ensure that adequale funds willb* available to decommission its nuclear tacilities.

As ofSeptember 30, 2016, FirstEnergy had appmximately

$2.5 billion invested in extemaltrusts to be used lor the decommissioning andenvironmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. The values of FirstEnergy's NDTS fluctuate based onmarket conditions. lf the value of the trusts decline by a material amount, FirstEnergys obligation b fund the trusts may increase.Disruptions in the carital markets and their effects on panicular businesses and the economy could also aftect the values of theNDTS. FE and FES have also entered into a total of

$24.5 million in parenial guarantees in support of the decommissioning of the 45 spent fuel storage facilities located al the nuclear facilities. However, as FES no longer mainlains investment grade credit ratings fromeither S&P or Moody's, NG plans to tund a supplemental trust in lieu of a parental guaranlee that would be required to support thedecommissioning of the spent luel storage facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts theamount of its parental guarantees, as appropriate.In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license lor an additional twenty years. On Decembei 8,2015, the NRC renewed the operating license for Davis-Besse, which is now autholized to continueoperation through April 22,2037 . Priol lo that decision, the N RC Commissioners denied an intervenois request to reopen the recordand 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 intervened in that proceeding. On September21, 2016, the U.S. Court ot Appeals for the DC Circuit granted the intervenor's unopposed motion and dismissed this case.As part of routine inspections ofthe 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 $acking condition had propagated a smallamount in selecl areas. FENOC'S analysis confirmsthatthe building continuesto maintain its structural integlity, and its abililyto safely perform all of its functions. In a May 28, 20'15, Inspection Report regading the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation tor FENOC'S tailure to request and obtain a license amendmentfor its method ofevaluating the significance ol the shield building cracking. The NRC also concluded that the shield building ]emained capable of performing its design salety functions despite the identified laminar cracking and that this issuewas of very low satety significance.

FENOC plans to submit a license amendment application to the NRC related to the laminar cracking in the Shield Building.On March 12, 2012, the NRC issued orders requiring satety enhancements at U.S. reactors based on recommendations from thelessons leamed Task Force review of the accident at Japan's Fukushima Daiichi n uclear po$/er plant. These orders require additional mitigation strategies for beyord-design-basis external events, and enhanced equipment for monitoring water levels in spent fud pools. The NRC also requested that licensees including FENOC: re-analyze earthquake and flooding risks using the latestinformation available; conduct earlhquake and fiooding hazard welkdowns at their nuclear plants; assess the ability of cunentcommunications systems and equipment to perform under a prolonged loss ofonsite and otrsiE eleclrical powe[ and assess plant staffing levels needed to lill emergency positions.

These and other NRC requirements adopted as a result of the accident atFukushima Daiichi are likely to result in additional material costs from plant modifications and upgrades at FirstEnergys nuclear facilities.Other Legal liitatP./']sThere are various larusuits, claims (including claims for asbestos exposure) and proceedings related to FiFtEnergy's normal business operations pending against FirstEnergy and its subgidiaries. The loss or range of loss in these matters is not expected to be matedal to FirstEnergy or its subsidiaries.

The other potentially material items not othe ise discussed above are described under Note 11,Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

FirtEnergy 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 cosb.

In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a materialobligation, itdiscloses such obligations and the possible loss or rar*e of loss ifsuch estimate can be made. lf it were ultimately detemined that FirstEnergy or its subsidiaries have legal liabilityorare otherwise made subject to liability based onany of the matters referenced above, it cluld have a material adverse effect on FirstEnergys or its subsidiades' financial condition, results of operations and cash flows.13. SUPPLEIIEiIfAL GUARANTOR INFORIIATIONIn A)07, FG compleied a sale and leaseback transaction for a 93.83% undivided interest in Bruce Mansfield Unit 1. FG's parent company has fully and unconditionally and inevocably guaranteed all of FG's obligations under each ofthe leases. The related lessolnotes and pass through certificates are not guaranteed by FG or ib parent company, but the notes are securd by, among otherthings, each lessortrust's undivided interest in Unit 1 , rights and interests under the applicable lease and rights and interests underother related agreements, including FES' learse guaranty.

This transaction is classified arsi an operating lease for FES and FitslEnergyand as a financing lease br FG.The Condensed Consolidating Statemenb of Income (Loss) and Comprehensive Income (Loss) for the three and nine monhs endedSeptember 30, 2016 and 2015, Condensed Consolidating Balance Sheets as of September 30, 2016 and December 31, 2015, andCondensed Consolidating Statemen$ ofCash Flows for the nine months ended September 30,2016 and 2015, for the parent and guarantor and non-guarantor subsidiaries are presented below. These statements are provided as FG's parent company fully and unconditionally guarantees outstanding registered securities of FG as wellas FG's obligations underthe tacility lease for the BruceMansfield sale and leaseback that underlie outsianding registered pass-through trust certificates.

Investments in wholly ownedsubsidiaaies are accounted forbythe parentcompany using the equity method. Results of operations for FG and NG ate,therefore,reflected in their parent companys investment accounts and earnings as if operating lease treatment was achieved.

The principalelimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required toreflect operating lease treatment associated with the 2007 Bruce Mansfield Unil 1 sale and leaseback transaction.

46 FIRSTENERGY SOLUTIONS CORP.CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Three Months Ended September 30, 2016 FES FG NG Eliminations Gonsolidated 494 $(ln millions)400 $(85s) $1,100STATEMENTS OF INCOME REVENUES OPERATING EXPENSES: Fuel Purchased power from affiliates Purchased power f rom non-affiliatesOther operating expensesProvision for depreciation Generaltaxes Total operating expenses oPERATTNG TNCOME (LOSS)oTHER TNCOME (EXPENSE):

Investment income, including net income from equity investees Miscellaneous incomeInterest expense - affiliates Interest expense - other Capitalized interestTotal other income (expense)rNcoME (LOSS) BEFORE TNCOME TAXES (BENEFITS) rNcoME TAXES (BENEFTTS)NET INCOME STATEMENTS OF COMPREHENSIVE INCOME NET INCOME orHER COMPREHENSTVE TNCOME (LOSS): Pension and OPEB prior service costs Amortized gains on derivative hedgesChange in unrealized gains on available-for-sale securitiesOther comprehensive income (loss)lncome taxes (benefits) on other comprehensive income (loss)Other comprehensive income (loss), net of tax COMPREHENSIVE INCOME$ 1,065 1,0;186 95 4 8 245 999 224 I 28 (236) 24 1-1 (13) (3) (2) 15 (3)(14) (27) (e) 14 (36)1s7 (18) 23 (207) (5)(218)2 40$144 $76$(220) $40$144 $76$(220) $53 39 149 51 6 149;28 7 (85s)11 202 191 186 316 83 21 101 102 1,304 (23e)(848)(11)(42)(82)125 231 49 96 40 (3)1 5 3 (s)(3)(3)1 5 (3)(1)(2)

(1)42 (2)$ 142 (221\ $CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)For the Nine Months Ended September 30, 2016 FES NG Eliminations Consolidated FG STATEMENTS OF INCOME (LOSSI REVENUES 3,281 $(ln millions)1 ,309 $ 1,404 $47 (2,593) $3,401 OPERATING EXPENSES: Fuel Purchased power from aftiliates Purchased power f rom non-aff iliates Other operating expenses Provision for depreciation Generaltaxes lmpairment ol assetsTotal operating expenses oPERATTNG TNCOME (LOSS)oTHER TNCOME (EXPENSE):

Investment income, including net income (loss)from equity investees Miscellaneous incomeInterest expense - affiliatesInterest expense - other Capitalized interestTotal other income (expense)rNcoME (LOSS) BEFORE TNCOME TA)GS (BENEFITS) rNcoME TAXES (BENEFTTS)

NET TNCOME (LOSS)STATEMENTS OF COMPREHENSIVE INCOME (LOSS)NET TNCOME (LOSS)oTHER COMPREHENSTVE TNCOME (LOSS): Pensions and OPEB prior service costs Amortized gains on derivative hedges Change in unrealized gains on available-for-sale securitiesOther comprehensive income (loss)Income taxes (benefits) on other comprehensive income (loss)Other comprehensive income (loss), net of tax coMPREHENSTVE TNCOME (LOSS)FIRSTENERGY SOLUTIONS CORP.449 146 2,ggg 145 829 218 220 450 10 91 151 23 23 20 23 517 3,991 1,300 912 492 (2,593)37 (2)595 440 829 925 250 66 540(2,558)3,645 (710)(3s)(244)310 3 (34),1'21 1 (7)(7e)7 67 (4)(33)20 (57)so (260) (28)-(':)39: 56 4 (6)(10e)27 239 (471)(204)(267) $(48)(1)(2e5)4 (272)(5)196 (267) $(47) $(47) $346 $(2es) $(267)346 $(2ee) $(267)60 (10)(10)1 (60)(10)61 61 51(10) 60 51 (50)20 (4) 23 (1e) 20------.sr--

rqrl-$ (136) $- $ 383 $ (s3o) $-]mo)--+: 48 FIRSTENERGY SOLUTIONS CORP.CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOMEFor the Three Months Ended September 30, 2015 FES NG Eliminations Consolidated 1,293 $420 $(ln millions)531 $(s06) $1,338STATEMENTS OF INCOME REVENUES OPERATING EXPENSES: Fuel Purchased power from affiliates Purchased power f rom non-aff iliatesOther operating expensesProvision for depreciation Generaltaxes Total operating expenses oPERATTNG lNCOM E (LOSS)OTHER TNCOME (EXPENSE):lnvestment income (loss), including net income from equity investeesMiscellaneous income Interest expense - affiliatesInterest expense - other Capitalized interest Total other income (expense)rNcoME BEFORE TNCOME TD(ES (BENEFTTS)rNcoME TAXES (BENEFTTS)NET INCOME STATEMENTS OF COMPREHENSIVE INCOME NET INCOMEOTHER COMPREHENSIVE LOSS:Pension and OPEB prior service costs Amortized gains on derivative hedges Change in unrealized gains on available for sale securitiesOther comprehensive loss Income tax benelits on other comprehensive lossOther comprehensive loss, net of taxCOMPREHENSIVE INCOME 9;

401 34 3 10 1,380 t: 66 30 8 52 77 134 47 6 316 (rT)12 (1)245 103 401 246 79 24 (8e5)1,098 (87)(11)215 123 191 (8)4 (18)1-(r1) ,r], (13) (26)(2) (1) e (2)(12) 15 (36)17o (22) (24) (174) (s0)(37)83 101 191 (185) 190 120 $65$121 $(186) $70 36 120 120 $65$121 $(186) $(3)t+)j 11 (4)(11)14 5 (1s)(6)9 (e)I 111 $ 63 q 114 9_(1?1 g 111 CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOMEFor the Nine Months Ended September 30,2015 FES NG Eliminations ConsolidatedSTATEMENTS OF INCOME 49 FG (ln millions)

REVENUES OPERATING EXPENSES: Fuel Purchased power from affiliates Purchased power from non-affiliatesOther operating expenses Provision for depreciation Generaltaxes lmpairment of assetsTotal operating expenses oPERATTNG TNCOME (LOSS)orHER TNCOME (EXPENSE):lnvestment income (loss), including net income from equity investees Miscellaneous incomeInterest expense - affiliatesInterest expense - other Capitalized interest Total other income (expense)rNcoME (LOSS) BEFORE TNCOME TA)GS (BENEFITS) rNcoME TAXES (BENEFTTS)

NET INCOMESTATEMENTS OF COMPREHENSIVE INCOME NET INCOME OTHER COMPREHENSIVE LOSSPension and OPEB prior service costs Amortized gains on derivative hedges Change in unrealized gains on available-for-sale securitiesOther comprehensive loss Income tax benefits on other comprehensive lossOther comprehensive loss, net of tax COMPREHENSIVE INCOMEFIRSTENERGY SOLUTIONS CORP.$ 3,699 $ 1,259 $1,494 $(2,618) $3,834 523 2,657 1,336 300 208 892 36 23 16 143 211 452 142 19 (2,618)36?666 250 1,336 996 240 78 16 4,353 967 (2,584)(34)'u1'24: 3,582 (654)551 1 (21)(3e)413 527 252 12 4 (6)(78)(1)(3)(37)(7)5 (6)(110)26 422 492 (64) (1e) (s01) (e2)(162)(2s8)187 131 508 (535)4 160 64 e6$218 $321 $(53e) $e6$218 $321 $(53e) $(12)(2)(34)(13)31 11 (12)(2)(20)(34)(13)(11)11 (20) (20)(11) (20)(4) (7)211 $308 $(s1e)(21) (7) (13) 20 (21)75$50 As of September 30, 2016FIRSTENERGY SOLUTIONS CORP.CONDENSED CONSOLIDATING BALANCE SHEETS FES FG NG Eliminations Consolidated ASSETS CURRENT ASSETS: Cash and cash equivalents Receivables-CustomersAffiliated companies Other Notes receivable from affiliated companies Materials and supplies Derivatives Collateral Prepayments and other PROPERTY, PLANT AND EQUIPMENTln service Less - Accumulated provision for depreciation Construction work in progress INVESTMENTS:

Nuclear plant decommissioning trustsInvestment in affiliated com panies OtherDEFERRED CHARGES AND OTHER ASSETS:Accumulated deferred income tax benefits Gustomer intangiblesProperty taxes

Derivatives OtherLIABILITI ES AND CAPITALIZATION CURRENT LIABILITIES:

Currently payable long-term debt Short-term borrowings-Affiliated companies Accounts payable-Affiliated companies OtherAccrued taxes Derivatives Other CAPITALIZATION:

TotalequityLong-term debt and other longterm obligations NONCUR RENT LIABILITIES :

Deferred gain on sale and leaseback transactionAccumulated deferred income taxesRetirement benefits Asset retirement obl igations Derivatives Other 57 1,4n 2.025 1,643 (3.594) 1.496 5,683 8,674 (378) 14,100 5,822 8,278 287 758 1.048 75 4,055 5,382 (186) 9.326 1 ,915 4,050 (192)3,768 4,624 (186)$225 356 21 494 38 146 85 2$351 4 1,501'1 (ln millions)$267 30 1,133 ,,:$(4e2)(t,t3 225 482 55 26 403 146 85 72 121 49 72 3 7,826 1,542 (7,826)1,542 10 10 7,826- 10 1,s42 (7,826) 1,552 29 333 12 374-i;; -ot$-tu'- S-57d $-E,ffi

$-Tmboi s--12*67-279 27 11 37 98$ $ 1es $2,723 480 597 165 180 18 71 31 28 51 88 1-66 71 12 ss 1015 -5,409 2,897 4,893;-817 25 194 186 701 455--:' I 8 $ (25)$ 182 (3,102) 101(u:) '33 (38) 72 89 33 182 (3,681) 1,108 691 2,108 1 ,120 (1 ,104) 2,815 6Joo - oos qo13 -'%)-(7,790\ 5,409 765 765 (90) 734 219 887 50 40 48 792 880$--6;ass S-s5r4 ,goo) $ te,eoz ,-:-r#51 As of December 31,2015 FIRSTENERGY SOLUTIONS CORP.CONDENSED CONSOLIDATING BALANCE SHEETS FES NG Eliminations Consolidated (ln millions)FG ASSETS CURRENT ASSETS:Cash and cash equivalents Receivables-Customers Affiliated companies OtherNotes receivable from affiliated companies Materials and supplies Derivatives Collateral Prepayments and other PROPERTY, PLANT AND EQUIPMENT ln service Less - Accumulated provision for depreciationConstruction work in progress INVESTMENTS:

Nuclear plant decommissioning trustslnvestment in affiliated companies OtherDEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits Customer intangibles Goodwill Property taxes Derivatives OtherLIABILITI ES AND CAPITALIZATION CURRENT LIABILITIES:

Currently payable long-term debtShort-term borrowings-Affiliated companies Other Accounts payable-Affiliated companies OtherAccrued taxes Derivatives Other CAPITALIZATION:

TotalequityLong-term debt and other long-term obligationsNONCURRENT LIABILITIES

Deferred gain on sale and leaseback transactionAccumulated deferred income taxes Retirement benefitsAsset retirem ent obl igations Derivatives Other 48 18 66 1,4?5 1*41 ?256) -T5s8 93 6,367 8,233 (382)14,311$275 433 36 406 53 154 70 2$ $403 461 419 1,210 805 ,t: ,:$(846)12,+i'1 2 275 451 59 11 470 154 70 1,327 10 40 2,144 3,775 (194) ?'19?53 4,223 4,458 (188) 8,546 30 24s 878 - !'!5-!83 4,472 5.336 (188) 9,703- -io-re- 0,+szt 1,337 7,452 300 61 23 79 884 21 7 103 5,605 690 1,327 10 146 368 118 93 62 1-(25) $(2,410)(r1)(86)45 570$ 13,199_104 181 61 23 40 79 367 28 T 12 (.:)29 312 14 12--Eao--to4)

$ e5o2 $-5bt$-g,ud,t$-Tit2ooi 22s $ 308 $2,021 389 8 512 8 542 139 76 66619 3J 02 1 .045 747 (3,332) 1 ,562 2,944 4,476 (7,420)2,116 840 (1 ,136)5,605 2,510 6.295-5,060 5,316 (8,556) 8"115;27 37 305 191 1 697 640 791 (rT)791 600 332 831 38 899 105 558 2,140 688 = ,9'1?1$ esot $-G-o6t 5-8"203 il (tt,eoo) $ 13,168$g50r- S----6.06t f 8,203- $ (11,299I $ 13'Eq-35 61 803 52 FIRSTENERGY SOLUTIONS CORP.CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWSFor the Nine Months Ended September 30, 2016 FES FG NG Eliminations Consolidated 401 $(ln millions)820 $(12) $NET CASH PROVTDED FROM (USED FOR)OPERATING ACTIVITIES CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-Long-term debt Short-term borrowings, netRedemptions and Repayments-Long-term debt OtherNet cash provided from (used for) financing activities CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions Nuclear fuel Sales of investment securities held in trustsPurchases of investment securities held in trusts Cash investmentsLoans to affiliated companies, net Other Net cash used for investing activities Net change in cash and cash equivalentsCash and cash equivalents at beginning of periodCash and cash equivalents at end of period (e6)(463)(7ee)$ (605)701 285 12 186 92 (211)(5)62 (304)(2)(6e2)47',l101 (503)(7)701 (21)(680)62 ,m, 10 (87)9 (,r:)(2s2)(233)(1e5)576 (61e)(328)692 (432)(1e5)576 (61e)10 (15)9 692 (666)2 e, Y': c 53 FIRSTENERGY SOLUTIONS CORP.CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Nine Months Ended September 30, 2015 FES FG NG Eliminations ConsolidatedNET CASH PROVTDED FROM (USED FOR)OPERATING ACTIVITIES CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-Long-term debt Short-term borrowings, netRedemptions and Repayments-Longterm debt Short-term borrowings, net OtherNet cash provided from (used for) financing activities CASH FLOWS FROM INVESTING AGTIVITIES:Property additions Nuclear fuel Sales of investment securities held in trusts Purchases of investment securities held in trustsLoans to affiliated companies, net Cash Investments Other Net cash used for investing activitiesNet change in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period 672 35 (54)(3) (144) (1e4)(101)503 (546)(45) (302) (475)(10)10 6 (48)(440) (813)405 $(ln millions)867 $$ (oz+)689 (17)(12) $636 43 51 ,1'(4)296 (322)(27)(1)(740)12 (82)(382)(10e)(5)339 (810)(157)2 2 822 (341)(101)503 ,u1, (10)16 822 (47e)2$54

14. SEGIIENT INFORiIATION FirstEnergys reportable segments are as follows: Regulated Distribution, Regulated Transmission, and CES.Financial information for each ot FirstEnergy's reportable segments is presented in the tables below. FES does not have separatereportable operating segments.The Regulated Distribution segment distributes electdcity through FirstEnergy's ten utility oPrating companies, serving approxi;ately six million ostomerswithin 65,000 square miles of Ohio, Pennsylvania, Wesf Virginia, Maryland, New Jersey and New vbi.4 ana pulcnases power lor its POLR, SOS, SSO and default service requirements in Ohio, Penns,ylvania, New Jersey andMarytand. ihis segment also controls 3,790lvfws of regulaled electric generation capacity located pdmalilyin WeslMryinia, Viqinia and New Jersey. The segment's results retlect the com;pdity cosB of aecuring electric generation and the deferal and amonizationof ceftain fuel costs.The Regulatad Transmission segmenttransmib electricity through transmission tacilities owned and operated byATSl,TrAlL, a]d certain;f FirsrEnergys utitities (Jcp&L, ME, PN, MB PE a;d WP). This s*gment also includesthe regulatory asset associated withthe abandoned PATi proiect. The segments revenues are primarily derived from forwardlooking rates at ATSI and TrAlL, as u*ll asfixed rates at certain-ot FirstEnergy;s utilities.

Both the fonyardiooking and fixed rates recover costs and provide a return ontransmission capital investment. Unierthe fo]ward-lookng rates, eaci of ATSI'S atd TrAlUs revenue *quilement is updated annuallybased on a proiected rate base and pmjected costs, which is subject to annualtrue-up based on actualcosts.

Except for the recoveryof the pATti abandoned project regutatory asset, the segments revenues are primarilyfrom transmission selvices provided b LSES pursuant to the PJM tarif.

ite segmenti results also reflect the net transmission expenses related to the delivery of slectricity onFirstEnergys transmission facilities.The CES segment, through FES and AE Supply, primarily supplies electricity to end-use customers through retail and wholesale anangementl, including aompetitive retait sit'ei ti customers primarily in Ohio, Pennsytvania, lllinois, Michigan, New Jersey and t,tarytind, anO ttre proviiion oi partiat POLR and delault servicelorsome utilities in Ohio, Pennsylvania and Maryland, including the Utitiiies. As of September 30,2016, this business segment controlled 13,162 l Ws of electric generating capacity. The CES segment's net income is pdmarily derived from electric g;neration sales less the relaled costs of electricily generation, includingfuel, puicnased power and net transhission (including con-gestion) and ancillary costs and capacrty costs charged.by PJM to deliver;nergy to lhe segment's customers, as well as othel operating and mainlenance @sts, including costs incuned by FENOC.Colporate support and other businesses that do not constitute an operating segment, interest epense on sland-alone holding company delii and corporate income taxes are categorized as Corporate/Other for reportable business segment purposes.Additionally, reconciling adjustments for the elimination of inler-segment transactions are included in Corporate/Other. As of SeptembeiSO, ZOt 6, C6rpoiate/Other nad 94.2 billion of stand-alone holding company long-term debt, of which 28% was subject tovariable-interest rales, and

$2.7 billion was borrowed by FE undel its revolving credit facility.55 Segment Financial lnformation For the Three Months Ended Regulated Distribution Regulated Transmission Gompetitive Energy Services Corporate/

Other ReconcilinE Adiustmentl Gonsolidated Seotember 30.2016 External revenues lnternal revenuesTotal revenues Depreciation Amortization of regulatory assets, net Investment incomeInterest expenseIncome taxes (benelits)Net income (loss)Total assets Totalgoodwill Property additions Seotember 30.2015 External revenues Internal revenues Total revenues DepreciationAmortization of regulatory assets, net lmpairment ol assets Investment income (loss)Interest expense Income taxes (benefits)

Net income (loss)Totalassets Totalgoodwill Property additionsFor the Nine Months Ended Seotember 30.2016 External revenues lnternal revenues Total revenues Depreciation Amortization of regulatory assets, net lmpairment of assets (Note 2)Investment income Interest expense Income taxes (benefits)

Net income (loss)Property additions September

30. 2015 External revenues lnternal revenues Total revenues Depreciation Amortization ol regulatory assets, nellmpairment of assets Investment income (loss)lnterest expense Income taxes (benef its)Net income (loss)Property additions

$ 248 $ 1,327- 141 248!;41 70 6,988 526 149 t:$(141)(2y 2,702 $'y$(ln millions)9e8 $117 3,917 2,702 171 98 13 139 167 283 28,276 5,092 303 2,624 285 i 43 45 78 8,034 526 246 79 23 48 49 86 15,165 110 311 98 28 286 251 380 51,961 5,618 664 4,123 4,123 328 110 8 (28)285 226 395 51,930 6,418 539 2,624 174 110 8 8 149 137 234 27,883 5,092 292 7,423 $1,468 i (1e)48 84 145 16,229 800 83 3,158 377 (11 7)(185) 3,917 16 , trol 56 (11) 1 (67)486 5-$ (76) $15 (6) (11)48 (3e) 3 (54)830 15 (218) $ 11,187 7,423 510 218 7,425 $3,535 284 1,447 56 143 (s6)(1,029)492 i 13 161 (51)(16e)31 824 132 4$ 3,536 $ $ (231)$ 11,48s s63 (563)-----loee"--

11/8s 293 44 969--+ii rc 974 222 1,447 75 863 334 (381)2,156 ttl tsll 144 (84) 8 (1s4)41 201 24 (14)846 485 804 2,025 37 431 349 594 878 128 130 223 755'1 (31)2 7,425 516 196 I 33 439 350 598 884 16 (7)144 76 129 400 755 116 j 119 135 231 700 56 Item 2.Management's Discussion and Analysis of Registrant and Subsidiaries FIRSTENERGY CORP.MANAGEMENT'S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONSFIRSTENERGY'S BUSINESSFirstEnergy and ib subsidiaries are principally involved in the generation, lransmission and distribution of electricity.

lts reportable segments are as follows:

Regulated Distribution, Regulated Transmission, and CES.The Regulated Dbtrlbu on segment distibutes electricity through FirstEnergy's ten utility operating companies' servingapproxiriately six million customers within 65,000 square mib; otOhio, Pennsyhrania, West Virginia, Maryland, New Jersey and New ybrk, and puichases poyver for its POLR, SOS, SSO and default service requirements in Ohio, Penns}lvania, New Jersey and Maryland.

This segment also controls 3,790 lWVs of regulated electric aeneration capacity located primarilyinl/t/est Virginia' Virginia and New Jersey. The segment's resulb reflect the comirodity costs ot iecuring electric generation and the deferral and amonizationof cenain fuel costs.The Regulated Transml$lon segment transmits electricity through transmission tacilities owned and operated byATSl,TrAlL, andcertain 6f FirstEnergy's utitities (JCP&1, ME, PN, MP, PE and WP). This segment also includes the regulatory asset associated withthe abandoned PATH project. The segment's revenues are primarily derived from forwardlooking rates atATSland TrAlL, as

\'vell asfixed rates at certain of FirstEnergyls utilities. Both the forwardlooking and fixed rates recover costs and provide a return on transmission capitalinvestment. Un-der the lonarardlooking rates, each of ATSI's and TrAlUs revenue Equirementis updated annuallybased on a projected rate base and projected costs, which is subject lo annualtrue-up based on actualcosb.

Exceptbrthe recovery ofthe PATH abandoned project regula6ry asset, the segment's revenues are primarily from transmission services provided to LSES pursuant to the pJM taritt. itre segmentt results also reflect the net transmission expenses related to the delivery of electricily onFirstEnergy's transmission facilities.The CES segment, through FES and AE Supply, primarily supplies electricity to end-use customers through retail and wholesale arrangemenG, including competitive retail salei to customers primarily in Ohio, Pennsylvania, lllinois, Michioan, Now Jersey and tvtarytind, and tne proviiion oipartial POLR and detault servicefor some utilities in Ohio, Pennsylvania and Maryland, including lhe Utitiiies.

es of September gO, ZO1O, ttris business segment controlled 13,162 lvlvvs of electric generating capacity. The CES segment's net income is primarily derivedfrom electric g;neration sales lessthe related costs ol electricity generation, including tuel'puichased power and net transmission (including congestion) and ancillary costs and capacity costs charged.by PJM to deliver;nergy to the segment's customers, as well as other operating and maintenance costs, including costs incurred by FENOC.Corporate support and other businesses that do not constitute an operating segment, interest expense on stand-alone holding company debi and corporate income iaxes are categorized as Corporate/Other for reportable business segment purposes'AOOition'atty, reconciling adjustments for ihe elimination of inter-segmenl transactions are included in CoPorate/Other. As of Septembei gO, ZOt O, C6rpoiate/Other trad g4.2 billion of stand-alone holding company long-term debt, of which 28% was subject tovariable-interest rates, and

$2.7 billion was borrowed by FE under its revolving credil facility.57 EXECUTIVE SU iIARYFirstEnergy believes having a combination ot distribution, transmission and generation assets in a regulated or regulatedlike construct is the best way to serve customers.

The Company's strategy is to be a fully regulated utility, focusing on stable and prediciable earnings and cash flow from its regulated business units.C@pdllveElersyscrviegs In order to execute on this strategy, FirstEnergy has begun a strategic review of its competitive operations focused on the sals of gas and hydroetectric unis as wellas Lpbring atilftematives for the remaining generation assets at FES and AE Supply.

These indude,but are not limited to, legislative efforts to aonvert generation from competitive operations to a regulated or regulated-like constructsuch as a regulatory reJtructuring in Ohio, offering generation into any process to address MP's generation shortfall included in itsIRR and/or a-solution for nuclear generation that recognize their environmentalbenefib. Management anticipates that the viatility ofthese altematives will be determined in the near ter; with a target to implement these strategic options within the next 12 lo 18months and could result in material asset impairments.Based on cunent maket foMards, CES, including FES, expects to have more than sufficient cash flowfrom operations in 2017 and2018 to fund anticipated capital expenditures with no equity contributions trom FirstEnergy.

However, in addilion to exposure to market price volatility and operational risks, CES, including FES, faces significant financialrisks thatcould impact its anticipated cash flow and liquidity including, bul not limited to, the following:Requests to post additionalcollateral or accelerated payments of up to $355 million resulting from current credit ratings at FEd, including Moody's downgrade of the Senior Unsecured debt rating for FES to Caal as well as S&P's downgrade of theSenior Unsecured debt rating at FES to B, both of which occurred on November 4,2016.Adverse outcomes in the previously disclosed disputes regarding longterm coal transportation contracts-The inability to extend or refinance debt maturities at CES, including at FES subsidiaries, in 2017 and 2018 of $130 million and $515 million, respectively.

A significant collateralcallor the inability to refinance 2017 debt maturities at FES subsidiaries is expected to be addressed by FESthrough a combination of cash on hand, additional capital exp*nditure reductions, asset sales, ancvor borrowings under the unreg-ulated money pool. However, adverse outcomes in the coal transportation contracts disputes, the inability to relinance 2018debt;aturities, oriack of viable alternative strategies could cause FES to iake one or more of the lollowing actions: (i) restructuringot debt and otherlinancial obligations, (ii) additio;al borrowings under the unregulated money pool, (iii) further asset sales or plantdeactivations, and/or (iv) seekprotection underbankruptcy laws. In the event FES seeks such protection, FENOC may similarly seek protection under bankruptcy laws.Material asset impairments, resulting from the sale or deactivation of generation assets or from a determination by management of itsintent to exit competitive generatio; assets before the end of their estimated useful life resulting lrom the inability to implementalternative strategies discussed above, adverse judgments or a FES bankruptcyfiling could result in an event of dehult u nder various agreements relaied to the indebtedness ol FE- Although management expects to successfully resolve any FE defaults lhroughwaivers or other actions on acceptable terms and conditions, the failure to do so would have a material and adverse impact on FirstEnergy's financial condition, and FirstEnergy cannot provide any assurance that it will be able to successtully resolve any suchdefaults on satisfactory terms.During this period oftransition, subject to strategic decisions regarding competitive generation assets, it is anlicipated that CES will produie approximatety 70 to 75million MWHS of electricity annually, with up to an additional five million MWHS available from purchased iower agreements forwind, solar, and CES'entitiement in OVEC. In 2017 and 2018, CES expects to hedge 75% - 85%of its generation out-put by targeting approximately 50 to 65 million [lwHs in annual contract sales and maintaining upto 25 millionMWHI as ,eserue margiri. for thJpdrioO Octobei 1,2016 to December 31,2016, CES'committed sales are S2y"tedged against generation supply, including committed purchases, assuming normalweather conditions. As of Septembel 30, 2016, contractual iales obligatidnjior 2017 ;nd 2018 ar; approximately 48 ;illion MWHS and 28 million MWHS, respectively.

Contractual sales obligations for A)16 are approximately 67 million lvfwHs.

CES will continue to make prudent investmenb in its nuclear units in order to maintain safe and reliable operations in accordance with nuclear standards, buiwill continue to focus on costs given current market @nditions, specifically surounding its lossilieet.

Management curren y anticipates totalcapitale4enditureJ of $370 million and

$300 million in 2017 and 2018, tespectively, which represents a significant reduction lrom 2Ol6 forecasted capital ependitures of $540 million.Reoulated TransmissionThe centerpiece of FirstEnergy's regulated investment strategy continues to be ib Enelgirng the Fulutetransmission plan. The plan inctudes gi.2 biltion in investments irom 2014 through 2017 a;d an additional

$8OO million to

$1.2 billion annually from 2018 to 2021 58 to modernize FirstEnergy's transmission system to make it more reliable, robust, secure and resistant to extreme weather events,with improved operational flexibility.These investments will continue to be focused in oul stand-alone transmission @mpanie6 with lormula rates including ATSI, TrAIL and MAIT (which will include the transmission assets from Met-Ed and Penelec), as well as the transmission system at JCP&L asfilingswere made with FERC on October 28,2016 to implement and transition to aformula rate for MAIT and JCP&L's transmission investments.

FirstEnergy believes efsting transmission infrastructure creates improvement inr*slment opportuni$es ol apgofmately

$20 billion beyond those idenlilied through 2021.Reoulated Distdbution The scale and diversity ot our regulated utilities has uniquely positioned Regulat6d Distribulion for growth and represents anaddilional investment opportunity. Although weather-adjusted distribufion deliveries through 2019 are forecasted to be flat ascompared to 2016, Regulated Distribution's eamings over the next three years are anticipated to increase as a result of the recentorder by the PUCO regarding the Ohio Companies' ESP lV, which includes approfmately

$204 million, gossed up ior income bxes, in additional annual revenue through rider DMR, cunent settlement agreements that are pending betore the PAPUC regarding the Pennsylvania Companies' base rate cases, as well as the impact of the settlement-in-principle achieved in the base l?lte case in New Jersey, which provides for an annual

$80 million distribution revenue increase effective on January 1, 2017, subject to finalization,execution and NJBPU approval of a Slipulation ol Setllement.

Planned capital ependitures for Regulated Distribution are approximately

$1.3 billion, annually for 2017 through 2019.

59 FINANCIAL OVERVIEW (ln millions, except per share amounts)For the Three Months Ended September 30For the Nine Months Ended September 30 2016 2015 Change$ (206) (5)%2016 2015 Change REVENUES:OPERATING EXPENSES:

Fuel Purchased powerOther operating expensesProvision for depreciation Amortization of regulatory assets, net Generaltaxes lmpairment of assets Total operating expensesOPERATING INCOME OTHER TNCOME (EXPENSE):

Investment income (loss)Interest expenseCapitalized financing costs Total other expense rNcoME (LOSS) BEFORE TNCOME TAXESINCOME TAXES NET TNCOME (LOSS)$ 11,187 $ 11,485 $ (298) (3)/.(32) (7)o/" 1,269 1,378 (109)(230) (19)%

2,992 3,311 (319)13 % 2,835 2,79936 5 21 39 (5)%(8) (100)%

1,447 24 1,423 NM10.525 9.429 1,096 12 %-3,056 3,215 861 28 (286)28(230) (287t 57 (20\%$ 3,917$ 4,123 482 1,209 842 328 110 236 8 450 979 953 311 98 265 111 (17l'89 (17)(8)%(10)%1 "/" 1 o/o 10 o/" 5%NM 2%(12\ (11)./" 29 12%974 222 786 969 201 747 (15e) (5t%(47) (5)%56 (2001./" 662 2.056 (1,3s4) (68)%(28)(28s)26-%8 o/o (1)2 75 (14)(863) (846)

(47) 1,289 334 485 (1,336) (104) /0 (151) (31)%9_(1 ,185)_ (147)/" (2.81) (147)%(2,80) (147)%7s e3 (14) (15)%?oe) 06?\ -58 (8)%631 251$ gao 621 226 g 1.e1 $$ 1.e0 $$ 0.89$ 0.89 2 o/"11 %$ (15) _<al%. $_(381)10 25 0.94 0.93 (0,0s)(0.04)(5)./, (4)%(0.e0)(0.e0)EARNTNGS (LOSSES) PER SHARE OFCOMMON STOCK:

Basic Diluted$

$$$$$NM - Not Meani.lulFor the Thr** iltonlhs Ended Septem'*,t 30. 2016FirstEnergy's net income in thethird quarter of 2016 was

$380 million, ora basic and diluted earnings ot$0.89 pershare of common stock, compared with net income ol $395 million, or basic earnings of

$0.94 per share of common stock

($0.93 diluted) in the third quarter of 2015.As further discussed below third quarter 2016 earnings improved over the same period ot 2015 at Regulated Distribution andRegulaled Transmission but were partially otfset by lower earnings at CES and Corp/Other.

During the third quarter of 2016, FirstEnergy's revenues decreased

$206 million as compared to the same period in 2015, primarilyresulting from a $353 million decrease at CES, partially ofiset by a

$78 million increase at Regulated Oistribution and a

$37 million increase al Regulaled Transmission.. The decrease in revenue al CES resulted trom a 2.6 million MWH decline in contract sales as the segmenl continues to align its sales to its generation, as well as lower capacity revenue associated with lower capacity auction prices, parliallyoffset by higher wholesale sales.. The increase in revenue at Regulated Distribution primarily resultedlrom a 7% increasein MWH deliveries mainly related to higherweatheFrelated usage as well as higher rates associated with the recovery of detened program costs, partially offsel by lower default service generation sales resulting primarily from lower prices in Ohio and Pennsylvania.. The increase in revenue at Regulatsd Transmission resultedtrom recovery of incrementaloperating expenses and a higher rate base at ATSI and TrAlL, parlially offset by a lower ROE at ATSI.Operating expenses deffeased

$159 million in the third quarter of 2016 as compared to the third quarter o12015, primarily reflecting a decrease at CES of

$217 million, partially otfset by an increase at Regulated Transmission of $22 million and an increase alRegulated Distribution of $14 million. Changes in certain operating expenses include the following:. Fuel expense decreased

$32 million, primarily resulting from lower generation at CES associated with outages and economic dispatch ol fossil units resulling trom low wholesale spot market energy prices, as well as lower unit prices onfossil fuel contracts.. Purchased power decreased

$230 million, primarily due to lower capacity expense at CES as a result of lower conlract sales and capacity rates, as well as lower default service and wholesale spot ma*et prices.. Other operating expenses increased

$111 million, primarily retlecting an increase of

$81 million at Regulated Distribution primarily associated with higher storm restoration expenses, network transmission expenses in Ohio and retirement benefitcosts as well as a

$31 million increase at CES resulting primarily from a contract termination charge.60 Other income (expense) increased

$57 million, prjmarily from lower OTTI on NDT investments. FirstEnergy's ofiective lax rate was39.8% tor the three months ended September 30, 2016 compared to 36.4% for the same period in 2015.For the Nlne Months En ted sF,otember 30. m16 For the nine months ended September 30, 2016, FirstEnergy's net loss was

$381 million, or a basic and diluted loss of $(0.90) pershare of common stock, compared to net income of

$804 million, or basic earnings of $1.91 per share of common stock

($1.90 diluted) for the nine months ended September 30, 2015.FirstEnergy's 2016 year-to-date eamings decreased

$1,185 million as compared tothe same period of 2015 primarily reflecting assetimpairment and plant exit costs recognized in the second quarter ot 2016 consisting of:. Non-cash impairment charge of

$800 million (pre-tax) associated with goodwill at CES,Non-cash impairment charges of $647 million (pretax) associated with the announced plan to exit operations by 2020 ot Units 1-4 of the W.H. Sammis generation station (720 MW) and the Bay Shore Unit 1 generating station (136 MW), Coal contract settlement and termination costs of $58 million (pre-tax), and Valuation allowances against state and local NOL carryforwards of $159 million.During the first nine months of 2016, FirstEnergy's revenues decreased

$298 million as compared to the same period in 2015,resulting from a $564 million decrease at CES, partially offset by an increase of $69 million at Regulated Transmisshn.. The decrease in revenue at CES resulted from a 13 million MWH decline in contract sale6 as the segment cortinuesto align its sales to its generation. The decline in contract sales volume was partially olfset by higher wholesale salss, increased capacity revenue associated with capacity auction prices, and higher net gains on linancially settl*d contrac{s.. The increase in revenue at Regulated Transmission primarily reflecled recovery of incremental operating expenses am higher rate base at ATSI and TrAlL, panially offset by adjustments associated with ATSI and TrAlUs annual rate liling for costs previously recovered as well as a lower ROE at ATSI under its FERc-approved comprehensive settlsmefi related to the implementation of a foMardlooking rate.Operating expenses increased

$1,096 million during the first nine months of 2016 as compared to2015, mainly reflecting an increaseat CES of

$830 million, resulting primarily ftom the asset impairment and plant exit costs descdbed above, and an inclease atRegulated Transmission of

$62 million. Changes in certain operating expenses include the tollowing:. Fuelexpense decreased

$109 million mainly resulting from lowergeneralion at CES associated with oulages and economicdispatch of fossil units reflecting low wholesale spot market energy prices, as well as lower unit prices on lossil fuel contracts.. Purchased power decreased

$319 million mainly due to lorver volumes at CES and Regulated Distribution and lowercapacity e)pense at CES.Other income (e4ense) increased

$58 million, primarily from lower OTTI on NDT investments. Changes in FirstEnergys efiective taxrate forthe nine months ended September 30, 2016 compared to the same period in 2015, primarily related to the second quarter of2016 impairment of

$8OO million of goodwill, of which $433 million is non-deductible for tax purposes.

Additionally, $159 million ofvaluation allowances were recorded against state and local NOL carryforwards in the second quarter of 2016 that managementbelieves, more likely than not, will not be realized based primarily on projected taxable income refectilE updates to FirstEneagys annual long-term fundamental pricing model for energy and capacity, as w*ll as certain statutory limitations on the utilization of stateand local NOL carryfoMards.

61 RESULTS OF OPEFATIONSThe financial resulb discussed below include revenues and expenses from transaclions among FirstEnergy's segments.

A reconciliation of segment financial results is provided in Note 14, Segment Informalion, ot the Combined Notes to Consolidated Financial StatemenF.

Certain prior year amounts have been reclassifiod to contorm to the current year presentiation.Summary ol Besults of Ope/,a,tlons - Thhtt Atarw 2016 Compared wfth mh.t Quaftr m15Financial results for FirstEnergy's business segments in the third quarter of 2016 and 2015 were as follows: Third Quarter 2016 Financial ResultsRegulated RegulatedDistribution Transmission Competitive Corporate/Other Energy and Reconciling

_FirstEnergy ServiCes Adiustments Consolidated Revenues: External Electric Other lnternalTotal RevenuesOperating Expenses:

Fuel Purchased powerOther operating expensesProvision for depreciation Amortization of regulatory assets, net Generaltaxes lmpairment of assets Total Operating Expenses Operating Income Other Income (Expense)

Investment income

Interest expense Capitalized f inancing costs Total Other Expenselncome Before Income Taxes Income taxesNet Income 2,649 53 285 $(ln millions)959 39 117 (46)(22)(117)3,847 70 2,702 1,115 (185)3,917 156 902 615 171 98 190 8 30 46 45 37 294 194 367 79 t1ul (75)16 450 979 953 311 98 265 2,132't28 (168)3,056 570 861 (17)157 (60)(16)13 (13s)6 (43)I 23 (48)I (8)(56)4 28 (286)28 (120)450 167 (34)(230)123 45 135 49 (77)(10)631 251 283 $78$86$(67) $380 62 Third Quarter 2015 Financial Results Competitive Regulated Regulated EnergyDistribution Transmission Services Corporate/Other and Reconciling FirstEnergy Adjustments Gonsolidated Revenues: External Electric Other InternalTotal RevenuesOperating Expenses:

Fuel Purchased powerOther operating expenses Provision for depreciation Amortization of regulatory assets, net Generaltaxes lmpairment of assets Total Operating Expenses Operating Income Other Income (Expense):lnvestment income (loss)Interest expenseCapitalized f inancing costs TotalOther Expense lncome Before Income Taxes Income taxesNet Income 140 980 534 42 174 41 110 172 23 I 2,118 106 2,571 53 248 $(ln millions)1,276 51 141 2,624 248 1,468 (217)(41)

(35)(141)4,054 69 4,123 482 1,209 842 328 110 236 8 3,215 6 342 370 336 98 35 (141)(70)15 1,181 (1e0)506 142 (27)908 I (14e)6 (135)371 137 (40)I (31)(58)(63)(287)(1e)(48)9 (17)

(48)2 (28)(285)26 111 41 229 84 (e0)

(36)621 226 234 $70$(54) $395 145 $63 Changes Between Third Quarter 2016 and Third Quarter 2015 Financial Results Regulated Distribution Revenues: External Electric Other lnternalTotal Revenues Operating Expenses: Fuel Purchased powerOther operating expensesProvision for depreciation Amortization of regulatory assets, net Generaltaxes lmpairment of assets Total Operating Expenses Operating IncomeOther Income (Expense)

lnvestment income Interest expenseCapitalized f inancing costsTotalOther ExpenseIncome Before lncome Taxes lncome taxesNet lncome ComPetitive Regulated EnergyTransmission Services Corporate/Other and Reconciling FirstEnergy Adjustments Consolidated 78$37$(5)13 24 (207)1 (ln millions)(317)(12)

(24',)(206)32 37 78 (353)16 (78)81 (3)(12)18 (8)2 4 4 14 (48)(176)31 ,:,:, 24 (5)1 (32)(230)111 (17)('t2)29 (8)14 (217)(15e)(47)10 15 (136)42 5 10 79 30 (3)/e\\v,, 9 (8)2 56 (1 )2 15 12 4 (e4)(3s)13 26 10 25 4e$8$(5e) $(13) $(15)64 Regulabd Dlstrlbutlon - Thhd Quarter 2016 Comparcd with Thlttt Ouarter 2015Regulated Distribution's net income increased

$49 million in the third quarter oI 2016 as compared to the same period ot 2015,reflecting higher revenues associated with cooling degree days that were 28% above 2015, partially ofisel by higher operating and maintenance costs and increased retirement benefit costs.Revenues -The $78 million increase in toial revenues resulted from the following sources:

For the Three Months Ended September 30 Increase Revenues by Type of Service 2016 2015 (Decrease)(ln millions)1,390 $ 1,245 $145 Distribution servicesGeneration sales:

Retail Wholesale Total generation sales Other Total Revenues 1,117 142 1,',182 144 (65)(2)1,259 53 1,326 53 (67)2,702 $2,624 $Distribution services revenues increased

$145 million primarily resulting lrom higher MWH deliveries, described bdow and a rate increase associated with the Ohio Companies'rider OCR. Additionally, distribution service revenues increased related to higher rates associated with the remvery of deferred costs, including Ohio Companies'NMB transmission rider revenues, and a surchargeincrease in West Virginia associated with the recovery otvegetation management deferred program costs, effective January'1,20'16.

Distribution deliveries by customer class are summarized in the following iable:

For the Three MonthsEnded September 30 lncreaseElectric Distribution MWH Deliveries 2016 2015 (Decrease)(ln thousands) 78 Residential Commercial Industrial OtherTotal Electric Distribution MWH Deliveries 16,138 12,005 13,023 144 14,305 11,463 12,721 146 12.8 "/" 4.7 "/" 2.4 V" (1.4)%41,310 38,635 6.9 %Higher distribution deliveries to residential and commercialcustomers primarily reflect increased wsather-related usage resulting fromcooling degree days that were 28% above 2015, and 46% above normal. Deliveries to industrial customers increased relaled tohigher shale, coal and steel customer usage.

65 The following table summarizes the price and volume factors contributing to the $67 million decrease in generalion revenuesforlhe third quarter of 2016 compared to the same period of 2015: Increase Source of Change in Generation Revenues (Decrease)(ln millions)16 (81)(65)(67)The decrease in reiail generation sales primarily resulted from lower default service auction prices in Ohio and Pennsylvania. The increase in retail generalion volumes was primarily due to weather-related volume, as described above, partially offset by increasedcustomer shopping in Ohio and New Jersey. Total generation provided by alternative suppliers as a percentage of total iifwHdeliveries increased to 85% from 81% for the Ohio Companies and lo 48"/" fiom 47"/. forJCP&L.The decrease in wholesale generation revenues of $2 million in the third quarter of 2016, as compared to the same period in 2015,reflects lower capacity revenues partially oltset by higher wholesale sales.

The difference bstween currenl wholesale generation revenues and certain energy costs incurred are deferred for tuture recovery or refund, with no matelial impact to earnings.Openting Expenses

-Total operating epenses increased

$14 million primarily due to the following:

Fuel expense increased

$16 million in the third quarter of 2016, as compared to the same period in 2015, primarily related to higher generation.

Purchased power costs were $78 million lower in the third quarter of 2016, as compared to the same period in 2015, primarily due to decreased unit cost reflecting lower default service auction prices in Ohio and Pennsylvania.

Source of Change in Purchased Power lncrease(Decr ease)(ln millions)$ (85)10 (75)(14)(e)(23)Retail: Effect of increase in sales volumes Change in prices Wholesale:Effect of increase in sales volumes Change in prices Capacity RevenueDecrease in Generation Revenues 10 (1)(11)(2\Purchases from non-affiliates:Change due to decreased unit costs Change due to increased volumes Purchases from affiliates:Change due to decreased unit costs Change due to increased volumes Capacity Expense Amortization of deferred costs Decrease in Purchased Power Costs (7)27 66 (78)

. Other operating expenses increased

$81 million primarily due to:. Higher operating and maintenance expense of

$37 million including higher storm restoration costs of

$32 million, which are deferred for future re@very resulting in no material impact on current period earnings.. Higher transmission expenses of$24 million primarily due to an increase in network transmission epenses at theOhio Companies. The difference between currenl revenues and transmission costs incurred are debrred for future recovery or refund, resulting in no material impact on current period earnings.. Higher retirement benefit cosls ol

$12 million.. Net amorlization of regulatory assets decreased

$12 million primarily due to higher deferral of storm restoration costs, partially offset by increased recovery otvegetation management program costs in West Virginia and increased lecovery of network transmission expenses in Ohio.. General taxes increased

$18 million primarily due to higher property taxes and higher revenue-related taxes in Ohio.Othet ExDense

-Other expenses decreased

$15 million primarily due to lower interest expense associated with various debt redemptions atJCP&L,OE, and MP and lower OTTI on NDT investments.lncome Taxes

-Regulated Distrjbution's effective tax rate was 37.1% and 36.9%

for the quarter ended S'*ptember 30, 2016 and 2015, respectively.Regulatect T?,nsml9F,lon - Thid o{raner m16 Compared wfth Thhct Ouaner m15Nel income increased

$8 million in the third quarter of 2016 compared to the same period of 2015 reflecting higher transmission revenues, as described below.

Revenues -Toial revenues increased

$37 million principally due to recovery of incremental operating expenses and a higher rate base at ATSI and TrAlL, partially otfset by a lower ROE at ATSI under its FERc-approved comprehensive settlement related to lhe implementalionol a forwardiooking rate.Revenues by transmission asset owner are shown in the foliowing table:For the Thl*e Months Endod Soptember 30 Revenues by Transmission Asset Owner 2016 2015 Increase ATSI TrAIL PATH Utilities Total Revenues (ln millions)$ 139$ 110$ 2s 67607 33 76751$ 285 $ 248 $ 37Operating Expenses

-Totaloperating epenses increased

$22 million principally dueto higher pmperty taxes, depreciation, and other operating expenses atATSI, which are recovered through ATSI'S formula rate.Other Expense

-Total other expense increased

$3 million in the third quarter of 2016 as compared to the same period of 2015 primarily due toincreased inlerest expense resulting from debt issuances of $150 million at ATSI in the fourth quarter of 2015, the proceeds otwhich, in part, paid otf shorl-term borrowings.

ln@me Taxes -Regulated Transmission's etfective tax rate was 36.6%and 36.9%lorthe quarterended September 30,2016 and 2015, respectively.

67 CES - Thhct Ouarl3'r m16 Compared wlth Thhd QuatlF,r m15 Operating results decreased

$59 million in the third quarter oI20l6, compared to the same period oI 2015, primarily resulting tromlower contract sales volumes,lower capacity revenues from lower capacity auction prices,lo\,ver mark-to-market gains on commodity contract positions, and a termination charge associated with a FES customer contract, partially offset by higher wholesale sales volumes and lower fuel and purchased power, Bevenues -Total revenues decreased

$353 million in the thkd quarter of 2016, compared to the same period of 2015, primarily due to lowercapacity revenues from lower capacity auction prices, lower conlract sales volumes and lower unit prices. Revenues were alsoimpacted by higherwholesale sales volumes, partially ofiset by lower net gains on financially settled contracts, as further described below.The change in tolal revenues resulted from lhe following sources: For the Three MonthsEnded September 30 Revenues by Type of Service 2016 2015 lncrease (Decrease)(ln millions)Contract Sales: Direct Govern mental Agg regationMass Market POLR Structured Sales Total Contract Sales Wholesale Transmission OtherTotal Revenues 207 $235 47 296 $296 62 (8e)(61)(15)24 (76)165 141 94 170 748 311 17 39 1,1'15 $For the Three Months Ended September 30 (217)(118)(6)(12)1,468 $(353)965 429 23 51 MWH Sales by Channel 2016 2015 Increase (Decrease)

Contract Sales: DirectGovernmental Agg regation Mass Market POLR Structured Sales Total Contract Sales Wholesale Total MWH Sales 3,913 4,238 673 2,893 2,437 14,154 4,447 (ln thousands) 5,541 4,226 906 2,169 3,893 16,734 3,156 (2e.4)%0.3 %(25.7)%33.4 %(37.4)%(15.4)%40.9 %18,601 19,890 (6.5)%68 The following table summarizes the price and volume factors contributing to changes in revenues:

Source of Change in Revenues Increase (Decrease)

MWH Sales Channel:

Sales VolumesGain on Settled Prices Contracts Capacity Revenue Total (ln millions)(2) $ $Direct Governmental Aggregation Mass Market POLR Structured Sales Wholesale (87) $1 (16)47 (64)38 (62)1 (23)(12)3 (8e)(61)

(15)24 (76)(e)(150) (118)

Lower sales volumes in Direct and Mass Market channels primarily reflects the continuation oI CES'strategy lo more efiectivelyhedge its generation. The Direct, GovernmentalAggregation and Mass Market customer base was 1.4 million as ot September 30, 2016, compared to 1.7 million as of September 30,2015. Although unit pricing was lower year-over-year in the Governmental Aggregation channel, the decrease was primarily attribulable to lower capacity e)pense as discussed bdow which is a mmponent otthe retail price.The increase in POLR sales of $24 million was due to higher\olumes, parlially offset by lower rates associated with POLR auctions.

Structured Sales decreased

$76 million primarily duetothe impact of lower market prices and lower structured transaction volumes.Wholesale revenues decreased

$1 1 I million, primarily due to a decrease in capacity revenue lrom capacity auctions and lower gainson financially settled contracts, partially offset by an increase in short-term (net hourly position) transactions at highel realized pric*s.Although wholesale short-term transactions and prices increased year-over-yeaa, low average spol marlGt energy plices reduced the economic dispatch of fossil generating units, limiting additional wholesale sales.Openting Expenses

-Toial operating expenses decreased

$217 million in the third quarter of 2016 due to the following:. Fuelcosts decreased

$48 million, primarily due to lower generation associated with outages and economicdispabh ofbssil units resulting from lowwholesale spot maket energy prices, as described above, as well as lower unit prices on fossilfuel conlracts.. Purchased power cosF decreased

$176 million due to lower capacity e)eense

($137 million), lower prices ($27 million) andlower volumes

($12 million).

Lower volumes primarily resulted from lower contract sales as discussed above, partially ofbetby economic purchases, resulting from the low wholesale spot market price environment. The decrease in capacity expense,which is a mmponent of CES'retail price, was primarily the result ol lower contract sales and lower capacity ratesassociated with CES' retail sales obligation. Lower prices rellect lower realized prices on economic purchases.. Depreciation expense decreased

$19 million, primarily as a result ot an out-of-period adjustment to reduce the deprecialionof a hydroelectric generating station.. Transmission expenses decreased

$12 million due to lower congestion and market-based ancillarycosts, primarily resulting from lower conlract sales.. Other operating expenses increased

$* million, primarily due to lower mark-to-market gains on commodity contract positions of $41 million, higher benefit costs and a

$32 million charge associated with the termination of a FES customer contract, partially olfset by lower lease expense as a result ot the expiration of a nuclear saleleaseback agreement andlower retail-related costs.Other Expense

-Total other expense decreased

$42 million in the third quarter of 2016, as compared to the same period o12015, primarily due tolower OTTI on NDT investments.

69 lncone Taxes

-CES' efiective tax rate was 36.3% and 36.7%

for the third quaner of 2016 and 2015, respectively.Cotp0,lzte /

Other - Thltd Quarl*/r m16 Com,*,red wfth Thhtl Quatl*,r N15Financial results trom the Corporate/Other operating segment and reconciling items, includirE interest expense on hoHing companydebt, corporate supporl services revenues and expenses and income taxes, resulted in a

$13 million decrease in earnings in thethird quarter of 2016, compared to the same period of 2015, primarily associated with a higher consolidated effective lax rate.70 Summary ol Results of Operations - First Nine Months of 2016 Comparcd with First Nine Months of 2015 Financial results for FirstEnergy's business segments in the first nine months of 2016 and 2015 were as follows:First Nine Months 2016 Financial Results Regulated Distribution ComPetitive Regulated EnergyTransmission Services Corporate/Other and Reconciling FirstEnergy Adjustments Consolidated Revenues: External Electric Other InternalTotal Revenues Operating Expenses: Fuel Purchased powerOther operating expensesProvision for depreciation Amortization of regulatory assets, net Generaltaxes lmpairment of assets Total Operating Expenses Operating Income (Loss)Other Income (Expense):Investment income Interest expenseCapitalized f inancing costs Total Other Expense Income (Loss) Before Income Taxes (Benefits) lncome taxes (benefits)Net Income (Loss)7,238 $185 824 $(ln millions)3,023 135 377 (135)(83)(377)10,950 237 7,423 436 2,549 1,843 510 218 5456,1 01 1,322 824 3,535 (5e5)11,187 118 132 4 114 833 820 1,120 284 98'i.,447 4,602 tsnl (246)48 1,269 2,992 2,835 974 222 786 1,447 29 368 (546)10,525 456 (1,067)56 (143)29 (4e)37 (431)15 (37e)943 349 (128)25 (103)353 130 (18)(161)10 75 (863)79 (58)(16e)(70e)(1,125)(e6)(218)(4e)(47)334 594 $223 $(1,029) $(16e) $(381)71 First Nine Months 2015 Financial Results Regulated Distribution Gompetitive Regulated EnergyTransmission Services Corporate/Other and Reconciling FirstEnergY Adjustments Consolidated Revenues: External Electric Other Internal Total RevenuesOperating Expenses:

Fuel Purchased powerOther operating expensesProvision for depreciation Amortization of regulatory assets, net Generaltaxes lmpairment of assets Total Operating ExpensesOperating IncomeOther Income (Expense):

Investment income (loss)Interest expenseCapitalized financing costs TotalOther ExpenseIncome Before Income TaxesIncome taxesNet Income (11e)36 (385)(83)7,277 148 755 $(ln millions)3,381't55 563 (12e)(102)(563)11,284 201 7,425 755 4,099 972 1,113 1,266 293 112 16 (7e4)11,485 406 2,761 1,669 516 196 536 8 112 116 5 73 (563)(248)44 1,378 3,311 2,799 969 20'l 747 24 26 6,092 306 3,772 327 (741)9,429 1,333 (53)449 2,056 33 (43e)21 (7)(144)29 (122\205 76 (40)(144)7 (14)(846)93 (177)(767)948 350 ss8 $366 135 231 $(230)(76)1,289 485 129 $(154) $804 72 Changes Between First Nine Months 2016 andFirst Nine Months 2015 Financial Results Regulated Distribution ComPetitiveRegulated EnergyTransmission Services Corporate/Other and Reconciling FirstEnergy Adjustments Consolidated Revenues: External Electric Other InternalTotal RevenuesOperating Expenses:

Fuel Purchased powerOther operating expenses Provision for depreciation Amortization of regulatory assets, net Generaltaxes lmpairment of assets Total Operating ExpensesOperating Income (Loss)Other Income (Expense)

Investment income lnterest expenseCapitalized financing costsTotalOther Expense Income (Loss) Before Income Taxes (Benefits)

Income taxes (benefits)Net Income (Loss)(3e)37 (ln millions)$ 6e $ (358)(20)(6)19 186 (334)36 (2) 6e (564)199 (2e8)30 (212)174 (6)22 I (8)6 16 (1)41 (13e)

(2e3)

(146)3 (14)1,431 186 2 4 3 (10e)(31e)36 5 21 39 1,423 195 62 1,096 (1,394)(1,330)(172)(1,394)4 I 63 1 (e)22 (17)3 89 (17)

(14)(6)6 (20) 64 58 (5)(1)(13)(5)12 27 (1,336)(151)(1,185)73 Regula'*d Dtsttibution - Flrst Nlne Months ol m16 Comryrd tflnh Fi'r,t NIne hnthc ol m15Regulaled Distdbution's net income decreased

$4 million in the first nine months of 2016 as compared to lhe same period ot 2015,retlecting increasing retirement benefil costs and lower distribution deliveries, partially ofiset by the impact ot net rate increasesimplemefied in 2015 as a result of approved rate cases at certain operating companies, as further described below Additionally, theOhio Companies rocognized

$51 million in regulatory charges in the second quarter of 2016 resulting ftom the PUCO'S March 31Opinion and Order adopting and approving, with modifications, the Ohio Companies'ESP lV Revenues -The $2 million decrease in total revenues resulted from the following sour@s: For the Nine MonthsEnded September 30 Increase Revenues by Type ol Service 2016 2015 (Deqease)(ln millions)Distribution servicesGeneration sales:

Retail Wholesale Totalgeneration sales OtherTotal Revenues

$ 3,681 $ 3,502 179 3,173 384 3,331 444 (158)(60)3,557 185 3,775 148 (218)37$ 7,423 $ 7,425 $(2)Distribution services revenues increased

$179 million primarily resulting from appoved base distlibution rate increases in Pennsylvania, effective May 3, 2015, and MP and PE in West Virginia, effective February 25, 2015, partially ofbet by a distributionrate decrease atJCP&L, including the recovery of 2011 and 2012 storm costs, effective April 1, 2015. Partially ofisetting this net rateincrease was a decline in lvlwH deliveries, pdmarily resulting from lower average customer usage, as desclibed below. Additionally,distdbution revenues were impacted by higher rates associated with the recovery of deterred costs. Distribution deliveries bycustomer class are summarized in lhe tollowing table:

For the Nine MonthsEnded September 30 Electric Distribution MWH Deliveries 2016 2015 (Decrease)(ln thousands)

Residential Commercial lndustrial Other Total Electric Distribution MWH Deliveries 42,130 32,913 37,746 437 42,706 33,006 38,149 438 (1.3)%(0.3)%(1.1)%

(0.2)%113,226 114,299 (0.e)%Lower distribution deliveries to residential and commercial customers retlect declining aveftrge customer usage associated with moreenergy efficient products and seMces. Additionally, wealher-related distribution deliveries to residentialand commercial cuslome6were flat resulting from heating degree days that were 17olo below 2015, and 97" below normal and cooling degree days that were 16% above 2015. and 36% above normal. Year-to-date deliveries to industrial customers have declined as the increase frcm shalecustomer usage was more than offset by a decrease from steel customer usage.

74 The following table summarizes the price and volume factors contributing to the

$218 million decrease in generalion revenues br thefirst nine months ot 2016 comoared to the same Deriod of 2015:

IncreaseSource of Change in Generation Revenues (Decrease)(ln millions)Retail: Effect of decrease in sales volumes Change in prices Wholesale:

Effect of increase in sales volumes Change in prices Capacity RevenueDecrease in Generation Revenues (1e0)32 (158)43 (101)(z',)(60)(218)The decrease in retail generation sales volumeswas primarily due to increased customer shopping in Ohio, Pennsylvania, and NewJersey and industrial usage in West Virginia, as described above. Totalgeneration provided by alternative suppliers as a percentageof total MWH deliveries increased to 82% from 80%forthe Ohio Companies, to 670lo from 65%forthe Pennsylvania Companiesandto 5l% from 49olo lor JCP&I. The increase in retail generation prices primarily resulted an ENEC rate increase in West Virginia,etfective January 1, 2016, partially offset by lower default service auction prices in Ohio and Pennsylvania.

Wholesale generation revenues decreased

$60 million in the lirst nine months of 2016, as compared to the same period oI 2015, primarily due to lower spot market energy prices, partially offset by higher wholesale sales. The difference between currentwholesale generation revenues and certain energy costs incurred are deterred torfuture recovery or refund, with no materialimpacl to earnings.Other revenues increased

$37 million primarily related to a $29 million gain on the sale of oil and gas rights at WPOperating Expenses

-Total operating expenses increased

$9 million primarily due to the tollowing:. Fuel expense increased

$30 million in the first nine months of 2016, as compared to the same period of 2015, primarily related to higher generation.. Purchased power costs decreased

$212 million during the first nine months of 2016, as compared to the same period of 20'15 primarily due to decreased volumes resulting lrom increased customer shopping, as described above, aswellas lower unit costs retlecting lower default service auction prices in Ohio and PennsylvaniaSource of Change in Purchased Power Increase (Decrease)(ln millions)Purchases from non-affiliates :Change due to decreased unit costsChange due to volumesPurchases from affiliates:Change due to increased unit costsChange due to volumes Capacity Expense Amortization of deferred costsDecrease in Purchased Power Costs (83)16 (67)6 (1e1)(185)2 38 75 (212)

. OtheI operating expenses increasd

$174 million primarily due to:. An increase ol $51 million resulting from the recognition of economic development and enelgy efficiencyobligations in accordance with the PUCO'S March 31 Opinion and Oder adopting and approving, with modifications, the Ohio ComDanies' ESP lV.. Higher operating and maintenance expense of

$42 million, including increased storm restoration costs of $39million, which are deferred for future recovery, resulting in no material impact on current period earnings.. Higher retirement b*nefit costs ot

$37 million.. Higher transmission expensesof

$36 million primarily related to an increase in network transmission expenses at the Ohio Companies, partially otfset by lower congestion expenses at MP. The difference between current revenues and costs incurred are deferred for future re@very or refund, resulting in no material impacl on current period earnings.. Net amortization of regulatory assets increased

$22 million primarily due to:. Recovery ofstorm costs in NewJersey, Pennsylvania, andwest Virginia etlective with the implementation of new rates as discussed above

($35 million),. Recovery of West Virginia vegetation management program costs ($34 million), partially offset by. Higher deferral of storm restoration costs ($39 million), and. Higher deferralof Ohio network transmission expenses

($10 million).ln@me Taxes -Regulated Distribution's effective tax rate was 37.0% for the tirst nine months of 2016 and 2015.negulal*d T'*nsmlsslon - Flrat Nlne Months o, m16 Con parcd wlth Flrst Nln* Months ot m15Net income decreased

$8 million in the first nine months of 2016, compared to the same period of 2015, primarily resulting fromadjustments associated with ATSI and TrAIL's annual rate filing for costs previously re@vered, a lower return on equity at ATSI, and lower capitalized financing costs, partially offset by higher rate base.

Revenues -Total revenues increased

$69 million principally due to recovery of incrementaloperating epenses and a higher rate base at ATSIand TrAlL, partially otfset by adjustments associated with ATSI's and TrAIL's annualrate filing for costs previously recovered as wellas a lower ROE at ATSI under its FERo-approved comprehensive settlement related to the implementation of a toru/ard-looking rate.Revenues by transmission assel owner are shown in the lollowing table:

For the Nine Months Ended September 30 Increase Revenues by Transmission Asset Owner 2016 2015 (Decrease)(ln millions)$ 333$ATSI TrAIL PATH UtilitiesTotal Revenues 401 187 I 227 186 10 226 68 1 (1)1 824 $755 $69 Opercting Expenses -Totaloperating expenses increased

$62 million principally due to higher property taxes and depreciation expense atATSl, which are recovered through ATSI's formula rate.

Other Expense -Other expense increased

$20 million in the first nine months of 2016 compared to the same period ot 2015 primarily due to lower capitalized financing costs resulting trom lower construction work in progress balances at ATSI as well as increased interest expenseresulting tmm debt issuances of$150 million at ATSI in the fourth quarter of 2015, the proceeds ofwhich, in part, paid ofi short-term borrowings.lncone Taxes

-Begulated Transmission's effective tax rate was 36.8% and 36.9%

tor the first nine months of 2016 and 2015, respectively.

76 CES - Fhst Nine Months ot 2016 Compa,Ed wlth Hrst Nlne Months ot 2015Operating results decroased

$ 1 ,158 million in the first nine months of 2016, compared to the same period ot 2015, primarily resultingIrom charges associated with impairments of goodwill, Units 1-4 of the W. H. Sammis generating station and lhe Bay Shor* Unit 1 generating station, as discussed above, termination and settlement costs on coal contracts and lower mark-to-market gains oncommodity contract positions.

In addition lo these items, operating results were impacted by higher capacity revenues, lower tuelcosts and lower purchased power, partially offset by lower sales volumes and a termination charge associated with a FES customer contract.Revenues -Total revenues decreased

$564 million in the first nine months o12016, compared to the same period of 2015, primalily due to lower sales volumes, partially offset by higher capacity revenues and higher net gains on financially settled contracts, as fuItherdescribed below.The decrease in total revenues resulted from the following sources: Revenues by Type of Service For the Nine MonthsEnded September 30 lncrease 2015 (Decrease) ftn mittiorrsl 2016 Contract Sales: Direct Govern m ental Agg regationMass Market POLRStructured Sales Total Contract Sales Wholesale Transmission OtherTotal Revenues MWH Sales by Channel

$ 610 666 133 447 371 1,014 $802 222 585 429 (404)(136)(8e)(138)(58)(825)341 (60)(20)2,227 1,117 56 135 3,052 776 116 155$ 3,535$ 4,099 $(s64)For the Nine MonthsEnded September 30 Increase (Decrease) 2016 2015Contract Sales:

Direct Governmental Agg regationMass Market POLRStructured Sales Total Contract Sales WholesaleTotal MWH Sales (ln thousands) 11 ,391 10,798 1,912 7,526 9,175 18,860 12,278 3,246 9,910 9,790 54,084 4,023 (3e.6)%(12.1)o/"

(41.1)/"

(24.1)/" (6.3)%40,802 9,938 (24.6)%147.0 %50,740 58,107 (12.7)/" 77 The following table summarizes the price and volume factors contributing to changes in revenues: Source of Change in Revenues Increase (Decrease)

MWH Sales Channel:

SalesVolumesPricesGain on Settled Capacity Gontracts Revenue Total Direct Governmental Agg regation Mass Market POLR Structured Sales Wholesale (401) $(e7)(e1)(140)(27)175 (ln millions)(3) $ $(3e)2 2 (31)(16) 113 (404)

(136)(8e)(138)(58)341 69 Lower sales volumes in Direct, GovernmentalAggregation and Mass Market channels primarily reflects the continuation of CES'strategy to more effectively hedge its generation. The Direct, GovernmenialAggregation and Mass Market customer base lvas 1.4million as of September 30, 2016, compared to 1.7 million as ol September 30, 2015. Although unit pricing was lower year-over-yearin the Governmental Aggregation channel, the decrease was primarily attributable to lower capacity expense as discussed belouwhich is a component of the retail price.The decrease in POLR sales ot $138 million was pdmarily due to lower volumes. Slructured Sales decreased

$58 million, primarilydue to the impact of lower market prices and lower structured transaction volumes.Wholesale revenues increased

$341 million, primarily dueto an increase in capacity revenue from capacity auctions, an increase in shon-term (nethourly position) transactionsand higher netgains on financially settled contracts, partially olfset by lower spot market energy prices. Although wholesale short-term transactions increased year-over-year, low a\ietage spot mad(et energy prices reducedthe economic dispatch of tossil generating units, limiting additional wholesale sales.Transmission revenue decreased

$60 million, primarity due to lower congestion revenue associated with less volatile marftet conditions.

Other revenue decreased

$20 million, primadlydueto the absence of a pr+tax gain on the sale of pmperty to a regulated affiliate inthe second quarter ot 2015 and lower lease revenues lrom the expiration of a nuclear sal+leaseback agreement.

Operufng E enses -Total operating expenses increased

$830 million in the lirst nine months of 2016, compared to tho same period of 2015, due to the following:

Fuel costs decreased

$139 million, primarily due to lower generation associated with outages and economic dispatch of fossil units resulting from lowwholesale spot market energy prices, as described above, aswellas lower unit prices on fossil fuelcontracts. Additionally, fuel costs were impacted by higher settlement and termination costs on coal contracts.

Purchased power costs decreased

$293 million, primarily due to lower volumes

($2OO million) and lower capacity expenses ($t t Z million), partially offset by higher losses on financial settled contracts from lower wholesale spot market prices ($25 million). Lower volumes primarily resulted from lower contract sales as discussed above, partially offset by economic purchases, resulting from the low wholesale spot market price environment. The decrease in capacity expense, which is a component of CES' retail price, was primarily the result of lower contract sales and lower capacity rates associated withCES' retail sales obligations.

Fossil operating costs increased

$18 million, primarily due to increased outage costs and higher employee benefit costs.Nuclear operating costs decreased

$31 million, primarily as a result of lower refueling outage costs, partially offset by higheremployee benefit costs. There was one refueling outage during the first nine months of 2016 as compared to two refueling outages during the same period of 2015.Retirement benefit costs increased

$24 million.78

. Transmission expenses decreased

$162 million, primarily due to lower congestion and markel-based ancillary costsassociated with less volatile market conditions as comDared to the first nine months of 2015, as well as lower load requirements.. Otheroperating expenses increased

$5 million, primarilydueto lower mark-to-market gains on commodily mntract positions of $54 million and a $32 million charge associated with the termination ol a FES customer contract, partially ofisst by lower lease expense as a result ot the expiration of a nuclear saleleaseback agreement and lower retail-related costs.. Depreciation expense decreased

$9 million, primarily as a result of an out-of-period adjustmentto reduce the deprecialion ota hydroelectric generating station, partially offset by a higher asset base.. General taxes decreased

$14 million, primarily due to lower gross Fceipts taxes associated with lower retail sales volumes.. lmpairment of assets increased

$1,431 million primarily due to an

$800 million impairment of goodwill and a decision to exit operations of Units I -4 ofthe W. H. Sammis generating station by iitay 31, 2020 and the Bay Shore Unit 1 generating stationby October 1, 2020.

Other Expense -Total other eryense decreased

$64 million in the first nine months of 2016, compared to the same period of 2015, primarily due to lower OTTI on NDT investmenls.ln@me Tax*s (BeneliB)

-CES'effective tax rate was 8.5% and 37.1%forlhe first nine months of 2016 and 2015, respectively. The decrease in the efieclive taxrate is primarily due to valuation allowances of

$159 million recorded against state and local NOL carMon ,ards that management believes, more likelythan not, will not be realized as discussed above aswellas the impairment ofgoodwill, ofwhich, $433 million is non-deductible for tax Durooses.Corpo',te /

Other - Hrct NIne ttonths of ml6 ComparEd wnh H'3,t Nine tionths ot ml,Financial results from the Corporate/Other operating segment and reconciling items resulted in a $15 million decrease in net income in the tirst nine months of 2016 compared to the same period of 2015. Increased taxes at lhe Coporate/Other operating segmentresulted from an increased consolidated tax rate and the impact ot estimated annual permanent hems on lower pre-tax income for the penoo.Ragulatory Aslsets Regulatory assets represent incurred costs that have been deferred because oI their probable future recovery from customersthrough 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 regulatoryassets and liabilities based on federal and state jurisdictions.

The following table provides inlormaton about lhe composition of net regulatory assets as of September 30, 2016 and December 31, 2015, and the changes dudng the nine months ended September 30, 2016: Regulatory Assets (Liabilities) by Source September 30, December 31, Increase 2016 2015 (Decrease)

Regulatory transition costs Customer receivables for future income taxes Nuclear decommissioning and spent fuel disposal costsAsset removal costs Deferred transmission costs Deferred generation costs Deferred distribution costs Contract valuationsStorm-related costs OtherNet Regulatory Assets included on the Gonsolidated Balance Sheets (ln millions)123 $ 185 $355 (272)(372)115 243 335 186 403 170 427 (316)

(470)123 247 305 166 375 108 (62)72 (44)(e8)8 4 (30)(20)(28)

(62)79 1,088 $1,348 $(260)

Regulatory assets that do not earn acurrent return totaled approximately

$148 million as ot September 30,2016and December 31,2015, respectively, primarily related to storm damage costs.

As of September 30, 2016 and December 31 , 2015, FirstEnergy had approximately

$142 million and

$116 million, respectively, of net regulatory liabilities that are primarily related to asset removal costs. Net regulatory liabilities are classified wilhin Other noncurrent liabilities on the Consolidated Balance Sheets.

CAPITAL RESOURCES AND LIOUIDITY 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 significanl resources to fund operating e&enses, construction expendilures,scheduled debt maturities and interest payments, dividend payments, and contributions to its pension plan.

In addition lo internalsources to fund liquidity and capital requirements for 20'16 and beyond, FirstEnergy expects to rely on external sources ot funds.Short-term cash requirements notmet by cash provided from operations are generally satisfied through short-lerm borrowings. Long-term cash needs, including cash requirements to fund Regulated Transmission's capitalprogram, may be met through a combinationof an additional$500 million of equity in each year 2017 through 2019, subject to certain market conditions, and new long-tem debt.

FirstEnergy also expects to issue long-term debt at ceriain Utilities to, among otherthings, refinance short-term and maturing debt,subject to maket and other conditions. Furthermore, FES subsidiaries have debt maturities in 2017 and 2018 of

$130 million and

$515 million, respectively, which will need to be refinanced. The inability to refinance the 2017 debt maturities at FES could beaddressed through a combination ot cash on hand, additional capital expenditure reductions, asset sales, and/or borrowings underthe unregulated money pool. The inability to refinance 2018 debt maturities at FES could cause FES to take one or more of the lollowing actions: (i) restructuring of debt and otherfinancialobligations, (ii) additional borrowings underthe unregulated money pool, (iii) further asset sales or plant deactivations, and/or (iv) sesk protection under bankruptcy laws. In the event FES seeks such protection, FENOC may similarly be forced lo seek protection under bankruptcy laws.FirstEnergy expectsborrowing capacity under credit facilities will continue to be available to manage working capital requirements doru with continued access lo long-term capital markets. However, it material impaiments are recognized as FirstEnergy executes on its strategy to transition b a lully regulated utility resulting in a consolidated debt to total capitalization ratio, as defined under each ol the revolving credit facilities as discussed below in excess of 65%, then FE would be in default undervarious credit agreements related to the indebtedness of FE. Furthermore, adverse iudgments or a FES bankruplcyfiling could alsoresult in an event ot default. Although management expects to successfully resolve any FE defaults through waivers or other actionson acceptable lems and conditions, the failure to do so would have a material and adverse impact on FirstEnergy's fnancialcondition, and FirstEnergy cannot povide any assurance that it will be able to successfully resolve any such defaults on satisfactory Ierms.Through October 2016, FirstEnergy satislied its minimum required funding obligations to its qualified pension plan for the year with contributions ol $382 million ($85 million in October 2016), including

$138 million at FES. Depending on, among olherthings, marketconditions, FirstEnergy expects to make additionalcontributions to ib qualified pension plan in 2016 of up lo

$500 million of equity to address its funding obligations for future years.Planned capital expenditures for 2016 through 2018 by reportable segment are included below:

that with Capital Gapital CaPital Expenditures Expenditures Expenditures Forecast Forecast Forecast 2016 2017 2018 Reportable Segment Reg ulated DistributionRegulated Transmission Competitive Energy Services Corporate/Other Total$ 1,295 $1,000 540 90 (ln millions)1,325 $ 1,305 1,000 1,000 370 300 95 90$ 2,925 $2,790 $ 2,695 Additionally, planned capital e4cenditures in 2019 lor Regulated Distribution are approximately

$1.3 billion while planned capitaiexpenditures for Regulated Transmission are expected to be approximately

$800 million to

$1.2 billion annually in 2019 to 2021.80 Forecasted capital expenditures for 2017 by operating company are shown in the following table:201 7 Gapital Expenditures Forecast oE $ 14s 45 120 45 355 135 160 250 125 205 420 65 255 325 50 90 2,790Unsecured notes

FMBs Unsecured PCRBs(1)Collateralized lease obligation bonds Sinking fund requirements Other notes Penn cEr TE JCP&L ME PN MP PE WP ATSI TrAIL MAIT FES AE Supply Other Total FirstEnergy's strategy is to tocus on investments in its regulated operations.

The centerpiece of this strategy isthe Energizing theFut re investment plan, which began as a

$4.2 billion investment plan from 2014 through 2017 to upgrade and expand FirstEnergystransmission system with additional investments of $800 million to $1.2 billion annually from 2018 through 2021. This program is focused on projects that enhance system performance, physical security and add operating flexibility and capacity siarting with the ATSI system and moving east across FirstEnergy's service territory overtime. Through 2015, FirstEnergy's capiial 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 over$20 billion in transmission investment opportunities across the24,000 mile transmission system,making this a continuing platform for investment in the years beyond 2021.In alignment wilh FirstEnergy's strategy to invest in its Regulated Transmission and Regulated Distribution segments and therepositioning olthe CES segment, FirstEnergy is also focused on improving the balance sheet overtime consistentwith its business protile, maintaining investment grade metrics at its regulated businesses and FirstEnergy Corp. and maintaining strong lqudilyfor anoverall stable financial position. Specifically, at the regulated businesses, authority has been obiained tor various regulated distribution and transmission subsidiaries to issue and/or refinance debt.Any financing plans by FirstEnergy, including the issuance of equity, refinancing ot maturing debt and reductions in short-termborrowings, are subject to market conditions and other factors, such as the impact of the current enelgy and capacity markets and potential credit rating changes. 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. Any delay in the completion offinancing plans could require FE orFES or any oftheir subsidiaries to utilize short-term borrowing capacity, which would impact available liquidity. In addition, FirslEnergyexpects to continually evaluate any planned financings, which may result in changes lrom time to time.As ot September 30, 2016, FirstEnergy's net deticit 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 September 30,2016, included the following:

Currently Payable Long-Term Debt (ln millions)680 250 158 8 82 38 81$ 1,216 (r) These PCRBS are classilied as curenily payable long-term debt b*cause the appli:aHe interesl rate mode permib individual debt holders to put the respective debt back to the bsuer prior to malurity.Short-Tam BofiowingsFirstEnergy had

$2,975 million and $1,708 million ol short-term borrowings as of Septemb*r 30, 2016 and December 31, 2015, respectively.

The $1,267 million increase in short-term borowings during the first nine-months of2016was primarily dueto pensioncontributions, debt redemptions, of which some may be refinanced inthe future, and for generalbusiness purposes. FirstEnergy also had approximately

$,100 million of short-term investments at Seplember 30, 2016 that were redeemed in early oc1ober to pay dovvn a portion of the short-term borowings.

FirstEnergy's available liquidity as of November 1 , 201 6, was as follows: Borrower(s)

Type Maturity Available Gommitment Liquidity (ln millions)$ 3,500 $1,500 1.000 750 FirstEnergy(t)

FES / AE Supply FET(2)Revolving March 2019 Revolving March 2019Revolving March 2019 1,241 1,500 Subtotal $Cash 6,000 $3,491 211 Total $6,000 $3,702{r) FE and the Utilities.(a Includes FET, ATSI and TrAlL.Ravolving Crac t Facfiltles FirstEnergy, FES/AE SuNy aN FET Facilities FE and certain ot its subsidiaries participate in three five-year syndicated revolving credit facilities with aggregate commitments of

$6.0 billion (Facilities) expking on March 31, 2019.Ouring September of20l6, the FES/AE Supply tacility was amended to decrease FES'S individualborrower sublimit lo

$900 million from $1.5 billion and AE Supply's individual borrower sublimit to

$600 million from $1 billion. The lending banks' aggregate commitments under the FES/AE Supply facility remain at

$1 .5 billion.Generally, borrowings under each of the Facilities are available to each borrower separately and mature on lhe earlier of 364 daystrom the date of borrowing or the commitment termination date, as the same may be extended. Each of the Facilities containsfinancial covenants requiring each borrower to maintain aconsolidated debt to total capiialization ratio (as detined undereach ofthe Facilities, as amended) of no more than 65'h, and75l"tot FET, measured at the end of each tiscal quarter.82 The following table summarizes the borrowing sublimils lor each bonower under the Facilities, the limitations on shorl-term indebtedness applicable to each bonower under current regulatory approvals and applicable statutory and/or cfiarter limitalions, as ofSeptember 30, 2016: BorrowerFE Revolving Credit Facility Sublimit FES/AE Supply Revolvidj FET Revolving

_R_egula-tory and Gredit Facility Credit Facility Other Short'Term sublimit sublimit Debt Limitations (ln millions)$FE FES AE Supply FET OE cEl TE JCP&L ME PN WP MP PE ATSI Penn TrAIL 3,500 500 500 500 600 300 300 200 500 150 500 400 900 600 50 (21 (2)(3)(3)(3)(3)(3)(3)

(3)

(3)(3)(3)(3)(3)500 500 500 500 500 300 200 500 150 500 100 400 1,000 (r) No limitations, (2) No limitation based upon blanket linancing authorization lrom lhe FERC under existing open markel laritls.

(3) Includes amounts which may be bonow*d under the regulated companies' money pool.The entire amount ofthe FES/AE Supply Facility, $600 million of the FE Facility and

$225 million of the FET Facility, subject to eachborrower's sublimit, is available for the issuance ol LOCS (subject to borrowings drawn under the Facilities) expiring up to one year lrom the date of issuance.

The staled amount of outstanding LOCS willcount against totalcommitments available under each ofthe Facilities and against the applicable borrower's bofiowing sublimil.The Facilities do not contain provisionsthat restrict the abilityto borrow or accelerate payment otoutstanding advances in lhe eventof any change in credit ratings of the borrowers. Pricing is defined in "pricing grids," whereby the cost of funds borrowed under theFacilities is related to the credit ratings of the company borrowing the funds, other than the FET Facility, which is based on ilssubsidiaries' credit ratings. Additionally, borrowings undereach ofthe Facilities are subjecttothe usualand customary provisionstoracceleration upon the occurrence ot events of default, including a cross-default for other indebtedness in excess of $'100 million.As of September 30, 2016, the borrowers were in compliance with the applicable debt to total capitalization ratios under theresDective Facilities.lem LoansFE has a $1 billion variable rate term loan credit agreement with a maturity date of March 3 t, 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 altemate base rate advances or other Eurodollar rate advances. Additionally, FE has a

$200 million variable rate term loan, due May 29, 2020. Eachof the term loans contains covenants and other terms and conditions substantially similar to those ot the FE Facility described abor*, including the same consolidated debt to total capitalization ratio requirement.

As ol September 30, 2016, FE was in compliance with the applicable debt to total capiialization ratios under each of the*e lerm loans.

83 FlrstEneryy lhney Pools FirstEnergy's utility operating subskliary companies also have the ability to borow trom each other and FE to meettheir short-temworking capital requirements. A similar but separate arangement exists among FirstEnergy's unregulated companies.

FESC administers these two money pools and tlacks surplus funds of FirstEnergy and the respective regulated and unregulatedsubsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreementsmust repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate ofinterest is the same for each company receiving a loan from their respective pooland is based on the average cost of tunds available through the pool. The average interesl rates for bonowings in the first nine months of 2016 were 0.67"6 per annum for the regulatd companies'money pool and 1.94olo per annum tor the unregulated companies'money pool. Absent sufficient available funds fromother companies in the unregulated money pool, borrowings by FES from such money pool may be funded by FE from bolrowingsunder its revolving credit lacilily or cash on hand.Potlu on Control nevenue Bonds In the third quarter of 2016, as discussed below, FG rema*eted

$86 million of fixed rate PCRBS and retired $12 million of variableinterest rate PCRBs, which resulted in the elimination of LOCS related to

$92 million of variable interest rate PCRBSthat are no longer outstanding.Long-Tem Debt CapacityFE s and its subsidiaries' access to capital markets and costs of financing are influenced by the credit ratings of their sgcurities.FirstEnergy is focused on improving its balance sheet and maintaining investment grade credit metrics at its regulated businesses and at FirstEnergy Corp. The following table displays FE's and its subsidiaries' credit ratings as of November 4, 2016:Senior Secured Senior Unsecured lssuer s&P Moody's S&P Moody's Fitch FE FES AE Supply AGC ATSI cEl FET JCP&L ME MP OE PN Penn PE TE TrAIL WP B1 BB.BB+BBB+BBB+

BBB+BB+B BB-BB.BBB-BBB-BB+BBB-BBB-BBB-BBB-Baa3 Caal B1 Baa3 Baa?Baa3 Baa3 Baa2 Baal Baal Baa2 A3 BB+BBB-A3 A2 A2 A3 BBB+

BBB+BBB+Baal Baal A2On July 29, 20'16, Moody's downgraded the Senior Unsecured debt rating tor FES to Ba2 from Baa3, and forAE Supply to Bal fromBaa3. At the same time Moody's atfirmed the Baa2 Senior Secured debt rating for FES and the BaaS Senior Unsecured debt ratingforAGC- FE s Baag lssuer Rating was unchanged. On November 4, 2016, Moody's turther downgraded the Senior Unsecured debtrating for FES to Caal, ard for AE Supply to Bl, and affirmed the Senior Unsecured debt rating for AGC at Baa3.

At the same time Mood)/s downgraded the Senior Secured debt rating for FES lo 81.On August 1, 2016, S&P lowered the Seniol Unsecured debt ratings for FES, AE Supply, and AGC to BB- from BB&. S&P alsodowlgraded the Senior Secured debt ratings lor FES and AES to BB+ from BB+. FE and its regulated utility subsidiaries BBB-Corporate Credit Ratings were affirmed.

Additionally on November 4,2016, S&P downgraded the Senior Unsecured debt rating forFES to B and Senior SecuEd debt rating to B&.Debt capacity is subject to the consolidated debt to total caritalization limits in the Facilities previously discussed.

As ofSeptember 30, 2016, FE and its subsidiaries could issue additional debt of approximately

$4 billion and remain within the limitations of the financial covenants required by the Facilities. As of September 30, 2016, FES' incremental debt capacity under ils consolidated 84 debt to total capitalization financial covenant is also $4 billion given FirstEnergy's consolidated debtto totalcapitalization ratio underits Facilily.Chang*s ln Cash Posltlon As of September 30, 2016, FirstEnergy had

$551 million of cash and cash equivalents compared to

$131 million of cash and cashequivalents as ot December 31, 2015. As of September 30, 2016 and Oecember 31,2015, FirstEnergy had approximately

$44 million and $82 million, respectively, of restricted cash included in Other current assets on the Consolidated Balance Sheets.

Cash Flows Frcm Opentlng AcUvMesFirstEnergy's most significant sources ofcash are derived from electric service provided by its utility operaling subsidiaries and thesales ofenergy and related products and services by its unregulated competitive subsidiaries. The most significanl use of cash fromoperating activities is to buy electricity in the wholesale market and pay fuelsuppliers, employees, tax authorities, lenders, and others for a wide range of material and services.

Net cash provided from operating activities was $2,580 million during the first nine months of 2016 compared with $2,317 million provided from operating activities during the first nine months of 2015. Cash flows trom operations increased

$263 million in the firstnine months of 2016, compared with the same period ot 2015, primarily due to the tollowing:. Distribution rate increases associated with the implementation ot new rates, partially otfset by a year-over-year decline in distribution deliveries primarily resulting from lower average cuslomer usage;. Higher transmission revenue, reflecting recovery of incremental operating epenses and a higher rate base;. Higher capacity revenues at CES, partially ofbet by a decline in sales volume; and. Lower disbursements for fuel and purchased power resulting from the lower sales volumes.Cash F ows Frcm Flnanclng ActlvltlesIn the first nine months of 2016, cash provided from financing activities was $316 million compared to $29 million oI cash used forIinancing activities during the first nine months of 2015. The following table summarizes redemptions, repayments, short-termborrowings and dividends:

For the Nine MonthsEnded September 30 Securities lssued or Redeemed / Repaid 2016 2015 (ln millions)$ 200471 339 250 50 295$ 521 $ 1pS4New /ssuesTerm Loan PCRBs Unsecured Notes FMBsRedemptions / Repayments Term Loan PCRBs Unsecured notes FMBsSenior secured notesShort-term borrowings, netCommon stock dividend payments$ (1^01r) $ (?81):: 1,275 $ 134$ (458) $ (455)$(483)

(300)(145)(8e)(200)

(':)(145)(124)On May 1,2016, JCP&L repaid $300 million of 5.625% senior unsecured notes at maturity.85 On June 1 and July 1 of 2016, NG repurchased approximately

$225 million and $60 million, respectively of PCRBS, which weresubject to a mandatory put on such date. On August 15, 2016, NG remarketed the apploximately

$285 million of PCRBS with a fixedinterest rate of 4.375% and mandalory put dates ranging lrom June 1,2022lo July 1,2022.On July 11,2016, Penn issued $50 million of4.24% FMBS due 2056. Proceeds received from fie issuance of the FMBS u/e]e used: (i)to fund capital Eleenditures; (ii) for working capital needs and other generalbusiness purposes; and (iii) to repay bonowings under the FirstEnergy regulated companies' money pool.On August 15, 2016, WP repaid

$145 million ol 5.8757" FMBS at maturity. Also on September 23, 2016, WP agreed to sell $475 million ol new3.84'l. FMBS due 2046

($100 million),4.09% FMBs due 2047

($100 million) and 4.14% FMBS due 2047

($275 million).The sales are expected to settle on December

'15,2016, September

'15,2017 and December 15,2017, respectively. Proceeds to bereceived from the issuances of the FMBS are expected to be used: (i) for general corporate purposes; and (ii) to repsy WP's currently outstanding

$275 million ot 5.95% FMBS that mature on December 15, 2017.

On August 15,2016, FG remarketed approximately

$86 million of PCRBs with fixed interest rates ranging trcm 4.25/olo 4.5O"/" and mandatory put dates ranging from May 1, 2021 to June l, 2021.On September 15, 2016, FG remarketed

$1OO million of PCRBS with a fixed interest rate of 4.25% and a mandatory put of September 15,2021.On September 15 and 30, 2016, respectively, FG retired an aggregate of $12 million of PCRBS with original maturity dates in 2018 and2029.On October 17,2016, PE issued

$155 million of 3.89% FMBS due 2046. Proceeds received from the issuance were used:(i)to repayshon-term bonowings incurred to repay PE s $100 mitlion of 5.80% FMBS that matured on October 15, 2016; and (ii) for general corporare purposes.@sh Flows Frcm lnves ng AdlyntesCash used for investing activities in the first nine months of 2016 principally represented cash used for property additions.

Thefollowing table summarizes investing activities for the first nine months of 2016 and the comparable period of 2015: For the Nine Months Ended September 30Cash Used for Investing Activities 2016 2015 Increase (Decrease)(ln millions)884 $700 400 41 101 87 111(37) (15)$ 2A?6w:: 189 Cash used lor investing activities lor the first nine months of 2016 increased

$189 million, compared to the same period ot 2015, primarily due to increases in nuclear fuel and property additions. Property additions increased due to higher transmission spend in New Jersey and CES' purchase of the remaining non-affiliated leasehold interest in Perry Unit 1. The increase in nuclearfuelwas dueto the scheduled Davis-Besse retueling and maintenance outage.Property Additions:Regulated DistributionRegulated Transmission Competitive Energy Services Corporate

/ OtherNuclear fuel Investments Asset removal costs Other 878 $755 492 31 195 76 101 (52)(6)55 92 (10)94 (11)(10)86 GUARANTEES AND OTHER ASSURANCESFirstEnergy has various financial and pertormance guarantees and indemnif ications which are issued in the normal course ofbusiness. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds andindemnitications. FirstEnergy enters into these arrangementsto facilitate commercialfansactions with third parties byenhancing thevalue ofthe transactjon tothethird party. The maximum potentialamount of future payments FirstEnergy and its subsidiaries could be required to make under these guarantees as of September 30, 2016, was approximately

$3.4 billion, as summarized below: Maximum ExposureGuarantees and Other Assurances FE's Guarantees on Behalt of its Subsidiaries Energy and Energy-Related Contracts(1

)Deferred compensation arrangements(2)

Qths/s)Subsidiaries' Guarantees Energy and Energy-Related Contracts(4)

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 l-QQsts)Total Guarantees and Other Assurances (1) lssued for open-ended terms, with a 10-day termination right by FirstEnergy.(ln millions)28 544 12 584 248 96 21 1,674 2,039 382 22 100 504 3,427 e) CES related portion is $136 million.(3) Includes guarantees of $4 million for nuclear decommissioning lunding assurances, $4 million for railcar l*ases and $4 million for vadous l6ase6.

(1) lncludes energy and engrgy-relaled conlracts associaled with FES ot approimately

$2,t9 million, (t tncludes $9 m illion issued for various terms pursuant to LOC capacity available undEr FirstEnergy's revotuing credil facililies, $87 million issuedin connection with energy and energy r*lated contracts, and

$4 miltion pledged in connection with the sale and leaseback of Beav*r Valley Unil 2by OE.FES'debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guaranteesthe debt obligations of each ofFG and NG. Accordingly, present and future holders of indebtedness of FES, FG and NG wDuld have claims against each of FES, FGand NG, regardless ol whether their primary obligor is FES, FG or NG.Co abral md Contingent-Related FeaturesIn the normalcourse of business, FE and its subsidiaries routinely enter into physical or financially settled contracts forthe 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 fom of cash or credit support withthresholds contingent upon FEs or its subsidiaries' credit rating from each of the major credit rating agencies.

The collateral andcredit support requirements vary by contract and by counterparty. The incremertal collateral requiGment allows for the offs*tting ofassets and liabilities with the same counterparty, where the contractual right of otfset exists under applicable master nelling agreements.Bilateralagreements and derivative instruments entered into by FEand its subsidiaries have margining provisionsthat require postingot collateral.

Based on FES'power portfolio exoosures as of September 30,2016, FES has posted collateralof

$193 million andAE Supply has posted collateral of

$4 million.87 These credit-risk-related contingent features, orthe margining provisions within bilateralagreements, stipulale that ilthe subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be rcquired to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability lo secure additional collateral when needed, could b* rcquired.As a result of the downgrades by Moodys and S&P on July 29, 2016 and August 1 , 2016, CES posted additional collateral of

$53 million. Additionally, on November 4, 2016, Moody's and S&P further downgraded FES. Given the downgrades, CES has furlher potential collateral posting obligations totaling

$81 million for which counterparties have not exercised their right to require CES to post collateral. Subsequent to the occurrence of a senior unsecured crcdit rating downgrade below S&P's and lroodys current ratings, or a "material adverse event,"the immediate posting ol collateral or accelerated payments may be required of FirstEnergy.

Thefollowing table disclosesthe additional credit contingent conlractual obligations that may be required undercertain events as ofNovember 4, 2016: Potential Gollateral Obligations CES Regulated Total (in millions)Contractual Obligations for Additional Collateral At Current Credit Rating Upon Further Downgrade Upon Material Adverse Event Surety Bonds (Collateralized Amount)Total Exposure from Contractual Obligations 355 $144 $81 $10 264$48 96 81 48 10 360 499Excluded from the preceding table are the potential collateral obligations due to afiliate transactions between the Regulated Distribution segment and CES segment.

As ot September 30, 2016, neither FES norAE Supply had any collateral posted with their atfiliates.Othet Commitments and ContingenciesFE is a guarantor under a syndicated senior secured lerm loan tacility due March 3,2020, underwhich Global Holding bonowed

$300million. In addition to FE, Signal Peak, clobal Rail, Global Mining Group, LLC and Global Coal Sales Goup, LLC, each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several guaranties of the obligations of Global Holdingunder the tacility.In connection with the facility, 69.99% of clobal Holding's direct and indirect membership interests in SiOnal Peak, Global Rail andtheir affiliates along with FEV'S and WMB Marketing Ventures, LLC'S respective 33-1/3%

membership interests in Global Holding, are pledged to the lenders under the current facility as collaleral.

OFF-BALANCE SHEET ARRANGEMENTS FES and certain of the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related lo thePerry Unit 1, Beaver Valley Unit 2, and 2OO7 Bruce Mansfield Unit 'l sale and leaseback arrangements, which are satisfied throughoperating lease payments.

The total present value of these sale and leaseback operating lease commitments, net of trustinvestments, was

$895 million as of September 30,2016, and primarily relates tothe 2007 Bruce Mansfield Unit 1 sale and leaseback arrangement expiring in 2040. From time to time FirstEnergy and these companies enter into discussionswith certain parties lo the arrangements regarding acquisition ot owner participant and other interests. However, FirstEnergy cannot provide assurance that any such acquisilions will occur on satisfactory terms or at all.As ot September 30, 2016, FirstEnergy's leasehold interest was 2.60% of Beaver Valley Unit 2 and FES' leasehold interest was93.83% of Bruce Manslield Unit 1.On May 23, 2016, NG completedthe purchase ol the 3.75% lessorequity interests ofthe remaining non-afiiliated leasehold interestin Perry Unit 1 tor

$50 million. In addition, the Perry Unit 1 leases expired in accordance with their terms on May 30, 2016, resulting in NG being the sole owner of Perry Unit 1 and enlilled to 100% of the unit's output.MARKET RISK INFORMATION FirstEnergy uses various maket risk sensitive instruments, including derivative contracts, primarilyto manage the riskof price andinterest rate fluctuations. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides genelal oversight for risk management activities throughout the company.

88 Connodfty Pne BiskFirstEnergy is exposed to financial risks resulting from fluctuating commodity prices, including prices for electricity, natural gas, coaland energy transmission. FirstEnergy's Risk Management Committee is responsible for promoting the effective design and implementation of sound risk management p;ograms and oversees complian@

with corporate risk management policies andestablished riskmanagement practice. FirstEnergy uses a variety of dedvative instruments for risk management puposes includiatg forward contracts, options, futures contracts and swaps.The valuation ol derivative contracts is based on observable market information to the extent that such infomation is available.

Incases where such information is not available, FirstEnergy relies on model-based information. The modelprovides estimates of future regional prices for electricity and an estimate ot related price volatility. FirstEnergy uses these results to develop estimates of fairvalue tor financial reporling purposes and for internal management decision making (see Note 8, Fair Value Measurements, of ihe Combined Notes to Consolidated FinancialStatements). Sources of information forthe valuation ot netcommodity derivative asseb and liabilities as of September 30, 2016 are summarized by year in the following iable: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 lstsl(e)(4) $(1) $27 5 (5)(5)3 (7)11 (1)(ln millions)$$(30)(11) $6$ 31 $(5) $(30) $(e)(1) Repres*nts Exchange traded New York Mercanlile Exchange lutures and options.

• ) Primarily represents contracts ba8Ed on broker and ICE quotes.(3) Includes $(118) million in non-hedge derivative contracts that are primarily related to NUG contracts al certain ot lhe Utilities. NUG contracts aresubject to regulatory accounling and do not impact eamings.FirstEnergy pertorms sensitivity analyses to estimate its exposure to the market riskof its commodity positions. Based on derivativecontracts held as of September 30, 2016, not subiect to regulatory accounting, an increase in commodity prices ot l0% woulddecrease net income by approximately

$37 million during the next 12 months.Equity Price RiskAs ot September 30, 2016, the FirstEnergy pension plan assets were allocated approximately as tollows: 42% in equity securities, 35% in lixed income securities, 9% in absolute return strategies, 10% in real estate and 4% in cash and short-term securities.

Adecline in the value of pension plan assets could result in additional tunding requirements.

FirstEnergy's funding policy is based onactuarialcomputations using the projected unit credit method. During the nine months ended September 30,2016, FirstEnergy made a $297 million contribution to its qualified pension plan. Additionally, in October 2016 FirstEnergy contributed

$85 million to ilsqualified pension plan, including

$50 million at FENOC. See Note 4, Pension and Other Postemployment Benefits, of the Combined Notes to Consolidated Financial Statements for additionaldetails on FirstEnergys pension plans and OPEB. Through September 30,2016, FirstEnergy's pension plan assets earned approximately 1'1.5% as compared to an annual expected return on plan assets of 7.5./".As of September 30, 20'16, FirstEnergy's OPEB plans were invested in fixed income and equity securities. Through September 30,2016 FirstEnergy's OPEB plans have earned approximately 5.8% as compared to an annualexpected return on plan assets of 7.5olo.NDT funds have been established to satisfy NG's and other FirstEnergy subsidiaries' nuclear decommissioning obligations.

As ofSeptember 30, 2016, approximately 62./. of the funds were invested in fixed income securities, 36% of the funds were invested inequity securities and 2% were invested in short-term investments, with limitations related to concentration and investment graderatings. The investments are carried at their market values of approximately

$1,546 million, $908 million and

$56 million for fixedincome securities, equity securities and short-term investments, respectively, as of September 30,2016, excluding

$(8)million of net receivables, payables and accrued income. Ahypothetical 1O%

decrease in prices quoted by stockexchanges would result in a $91million reduction in fair value as of September 30, 20'16. Certain FirstEnergy subsidiaries recognize in oarningsthe unrealized losses on AFS secudties held in its NDT as OTTI.

A decline in the value oI FirstEnergy's NDT or a significant escalation in estimated decommissioning costs could result in addltional funding requirements. During the nine months ended September 30, 2016,FirstEnergy contributed approximately

$2 million to the NDT.lnterest Bate RiskFirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quaner of each fiscalyear. A ptimaryfactor contributing to these actuarial gains and losses are changes in lhe discount rates used to value pension and OPEB oHigationsas of the measurement date of December 31 and the difterence between expected and actual returns on the plans'assels.

FirslEnergy would anticipate a pre-tax mark-to-market loss (net of amounts capitalized) to be in the range ot approximately

$300 million to $525 million assuming a discount rate ot approximately 4.00o/.lo 3.751" tot lhe pension plans and 3.75% to 3.50% for the OPEB plans, respectively, and a return on the pension and OPEB plans' assets ol 11% based on actual investment performancethrough September 30, 2016.CREDIT RISK Credit risk is defined as the risk that a counteparty to a transaction will be unable to fulfill its contractual obligalions.

FirstEnergyand FES evaluale the credit standing ot a prospective counterparty based on the prospective counterparty's financial condition.

FirstEnergy and FES may impose specilic collateral requiremenls and use standardized agreements that facilitate the netting of cashflows. FirstEnergy and FES monitor the tinancial conditions of existing counterparties on an ongoing basis. An independenl risk management group oversees credit risk.

Wholesale Crcdit Risk FirstEnergy and FES measure wholesale credit risk asthe replacement cost for derivatives in power, naturalgas, coaland 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 and FES have a legally enforceable right ofoffsel. FirstEnergy and FES monitor and manage the credit risk of wholesale marketing, risk management and energy lransacting operations through credit policies and procedures, which include an established credit approval process, daily moniloring ofcounterpany credit limits, the use of credit miligation measures such as margin, collateraland the use of master netting agleements.The majority of FirstEnergy's and FES'energy contract counterparties maintain investment-grade credit ratings.Betail Credit Risk FirstEnergy's and FES'principal retailcredit riskexposure relates to CES'competitive electricity activities, which serve residential, commercial and industrial companies.

Retail credit risk results when customers default on contractual obligations or fail to pay forseMce rendered. This risk represents the loss that may be incured due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers.

Relail credit risk is managed through established credit approval policies, monitoring customer exposures and the use oI creditmiligation measures such as deposits in the form ot LOCS, cash or prepayment arrangements.

Retail credit quality is afiected by the economy and the ability of customers to manage through unfavorable oconomic cycles and other market changes. lf the business environment were to be negatively affected by changes in e@nomic or other market condilions, FirstEnergys and FES' retail credit risk may be adversely impacted.OUTLOOKSTATE REGULATION Each of the Utilities' retail rates, conditions ol servi@, issuance of securities and olher matters are subjecl to regulation in the statesin 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 WestVirginia by the WVPSC and in New York bythe NYPSC. The transmission operations of PE in Virginiaare subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subiect to appeal to thePUCO lf not acceptable to the utility.

As competitive retail eleclric suppliers serving retail customers primarily in Ohio, Pennsylvania, lllinois, Michigan, New JeBey andMaryland, FES andAE Supplyare subject to state laws applicable to competitive electric supdiers in those states, including afiiliatecodes ofconductthat apply to FES, AE Supply and their public utility atfiliates.

In addition, if any of the FirstEnergy atfiliates were to engage in the construction ot significant new transmission or generation facilities, depending on the siate, they may be required toobtain state regulatory authorization to site, construct and operale the new transmission or generalion facility.MARYLAND PE provides SOS pursuant to a combination of senlement agreements, MDPSC orders and regulations, and stalutory provisions.SOS supply is competitively procured in the form ot rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third party monitor Although setllements 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 codilying the EmPOWER Maryland goals to reduce electric consumption anddemand and requiring each electric utility to file a plan every three years. PEs current plan, covering the three-year period 2015-2017, was approved bythe MDPSC on December 23,2014. The costs otthe 2015-2017 plan are expected to be approximately

$68million, of which

$38 million was incurred through September 30, 2016. On July 16, 2015, the MDPSC issued an order setting newincremental energy savings goals for 2017 and beyond, beginning with the level of savings achieved under PE s current plan for 90 2016, and ramping up 0.2'/o per fear thereafter to rcach 2o/o. PE continues to recover program costs subject to a five-yearamortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy etficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE.On February 27, 2013, the MDPSC issued an oder (the Feb ary 27 Ordeo requiring the Maryland electric utilities to submit analyses relating to the costs and benefits of making lurther system and statfing enhancements in order to attempt to reduce stormoutage durations. The order further required the Statf of the MDPSC to report on possible pertormance-based rate structures and lo propose additionalrules relating to leeder performance standards, outage communication and reporting, and sharing ofspecialneedscustomer information. PE s responsive filings discussed the steps needed to harden the utility's system in order to attempt to achievevarious levels ot storm response speed described in the February 27 Order, and projected that it would require approximately

$2.7billion in infrastructure investments over '15 years to attempt to achieve the quickest levelof response forthe largesl storm projected in the February 27 Order. On July 1, 2014, the Statf of the MDPSC issued a set ol reporls that rocommended the imposition otextensive additionalrequirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatoryreporting. The Stafi ofthe MDPSC also recommendedthe imposition of penalties, including customer rebates, fora utility's failure orinability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staffof the MDPSC proposed that the utilities be required to develop and implement system hardening plans, up to a rate impact cap oncost. The MDPSC conducted a hearing September 15-18, 2014, to consider certain ofthese matters, and has not yel issued a rulingon any of those matters.

NEW JERSEY JCP&Lcurrently provides BGS for retailcustomers who do not choose a third party EGS and forcustomers of thkd party EGSS that failto provide the contracted service. The supplyfor BGS is comprised ot two components, procured through separate, annually helddescending clock auctions, the results of which are approved by the NJBPU. One BGS component rellects hourly real time energy prices and is available for larger commercial and induslrial customers. The second BGS component provides a fixed price serviceand is intended for smaller commercial and residential customers. All New Jersey EDCS participate in this competitive BGSprocurement process and recover BGS costs directly from customers as a charge separate from base rates.Pursuant to the NJBPU'S March 26, 2015 final order in JCP&L'S 2Ol2 rate case proceeding directing that certain studies be completed, on July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which include operational and tinancial components. The independent consultant conducting the review issued a final report on July 27, 2016, recognizing that JCP&L is meeting the NJBPU requirements and making various operational and financial recommendations.

TheNJBPU issued an Order on August 24,20'16, that accepted the independentconsultant's final report and directed JCP&1, the Division of Rale Counsel, and other interested parties to address the recommendations.

ln an Order issued October 22,2014, in a generic proceeding to review its policies with respect to the use ot a CTA in base rate cases (Generic CTAproceeding), the NJBPU stated that it would continue to apply its current CTApolicy in base rate cases, subjectto incorporaling the following modifications: (i) calculating savings using a five-year look back from the beginning of the test year; (ii)allocating savings with 750lo retained by the company and 25% allocated to rat* payers; and (iii) excluding transmission asseb ofelectric distribution companies in the savings calculation.

On November 5,2014, the Division ol Rate Counselappealed the NJBPUOrder 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.

The oral argument was held on October 25, 2016.On April 28, 2016, JCP&Lfiled tariffs with the NJBPU proposing a general rate increase associated with its distribution operationsthat seeks to improve service and benefit customers by supporting equipment maintenan@, tree trimming, and inspections ot lines, poles and substations, while also compensating for other business and operating expenses.

Thefiling requestd approvalto increaseannual operating revenues by approximately

$142.1 million based upon a hybrid test year for the twelve months cnding June 30, 2016. On July 13, 2016, this matter was submitted to the Otfice of Administrative Law for hearing and the issuance of an Initial Decision. On September 30,2016, JCP&Lfiled an update to its filing, which includes actualdata for the twelve months ended June30,2016, requesting an increase to annualoperating revenues by approximately

$146.6 million. On Oclober 19,2016, an order was received approving the agreed upon procedural schedule.

Hearings are scheduled to occur in January 2017 through March 2017. OnNovember 2, 20'16, JCP&L achieved a settlement-in-principle with all the intervening parties providing for an annual

$80 million distribution revenue increase, which willtake efiect on JanuaryI, 2017, subject to finalization, execution and NJBPU approval ot aStiDulation of Settlement.On June 19, 2015, JCP&I, along with PN, ME, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requestingauthorization for JCP&L PN and ME to contribute theirtransmission assets to MAIT, a newtransmission-only subskliary of FET. The procedural schedule was suspended while the NJBPU considered a motion on a legal issue regading whether MAIT can bedesignated as a "public utility" in New Jersey. On February 24, 2016, the NJBPU issued an Order concluding that MAIT does not satisfy the "electricity distribution'element necessary for "public utility" status because MAlTwould not own any electric distributionassets in New Jersey. On April 22, 2016, JCP&L and MAIT liled a supplemental petition and testimony seeking to include certain JCP&L distributions assets in the transfer to satist the "electricity distribution" element necessary for "public utility" status inaccordance with the NJBPU'S February 24, 2016 order. In order to allow MAlT to file its formula transmission rale with an eftectivedate of January 1, 2017, on September 8, 2016, JCP&L and MAIT submitted a letter to the NJBPU to withdraw their petition to 91 transfer JCP&L assels into MAIT. The NJBPU administratively closed the matter on September 30, 2016. See Transter of Transmission Assels to MAIT in FERC Matters below for further discussion of this transaction.

oHtoOn August 4, 2014, the Ohio Companies filed an application with the PUCO seeking approval oftheir ESP lV efiitled Powetitv Ohbb Progress. ESP lV included a proposed Rirler RRS, which would tlowlhough to customers eiiher charges or credib repres*nting thenet result of the price paid to FES through an eight-year FERGjurisdictional PPA, refened to as the ESP lV PPA, against therevenues received frcm selling such output into the PJM markets. The Ohio Companies entered into stipulations whicfi modfied ESP lV and which included PUCO Staff as a signatory party, in addition to other signatories. On March 31, 2016, the PUCO issued an Opinion and Order adopting and approving the Ohio Companies'stipulated ESP lVwith modifications.

FES and the Ohio Companiesentered inlo lhe ESP lV PPA on April 1, 2016.On January 27, 2016, certain parties filed a complaint with FERC against FES and the Ohio Companies lequesting FERC review theESP lV PPA under Section 205 ot the FPA.

On April 27, 2016, FERC issued an order granting the complaint, prohibiting anytransactions under the ESP lV PPA pending future authorization by FERC, and directing FES to submit the ESP lV PPAfor FERCreview if the parties desired to transact under the agreement. FES and the Ohio Companies did not fil6 the ESP lV PPAlor FERC review but rather agreed to suspend the ESP lV PPA. FES and the Ohio Companies subsequently advised FERC ofthis course of action.On April 29, 2016 and May 2, 2016, several parties, including the Ohio Companies, filed applications tor rehearing on the OhioCompanies'ESP lVwith the PUCO. The Ohio Companies'Application for Rehearing included a modified Rider RRS proposalbut didnot include a FERC-jurisdictional PPA. The PUCO accepted the applications tor rehearing for lurther consideration and provided parties an opportunity to comment on the Ohio Companies'Application for Rehearing and file an alternative proposal.

PUCO Staff recommended that the PUCO deny the Ohio Companies' modified Rider RRS proposal and recommended a new Rider DMR providing for the collection ot

$204 million annually (grossed up for income taxss) for three years with a possible extension for an additional two years. The Ohio Companies recommended that the PUCO approve the proposed modified Rider RRS and that a property designed Rider DMR would be valued at $558 million annually for I years, and include an additionalamountthat recognizesthe value of the economic impact of FictEnergy maintaining its headquarlers in Ohio.Several parties subsequently filed protests and comments with FERC alleging, among other things, that the modified Rider RRSconstitutes a'virtual PPA'. The filings and FirstEnergy's responses thereto are p*nding before FERC.On September 6,2016, whilethe applications for rehearing were stillpending before the PUCO, theOCCand NOAC filed a notbe of appeal with the Ohio Supreme Court appealing various PUCO and Attorney Examiner Entries on the parties' applications lor rehearing. On September 16, 2016, the Ohio Companies intervened and tiled a motion to dismiss the appeal. The appeal remains pending before the Ohio Supreme Court.On Octobell2, 2016, the PUCO issued an opinion and oder ruling on the parties' applications for rehealing and funher moditiedESP lV. The PUCO orderdenied the Ohio Companies'moditied Fider RRS proposal, and instead approved a Rider DMR proposed by PUCO Staff, with modifications.

As a result ofthe stipulations, the PUCO'S March 31,2016 Opinion and Order and the PUCO'S October 12,2016 order, the material terms of ESP lV include:

' An eighl-year term (June 1, 2016 - May 31,2024).The Rider DMR which provides for the Ohio Companies to collect

$132.5 million annually for three years, with the possibilityof a two-year extension. The Rider DMR will be grossed up for taxes, resulting in an approved amount of approximately

$204 million annually.

Revenues from the Rider DMR will be excluded from the significantly excessive earnings test forthe initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension.

Three conditions for continued recovery under the Rider DMR:

(1) retention of the corporate headquarters and nexus ofoperations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO.No restrictions on the Ohio Companies' use of funds collected under the Rider DMR. However, the PUCO directed the PUCO Staff to periodically review howthe Ohio Companies and FE use the funds to ensure the funds are used, directly orindirectly, in support of grid modernization. Uses of funds to indirectly support grid modernization could include, e.9., reducing outstanding pension obligations or reducing debt.Continuation of a base distribution rate freeze through May 31 ,2024.Continuation of the supply of power to non-shopping customers at a market-based price set through an auction process.Continuation of Rider DCR with increased revenue caps of approximately

$30 million per year from June 1,2416 through May 31 , 2019', $20 million per year from June 1 , 2019 through May 31 , 2022; and $1 5 million per year from June 1, 2022through 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.92

. Continuation of a commitment not to recover from retailcustomers cerlain cosls related to tftrnsmission cost allocations for the longer of the five-year period from June 1, 2011 lhrough May 31, 2016 or when the amount of snch costs avoided bycustomers for certain types of products totals $360 million.. Potential pDcurement of 100 MW of new Ohio wind or solar resources subject to a demonstrated need to procure new renewable energy resources as part of a strategy to further diversify Ohio's ene$y portfolio.. An agreement to file a case with the PUCO by April 3,2017, seeking to transition to decoupled base rates for residential cu$omers.. An agreementtofile a Grid Modernization Business Plan for PUCO consideration and appoval(which liling was made onFebruary 29, 2016).. A goal across FirstEnergy to reduce Co, emissions by 90% below 2005 levels by 2045.. Acontribution of$3 million peryear ($24 million overthe eight-yearterm) tofund energy conservation plograms, economic development and iob retention in the Ohio Companies service tefiitory.. Contributions of $2.4 million per year ($19 million over the eight-year term) to tund a fuel-fund in each ol the Ohio ComDanies service territories to assist low-income customers.. Acontdbution of $1 million peryear ($8 million overthe eight-year term) to establish a CustomerAdvisory Councilto ensure preservation and groMh of the competitive market in Ohio.Finally, on March 21, 2016, a number of generation owners filed wilh FERC a complaint against PJM requesting that FERC epand the MOPR in the PJM Taritf to prevent lhe alleged artilicial suppression of prices in the PJM capacity markeF by stat+subsidized generation, in particular alleged price suppression that could result trom the ESP lV PPA and other similar agreements.

The complaint requested that FERC direct PJM to initiate a stakeholder process to develop a long-term iilOPR reform for existing resources thatreceive out-of-market revenue. This proceeding remains pending before FERC.Under Ohio's energy efiiciency standards (S8221 and 58310), and based on the Ohio Companies'amended energy efficiency plans,the Ohio Companies are required lo implement energy efficiency programs that achieve a totalannualenergy savings equivalent of 2,266 GWHS in 2015 and 2,288 GWHS in 2016, and then begin to increase by 1o/" each yeat in m17, subject to legislativeamendments b the energy etficiency standards discussed below. The Ohio Companies are also rcquired lo retain the 2014 peak demand reduction level for 201 5 ard 201 6 and then increase the benchmark by an additional 0.75% theGafter thlough 2020, subieci to legislative amendments to the peak demand reduction standards discussed below On September S0, 2015, the Energy Mandates Study Committee issued its report related to energy efficiency and r*newable energymandates, recommending that the current level of mandates remain in plac* indefinitely. The report also recommended: (i) an epedited process ior review of utility proposed ene*y efficiency plans; (ii) ensuring maximum 6edit br all of Ohio's Energy Initiati\*s; (iii) a swit*h from energy mandabs to energy incenti\res; and (iv) a declaration b* made that the GensralAssembly may determine the energy policy ot the state. Legislation was introduced to address issues raised in the Energy Mandates Study Committee report, namely 58320 and H 8554. S8320 proposes to freeze energy efficiency and rener,\table energy requirements for an additional four years at 2014 levels, as well as addressing net metering issues.

HBs54 proposes b freeze energy efficiency and renewable energy requirements thmugh 2027 al2014 levels.On September 24, 2014, the Ohio Companies filed an amendment to their energy efiiciency portfolio plan as contemplated by S8310,seeking to suspend certain programs for the 2015-2016 period in order to better align the plan with the new benchmarks underS8310. On November 20, 2014, the PUCO approved the Ohio Companies'amended porttolio plan. Severalapplications for rehearingwere liled, and the PUCO granted those applications for further consideration of the matters specified in those applications and thematter remains pending before the PUCO.On April 15, 2016, the Ohio Companies filed an application for approvalof their three-y*ar energy efficiency portfolio plans for the period from Januaryt,2017 through December31, a)19. The plans as proposed complywith benchmatks contemplated by S8310 and provisions of the ESP lV and include a portfolio of energy efficiency programs iargeted lo a variety of cusiomer segments,including residentialcustomers, low income customers, smallcommercial customers, large commercialand induslrialcustomers and governmenial entities.

The Ohio Companies anticipate the cost of the plans will be approximately

$323 million over the life of theportfolio plans and such cosb are e)eected to be recovered throughthe Ohio Companies'existing rate mechanisms. The hearing is scheduled for Novembet 21-23. 2016.On September'16,2013, the Ohio Companies filed with the Supreme Court of Ohio a notice ofappealof the PUCO'S July 17,2013Entry on Rehearing related to energy efficiency, altemative 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 liled a motion to dismissthe appeal, which was denied. OnAugust 9, 2016, upon a Joint Application tor Dismissalfiled by the Ohio Companies, PUCO and the ELPC, the Ohio Supreme Court dismissed the appeal.

Ohio law requires electric utilities and electric service companies in Ohio to serve part ol their load from renewable energy rcsourcesmeasured by an annually increasing percentage amountthrough 2026, subject to legislative amendments discussed above, except2015 and 2016 that remain at the 2014level. The Ohio Comoanies conducted RFPS in 2009, 2010 and 2011 to secure RECS to help meet these renewable energy requirements. In September 2011, lhe PUCO opened a docket to review the Ohio Companies'alternative energy re@very rider through which the Ohio Companies recover th* costs of acquiring these RECS. The PUCO issuedan Opinion and OrderonAugust 7,2013, approving the Ohio Companies' acquisition process and their purchases of RECS to meet 93 stalutory mandates in all insiances except forcertain purchases arising from one auction anddirected the Ohio Companiesto creditnon-shopping customers in the amount of

$43.4 million, plus interest, on the basis that the Ohio Companios did not prove such purchases were prudent. On December 24, 2013,lollowing the denial of their application for rehearing, the Ohio Companies filed a notice of appeal and a motion for siay of the PUCO'S order with the Supreme Court of Ohio, u/hich was granted. On February 18,2014, the OCC and the ELPC also filed appeals of the PUCO'S order. The Ohio Companies timely liled their meril brief with theSupreme Court ot Ohio and the briefing process has concluded. The mailer is not yet scheduled for oral argument.On April 9, 2014, the PUCO initiated a generic investigation ol marketing practices in the competitive retailelectric service market,with a tocus on the marketing offixed-price orguaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through ot new or additional charges. On November 18, 2015, the PUCO ruled that on a going{orward basis, pass-throughclauses may not be included in fixed-price contracts tor all cuslomer classes. On December 18, 2015, FES filed an Application forRehearing seeking to change the ruling or have it only apply to residentialand smallcommercialcustomers.

On January 13, 2016, the PUCO granted reconsideration for {urther consideration of the maners specitied in the applications for rehearing.

PENNSYLVANIAThe Pennsylvania Companies currently operate under DSPS that expire on May 31, 2017, and provide for the competitive procurement of generation supply forcustomers thatdo not choose an alternative EGS orfor customels of altemative EGSSthatfail to providethe contracted service. The detault service supply is currently provided bywholesale suppliers through a mixof long-termand short-term contracts procured through spot market purchases, quarterly descending clock auctions for 3-, 12- and 24-monthenergy contracts, and one RFP seeking 2-year contracts to sen* SRECS tor ME, PN and Penn. Following the expkation of the current DSPs, the Pennsylvania Companies willoperate under new DSPS for the June 1,2017through May 31 , 2019 delivery pedod,which would provide tor the competitive procurement of generation supply for customers who do not choose an altemati\*

EGS or forcustomers of altemative EGSS that fail to provide the contracted service. Under the programs, the supply would be provued by wholesale suppliers through a mix of '12 and 24-month energy contracts, as wellas one RFPfor2-year SREC contracts for ME, PN and Penn. In addition, the plan includes modifications to the Pennsylvania Companies'existing POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges.Pursuantto Pennsylvanias EE&C legislation (Act 129 of 2008) and PPUC orders, Pennsylvania EDCS implemeril energy efficiency and peak demand reduction programs. The Pennsylvania Companies' Phase ll EE&C Plans were effective through May 31, 2016.Total Phase ll costs of these plans were epected to be approximately

$175 million and recoverable through lhe Pennsylvania Companies' reconcilable EE&C riders. On June 19,2015, the PPUC issued a Phase lll Final lmplementation Order setting:demand reduction targets, relative to each Pennsylvania Companies'2007-2008 peak demand (in MW), at 1 .8"6 for ME, 1 .7% icr Penn,1.8%iorWB and 0% br PN; and energy consumption reduction tiaEeb, as a percentage ofeach Pennsylvania Companies'hisbdc 2010 forecasts (in lvfwH), at 4.0y. for ME,3.9% for PN,3.3%for Penn, and 2.67"forwP. The Pennsylvania Companies'Phase lll EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, are designed lo achieve the targets established in the PPUC'S Phase lll Final lmplementation Order without recovery to implement the EE&C plans.Pursuant to Act 11 ot 2012, Pennsylvania EDCS may establish a DSIC to recover costs ot infrastructure improvements and costs related lo highway relocation pojects with PPUC appmval. Pennsylvania EDCs mustfile LTllPs outlining infElstruclure imprcvement plans for PPUC review and approval prior to approval of a DSIC. On October 19, 2015, each ofthe Pennsylvania Companies filedLTllPs with the PPUC for infrastructure improvement over the five.year period of 2016 to 2020 for the iollowing costs: WP

$88.34million; PN

$56.74 million; Penn

$56.35 million; and ME

$43.44 million. On February 11, 2016, the PPUC approved the Pennsyhrania Companies' LTllPs. On February

'16,2016, the Pennsylvania Companies filed DSIC riders for PPUC approvalfor quarterly costrecovery associated with the capital projects approved in the LTllPs. On June 9, 2016, the PPUC approved the Pennsylvania Companies' DSIC riders to be effective July 1, 2016, subject to hearings and refund or reallocalion among customers.On April28,2016, each ofthe Pennsylvania Companiesfiled tarifis with the PPUC proposing generalrate increases associated withtheir distribution operations that will benefit customers by modemizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer seMce enhancements. The tilings request approval lo increase annual operating revenues by approximately

$140.2 million at ME, $158.8 million at PN, $42.0 million at Penn, and

$98.2 million at Webased upon fully projected future test years for the twelve months ending December 31, 2017 at each of the PennsylvaniaCompanies. As a result otthe enactment of Act 40 of 2016 that terminated the practice of making a CTAwhen calculating a utility'sfederal income taxes for ratemaking purposes, the Pennsylvania Companies submitted supplemental testimony on July 7,2016, thal quantified the value of the elimination ofthe CTA and outlined their plan for investing 50 percent of that amount in rale base eligibleequipment as required by the new law. Formal settlement agr*ements tor each of the Pennsytuania Companies were filed on October

'14,2016, which provide increases in annualoperating revenues of approximately

$96 million at ME, $'100 millionat PN, $29 million at Penn, and $66 million at WB and are subject to PPUC approval.

One item related to the calculation of DSIC rates was reserved fol brieling, with briefs filed by two parties. The proposed new rates are expected to take efiect in January 2017 pending regulatory approval , which is expected no later lhan J anuary 26, 2017 .On June 19, 2015, ME and PN, along with JCP&1, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requestingauthorization forJCP&1, PN and ME to contribute their transmission assets to MAIT, a newtransmission-only subsidiary of FET. OnMarch 4,2016, aJoint Petitionfor Full Settlement was subminedtothe PPUC tor consideration and approval.

OnAp l 18,2016, theALJS issued an Initial Decision approving the Joint Petition tor Full Settlsment without modifications.

On July 21, 2016, the PPUC 94 adopted a Motion approving the Joint Petition for Full Settlement with minor modifications. On August 24, 2016, the PPUC issued aFinalOrder approving the Joint Seftlement consistent with theJuly 21,2016 Motion. See Transfer of Transmission Assets to MAIT inFERC Matters below for further discussion of this transaction.WEST VIRGINIA MP and PE provide electric service to all customers lhrough traditional cost-based, regulated utility ratemaking.

MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC.

MP's and PE s ENEC rate is updaled annually.MP and PE filed with the WVPSC on March 31, 2016 their Phase ll energy efficiency program proposallor approval. MP and PE are proposing three energy efiiciency programs to meet their Phase ll requirement of energy etficiency reductions of 0.5% of 2013distribution sales for the January 1, 2017 through May 31 , 2018 period, as agreed to by MP and PE, and approved by the VWPSC inthe 2012 proceeding approving the transfer ol ownership ot Harrison Power Station to MP. The costs forthe program are expecled to be $10.4 million and will be eligible for recovery through the existing energy efficiency riderwhich is reviewed in the tuel (ENEC)case each year. A unanimous settl*ment was reached by the parties on all issues and presented to the WVPSC on August 18, 2016. Anorder approving the settlement in tull without modification was issued by the WVPSC on September 23, 2016. Under the order, lhe programs may begin as of the date of such order, but no later than January 1, 2017.The Staff of the WVPSC and the Consumer Advocate Division filed a Show Cause petition on August 5, 201 6, reqrcstirE the WVPSC order MP and PE to file and implement RFPS for allfuture capacity and energy requirements above 100 bfws and that they comply with an RFP settlement provision from the Harrison asset acquisition. MP and PE liled a timely response to the petition arguing fordismissal on September 7, 2016. On October 17, 2016, the WVPSC denied the petition fled by the Staff of the WVPSC and the Consumer Advocate DMsion and dismissed the case.

On August 16, 2016, MP and PE filed their annual ENEC case proposing an approximate

$65 million annual increase in rates effective January 1,2017, which is a 4.7"/. overall increase o\*r existing rates. The

$65 million increase is comprised of

$119 million under-recovered balance ars ofJune 30,20 t6, and a proiected

$54 million oveFrecovery for the 2017 rale effective period.Ahearing has been set lor November I and 10, 2016 with an order e)eected to be issued in the fourth quaner of 2016.On August 22, 2016, MP and PE filed an application for appoval ol a modemization and improvement plan for coal-fired boilers at electric power plants and cost-recovery surcharge prcposing an approximate

$6.9 million annual increase in rales proposed to be effective May I , 2017, which is a 0.570 overall increase over existing rates. The filing is in response lo recent legislation by the WestVirginia Legislature session permitting acceleratd recovery of costs related to modemizing and impmving coal-fired boilers, including costs related to meeting environmental requiremenb and roducing emissions. The lillng was supplemented on September28,2016,to add two additional projects, resulting in an appmximate

$7.4 million annual increase in rates.

The Staff of the WVPSC has filed a motion to dismiss the case arguing the new stalute was nol meant to recover these types of pmjecb, but the WVPSC has set the case for hearing for February 21-23,2017 -

On December 30, 2015, MP filed an IRP identifying a capacity shortfatl staning in 2016 and exceeding 700 lvlw by 2020 and 850 MW by 2027. On June 3, 2016, the WVPSC accepted the IRP finding that lRPs are informational and that it must not approve ordisapprove the lRP. MP Plans to issue a RFP to address its generation shorttall iderdmed in the IRP by the end of the year RELIABILITY UAITERS Federally-enforceable mandatory reliability standads apply to the bulk electric system and impose certain operating, recod-keepingand reporting requirements on the Utilities, FES, AE Supply, FG, FENOC, NG, ATSI and TrAlL. NERC is the ERO designated by FERC to establish and enfolce these reliability standards, alhough NERC has delegated day-tcday implementation and enbrcementof these reliability standards to eight legionalentities, including RFC. All ot FirstEnergys facilities are located within lhe RFC region.

FirstEnergy actively participales in the NERC and RFC siakeholder processes, and othenflise monitors and manages its companiesin responseto the ongoing development, implementation and enforcement of the reliability standards implemented and enlorced by RFC.FirstEnergy believes that it is in compliance with all currently-etfective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and tacilities, FirstEnergy occasionally loarns of isolated facts orcircumstances that could be interpreted as excursions from the reliability standards.

ll and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedialresponse to the specific circumstances, including in appropriate cases "self-reporting" an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC willcontinue 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 standardsfor its bulk electric system could result in the imposition of financial penalties, and obligationsto upgradeor build transmission facilities, that could have a material adverse effect on its tinancial condition, results of operations and cash flows.95 FERC MATTERSOhio ESP lV PPAFor intormation regarding matters belore FERC related to the ESP lV PPAbetween FES andthe Ohio Companies, see "Regulatory Matters - Ohio' above.PJM ftansmission Bates PJM and its stakeholders have been debating the proper method to allocate costs for newtransmission lacilities. While FirstEnergyand other parties advocate tora traditional "beneficiary pays" (or usage based) approach, others advocato lor "socializing" lhe costson a load-ratio share basis, where each customerin the zone would pay based on its totalusage otenergywithin PJM. Thisquestion has been the subject of extensive litigation before FERC and the appellate courts, including betore 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 5OO kV or higher lines and thus had not adequately supported its decision to socialize lhe costs of these lines. The majority found that eastern PJM utilities are the primary beneficiaries ot the lines, wh ile western PJM utilities are only incidental beneficiades, and that, while incidental beneficiaries should pay some shale of the costs of the lines, that share should be proportionate to the benelit they derive from the lines, and not on load-ratio share in PJM as a whole. The court Emanded the case bFERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings. On June 15, 2016 various parties, including ATSI and the Utilities, filed a settlement agreement at FERC agreeing to apply a combined usage basedsocialization approach to cost allocalion for charges to transmission customers in the PJM region for transmission projectsoperating at or above 500 kV. Certain parties in the proceeding did not agree to the settlement and tiled plotests to the senlementseeking, among other issues, to strike certain of the evidence advanced by FirstEnergy and certain of the other setlling panies insupport of the settlemert, as well as pmvided further comments in opposition lo the settlement.

The PJM TOs responded to theprotesting parties' various pleadings and motions. The settlement is pending betore FERC.In a series of ordeF in certain Order No. 1 000 dockeb, FERC asserted that the PJM transmission owners do not hoH an incumbent'rig ht ot first refusal" to @nstruct, own and operate transmission proiects within their respective footsrints that are approved ars part ofPJM'S RTEP procoss. FirstEnergy and other PJM transmission owners appealed these rulings tothe U.S. Court ofAppeals tor the D.C. Circuit which, in a July '1, 2016 oFinion, ruled that the PJM transmission owners lailed to preserve their atguments in the legal proceedings bebre FERC and, on that basis, denied the appeal. In a related case browht by the Slouthwest Power Pooltransmissionowners and issued on the same day, the court ruled that the lrobrire-S,b/a standard does not protect transmission owners' rights otfirst refusal lhat may be proviled for in RTO tariffs b*cause, according to the court, the tariff language is designed to block competition.

The lroblesrbna standard presumes that rates negotiated by pdvate parties at arm's length are just and reasonable and pmhibits FERC from modifying such rates unless the public interest requires.The outcome of these proceedings and their impact, if any, on FirstEnergy cannot be predicted at this time.RTO BealignmentOn June 1,2011, ATSI and the ATSlzone transferred from MISO to PJM. While many ofthe matte6 involved with the move have been resolved, FERC denied recovery under ATSI'S transmission rate for certain charges that collectively can be described as "exitfees" and certain other transmission cost allocation charges totaling approximately

$78.8 million until such lime as ATSI submits a cosubenefit analysis demonstrating net benefits to customers from the transfer to PJM. Subsequently, FERC rejected a poposed settlement ag reement b resohre the exit fee and transm ission cost allocation issues, stating that its action is withod prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh lhe exit fee and transmission cost allocation charges. On March 17,2016, FERC denied FirstEnerg/s request for rehearing of FERC'S earlier orderrejecting the settlement agreement and affirmed its prior ruling that ATSI must submit the cost/benefit analysis.Separately, the question ot ATSI'S responsibility for certain cosB tor the "Michigan Thumb" transmission project continues to bedisputed. Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings before FERCand certain United States appellate courts. On October 29,2015, FERC issued an orderfinding thatATSland theATSlzone do nothave to pay MISO MVP charges forthe Michigan Thumb transmission project. MISO and the MISO TOs liled a request for rehearing,which FERC denied on May 19,2016. On July 15, 2016, the MISO TOs filed an appeal ot FERC'S orders with the Sixth Circuit.

FirstEnergy intervened in the proceedings and intends to participate in the appeal. On a related issue, FirstEnergyjoined certain otherPJM transmission owners in a protest of MISO's proposalto allocate MVP costs to energy transactions that cross MISO'S border into the PJM Region. On July 13, 2016, FERC issued its order finding it appropriate for MISO to assess an MVP usage charge tor transmission exports from MISO to PJM. Various parties, including FirstEnergy and the PJM TOs, requested rehearing or clarification of FERC'S order. These parties'request for rehearing remains pending before FERC.In addition, in a May 31, 2011 order, FERC ruled that the costs tor certain "legacy RTEP" transmission proiects in PJM approvedbefore ATSI joined PJM could be charged to transmission cuslomers in the ATSI zone. The amount to be paid, and the question of derived benofits, is pending before FERC as a result of the Seventh Circuit's June 25, 2014 order described above under PJM Transmission Rates.96 The outcome of the proceedings that address the remaining open issues related to cosb for the "Michigan Thumb' transmission poject and "legacy RTEP' transmission projects cannot be predicted at this lime.Tmster of Transmission AsseB to MAITOn June 10, 2015, MAII a Delaware limited liability company, was formed as a new transmission-only subsidiary of FET for the purposes of owning and operating all FERo-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, theNJBPU, andthe PPUC requesting authorization forJCP&L, PN and ME to contribute their transmission assetsto MAIT. Additionally, the flings requested approval from the NJBPU and PPUC, as applicable, of: (i) a lease to MAIT ot real property and rights-of-wayassociated with the utilities' transmission assetsi (ii) a MutualAssistance Agreement; (iii) iilAlT being deemed a public utilily understate law; (iv) MAITS participation in FE's regulated companies'money pool; and (v) certain affliated interest agreemenb. As initially proposed, it was expected that JCP&1, ME, and PN would contribute their transmission assets at net book value and an allocated portion of goodwill in a tax-tree exchange to MAIT, which would operate similar to FETS two existing stand-alone transmissionsubsidiaries, ATSI and TrAlL. MAITS transmission faciliti*s will remain under the functional control of PJM, and PJM will provide transmission service using these facilities underthe PJM Tarifi. FERC approved the transaction on February 18,2016. OnAugust24, 2016, the PPUC issued a FinalOrder approving the transaction.

In order to allow MAIT to file its formula transmission rate with anetfective date of January 1, 2017, on September 8, 2016, JCP&L and MAIT submitted a letter to the NJBPU to withdraw their petitionto transfer JCP&L assets to MAIT. The NJBPU administratively closed the matter on September 30, 2016. See New Jersey andPennsylvania in State Regulation above lor turther discussion of this transaction.On October 14 and 28, 2016, MAIT submitted applications to FERC requesting authorization to issue equity, short-term debt, andlong-term debt. MAIT intends to issue membership interests to FET, PN, and ME in exchange for their respective cash and assetcontributions. MAIT is expected to issue short-term debt and participate in lhe FirstEnergy Utility Money Poolfor working capital, tofund day-to-day operations, and lor other generalcorporate purposes.

Over the long-term, MAIT is expected to issue long-term debtto support capital investmenl and to establish an actual capital structure for ratemaking purposes. On October 28,2016, MAIT submitted an application to FERC requesting authorization to implementa formula transmission rate to recover and earn a return on transmission costs etfective January 1, 2017. On October 28, 2016, MAlT and PJM submitted joint applications to FERC requestingauthorization for (i) ME and PN to withdraw from the PJM Consolidated Transmission Owners Agreement as TOs, and (ii) MAIT to become a participating PJM TO. Acceptance ot MAIT as a PJM TO would grant PJM functional control over MAlls transmission assets, and would permit PJM to implement MAIT'S formula rate on MAITS behalf.JCP&L ftansmission Formula RateGiven thatJCP&Lwill not be transferring its transmission assets to MAIT, there is a need forJCP&Lto update its lransmission rate.Accordingly, on October 28, 2016, JCP&L submitted an application to FERC requesting authorization to implement a tormulatransmission rate to recover and earn a return on transmission costs efiective January 1, 2017.Calitomia Clains Litigation Since 2002, AE Supply has been involved in litigation and claims based on its power sales to the California Energy Resource Scheduling division of the CDWR during 2001-2003. This litigation and claims are related to litigation and claims advanced by lhe Calilornia Attorney General and certain Calitornia utilities regarding alleged market manipulation of thewholesale energy markets inCalifornia during the 2000-2001 period. AE Supply negotiated a settlement with the California Attorney General and the Californiautilities and, on August 24, 2016, filed the settlement agreement for FERC approvat.

The settlement calls lor AE Supply to pay, without admission of any liability, $3.6 million in settlement in principle of all remaining claims that are based on AE Supply's power sales in the western energy markets during the 2001-2003 time period. On October 27, 2016 FERC approved this senlement.PATH Transmission Prcject 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 February2011.As a result of PJM canceling the project, approximately

$62 million and approximately

$59 million in costs incurred by PATH-Allegheny and PATH-WV respeclively, were reclassified from net property, plant and equipment lo a regulatory asset for future recovery PATH-Allegheny and PATH-WV requested authorization from FERC to recover the costs with a proposed ROE of 10.97.

(10.4% base plus 0.5% lor RTOmembership) from PJM customers over five years. FERC issued an order denying the 0.5% ROE adder for RTO membership and allowing the taritl changes enabling recovery of these costs to become efiective on De@mber 1, 2012, subject to settlement proceedings and hearing if the parties could not agree to a settlement. On March 24, 2014, the FERC Chief AU teminated settlement proceedings and appointed an AL, 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 ot FERC'S Opinion No. 531,discussed bdow to the PATH proceeding. On September 14,2015, theAu issued his initialdecision, disallowing recovery of certain costs. The initial decision and exceptions thereto remain before FERC tor review and a final order. FirstEnergy continues to believethe costs are recoverable, subjecl to tinal ruling from FERC.

97 FEBC ODinion I'lo.

531On June 19, 2014, FERC issued Opinion No. 531, in which FERC revised its approach for calculating the discounted cash flowelement of FERC'S ROE methodology, and announced the potential lor a qualitative adjustrnent to the ROE mehodology results.Under the old methodology, FERC used a five-year forecast for the dividend groMh variable, whereas going forward ths growthvariable willconsist of two parF: (a) a live-year forecast br dividend grourth (2/3 weight); and (b) a longterm dividend growlh torecastbased 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 foMard,FERC may rely on recod evidence to make qualitative adjustments to the outcome ot the ROE methodology in order b reach a levelsufiicient 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, 531-A and 531-B are pending before the U.S. Court of Appeals lor the D.C. Circuit.MISO Capadty PoftabilityOn June 11, 2012, in response to cenain 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. FirstEnergyand olher parties subminedtilings arguing that MISO'S concerns largely are without foundation, FERC did not mandale a solution in response to MISO'Sconcerns. At FERC'S dkection, in May, 2015, PJM, MISO, and their respective independent mark*t monitors provided additional information on theirvarious joint issues surrounding the PJ[iVMlSO seam to assist FERC's understanding ofthe issues andwhat, ifany, additionalsteps FERC should take to improve the efiiciency ot operations at the PJiiVMISO s*am. Stakeholders, including FESCon behalf ofcertain of its afiiliates and as oart of a coalition ofcertain other PJM utilities, filed responses to lhe RTOsubmissions.

The various submissions and responses remain before FERC for consideration.Changes to the criteria and qualifications tor participation in the PJM RPM capacity auctions could have a significant impact onthe outcome of those auctions, including a negative impact on the prices at which those auctions would clear.

ENVIRONMENTAL MATTERS Variouslederal, state and local authorities regulate FirstEnergywith regard toair and waterquality and other environmentalmatters.

Compliancewith environmental regulations could have a materialadverse effect on FirstEnergys earnings and competitive position tothe extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk ofcosts associated with compliance, or failure to comply, with such regulations.Clean Air Act FirstEnergy complies with SO, 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 trom lower or non-emitting plants an*Uor usingemission allowances.CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2emissions in affectedstates to

2.4 million

tons annually and NOx emissions to 1 .2 million tons annually. CSAPR allows trading of NOx and SO2 emissionallowances between power plants located in the same state and interstate trading ol NOx and SO2 emission allowances with some restrictions.

The U.S. Court ofAppeals lor the O.C. Circuit ordered the EPA on July 28, 2015, to reconsiderthe CSAPR caps on NOxand 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 EPAs regulatory approach under CSAPR, butquestioning whether EPArequired upwindstates to reduce emissions by more than their contribution to air pollution in downwind states.

EPA issued a CSAPR update rule onSeptember 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Depending on howthe EPAand the states implement CSAPR, the future cosl ofcompliance may be materialand changes to FirstEnergy's and FES'operations may result.EPAtightenedthe primaryand secondary NAAOS for ozone from the2008 standard levels ot75 PPBto 70 PPBon October1,2015.

EPA stated the vast maiority of U.S. counties will meet the new 70 PPB standad by 2025 due to other federal and state rules and programs but EPAwilldesignate those counties that lailto attain the new 2015 ozone NMQS by October 1,2017. States willthenhave roughly three years to develop implementation plans to attain the new 201 5 ozone NAAOS. Depending on how the EPA and the states implementthe new 2015 ozone NMQS, the future cosl of compliance may be materialand changes to FirstEnergys and FES'operations may result. In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Hanison generating facility's NOx emissions significantly contribute to Delaware's inability lo attain the ozone NMQS. The petition seeks ashort term NOx emission rate limit of 0.125lb/mmBTU over an averaging period of no more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. On September 27,2016,EPA extended the time frame tor acting on the CAA Section 126 petition by six months to April 7, 2017. FirstEnergy is unable to predict the oulcome of lhis matter or estimate the loss or range of loss.MATS imposes emission limits for mercury PM, and HClfor allexisting and new fossilfuelfired electric generating units effective inApril 2015 with averaging of emissions from multiple units located at a single plant. FirstEnergy's totalcapital cost for compliance (over the 2012 to 2018 time period) is cunently expected to be approximately

$345 million (CES segment ot

$168 million and Regulated Distribution segment of

$177 million), ofwhich $267 million has been spent through September 30,2016 ($117 million atCES and $150 million at Regulated Distribution).

On August 3, 2015, FG, a subsidiary ol FES, submitted to the AAA otfice in New York, N.Y., a demand for arbitration and stiatemenl ofclaim against BNSF and CSX seeking a declaration that MATS constituted a force majeure event that excuses FG's performance under its coal transportation contract with these parties. Specitically, the dispute arises from a contract lor the transportation by BNSFand CSX of a minimum of 3.5 million tons ot coal annually through 2025 to certain coaffired power plants owned by FG that arelocated in Ohio. As a resultotand in compliancewith MATS, allplants covered by this contract rvere deactivated byApril 16,20'15.InJanuary2012, FG notified BNSF and CSXthat MATS constituted a torce maieure event under the contract that excused FG'sturther performance.

Separately, on August 4, 2015, BNSF and CSX submined to the AAA otfice in Washington, D.C., a demand forarbitration and sialement of claim against FG alleging that FG breached the contract and that FG's declaration of a torce majeureunder the contract is not valid and seeking damages under the contract through 2025. On May 3l, 20'16, the panies agreed to astipulation that it FG's force majeure detense is determined to be wholly or partially invalid, liquidated damages are the sole remedyavailable to BNSF and CSX. The arbitration panelhas determinedto consolidate the claimswith a liability hearirE scheduled to beginon November 28, 20'16, and, if necessary a damages hearing scheduled to begin on May A,2017.

The decision on liability isexpected to be issued within sixty days from the end ofthe liability hearing proceedings, which are scheduledto conclude February24,2017. FirstEnergyand FES continue to believe that MATS constitutes a torce majeure event underthe contract as il relates to the deactivated plants and that FG's perlormance under the contract is therefore excused. FG intends to vigorously assert its position in the arbitration proceedings. lf, however, the arbitration panel rules in favor ot BNSFand CSX, the results otoperations andfinancial condition ot both FirstEnergy and FES could be materially adversely impacled.

Refer to lhe Strategic Review of CompetitiveOperations section ol Note 1, Organization and Basis ol Presentation, for possible actions that may be taken by FES in the event ofan adverse outcome, including, without limitation, seeking protection under the bankruplcy laws. FirstEnergy and FES are unable toestimate the loss or range of loss.FG is also a party to another coal transportation contract covering the delivery of 2.5 million tons annuallythrough 2025, a portion ofwhich is to be delivered to another coal-fired plant owned by FG that was deactivated as a resuh of MATS. FG has asserted adefense of force majeure in response to delivery shorttalls to such plant underthis contract as well. lf FG lails to reach a resolutionwith the applicable counterparties to the contracl, 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,lhe results of operationsand financial condition of both FirstEnergy and FES could be materially adversely impacted. FirstEnergy and FES are unable toestimate the loss or range of loss.As to both coal transportation agreements referenced above, FG paid approximately

$70 million in the aggregate in liquidateddamages to settle delivery shortfalls in 2014 related to its deactivated plants, which approximated full liquidated damages under the agreemenls for such year related to the plant deactivations.

Liquidated damages for the period 2015-2025 remain in dispute.As to a specific coal supply agreement, AE Supply has asserted termination rights etfective in 2015. In response lo notification ofthetermination, the coal supplier

@mmenced litigation alleging AE Supply does not have sutficient justification to terminate the agreement.

AE Supply has 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 approximately 5.5 million tons remaining under the contract fordelivery At this time, AE Supply cannot estimate the loss or range of loss regarding the on-going litigalion with respect to this agreemenl.

In September 2007, AE received an NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and WestVirginia state laws atthe coal-fired Hattield's'Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin andWillow lsland plants in West Virginia. The EPA's NOV alleges equipment replacements during maintenance outages triggered the pre construction permitting requirements underthe NSR and PSD programs. On June 29, 2012, January 3'1, 2013, March 27,2013 and Octobell8, 2017, EPA issued CAA section 114 requests for the Harrison coal-fired plant seeking intormation and documentation relevant lo its operation and maintenance, including capital projects undertaken since 2007. On December 12, 2014, EPA issued aCAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to ils operation andmaintenance, including capital projects undertaken since 2009. FirstEnergy intends to comply with the CAAbut, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss.Clinate ChangeFirstEnergy has established agoalto reduce CO2 emissions by 90%

below2005levels by 2045. There are a numberof initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in tho RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, lo control emissions of certain GHGS. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been imDlemented across the nation.The EPA released its final "Endangerment and Cause or Contribute Findings lor Greenhouse Gases under the Clean Air Acl" inDecember 2009, concluding that concentrations ot 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 electricgenerating plants. The EPA released its tinal regulations in August 2015 (rvhich have been stayed by the U.S. Supreme Court), to 99 reduce CO2 emissions from existing fossil fuel fhed electric generating units that would require each state to develop SlPs bySeptember 6, 2016, to meet the EPAS state specific CO2 emission rate goals. The EPAS CPP allows statss to request a lrvo-yearextension tofinalize SlPs by September 6,2018. lf states failto develop SlPs, the EPA also proposed a lederalimplementation planthat can be implemented by the EPA that included model emissions trading rules which states can also adopt in thek SlPs. The EPA also finalized separate regulations imposing CO, emission limils for new, modified, and reconstructed fossil fuel fired electric generating units. On June 23,2014, the United States Supreme Court decided that CQ or other GHG emissions alone cannot trigger permitting requirements underthe CAA, but that air emission sourcesthat need PSD pemib due to oher legulaEd air pollutants canbe required by the EPAto install GHG control technologies.

Numerous states and private parties filed appeals and motions to say the CPPwith the U.S. Court ol Appeals ior the D.C. Circuit in October2015. On January 21,2015, a panelofthe D.C. Circuit denied themotions for stay and set an expedited schedule lor briefing and argument. On February9,2016, the U.S. Supreme Coun $ayed therule during the pendency ot the challenges to the D.C. Circuit and U.S. Supreme Courl. Depending on the outcome ot turther apPeals and how any final rules are ultimately implemented, the luture cost oI compliance may be material.At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020.

The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide greenhouse gasemissions by 26 to 28 percent below 2005 levels by 2025 and joined in adopting the agreemenl reached on December '12, 2015 atthe United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement was ratified bythe requisite number of countries (i.e. at least 55 countries representing at least 55% of global GHG emissions) in October 2016 and ils non-binding obligations to limit globalwarming towellbelowtwo degrees Celsius are effective on November4,2016. FirstEnergy cannotcurrently estimate the financial impact ofclimatechange policies, although potential legislative or regulatory programs restricting CO,emissions, or litigation alleging damages trom GHG emissions, could require material capilal and other expendilures or result inchanges to its operations. The CO2 emissions per KWH ot electricity generated by FirstEnergy is lower than many of its regionalcompetitors due to its diversified generation sources, which include low or non-Coz emitting gasjired and nuclear generators.

Clean Watet Act Various water quality regulations, the maiorityotwhich are the result of the federalCWAand its amendments, apply to FirstEnergys plants. ln addition, the states in which FirstEnergy operates have water quality standards applicable to FiBtEnergys operations.The EPA finalized CwA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velociiy greaterthan 0.5leet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts ot a cooling water intake system to a 12"/" annual average and requirir* cooling water intake struclures e)ceeding 125 million gallons perday to conduct studies to detemine sitespecific controls, if any, to reduce enlrainment, which occurs when aquatic life is drawn into afacilitys cooling water system. FirstEnergy is studying various control options and their costs and efiectiveness, including pilot tssdng of reverse louvers in a portion of the Bay Shore plant's cooling waler intake channel to divert fish away ftom the plant's cooling waterintake system. Depending on the results of such studies and anyfinalaction taken by the states based on those studies, the ftJturecapital costs of compliance with these standards may be substantial.On September 30, 20'15, the EPAtinalized new, more stringent etfluent limits lor the Steam Eleclric Power Generating category (40CFR Part 423) lor arsenic, mercury selenium and nitrogen tor wastewater from wet scrubber systems and zero discharge of pollutanls in ash transport water. The treatment obligations will phase-in as permits are renewed on a tive-year cycle from 2018 to2023. The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporativetechnology and in relurn have untilthe end of2023to meetthe more stringent limits. Depending on the outcome ofappeals and howany final rules are ultimately implemented, the future costs of compliance with these Standards may be substantial and changes toFirstEnergy'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, sulfateconcentrations and other ettluent limitations lor heaw metals, as well as temperature limitations. Concurrent with lhe issuance of theFort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the eftluent limits that were efiective 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 finaldecision on the appealand subject toWVDEP moving to dissolve the stay.

TheFort Martin NPDES permit could require an initial capital investment ranging trom

$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 etfluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue theseissues but cannot predict the outcome ot 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 predicttheir out@mes or estimate lhe loss or range of loss.

Regulatbn ot Waste Disp6alFederal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amsnded, and the Toxic Substances Control Act. Certain coal combustion residuals, such as coal ash, were exempted from hazardous wasle disposal requirements pending the EPAs evaluation of the need for hJture regulation.

100 In December 2014, the EPAfinalized regulations forthe disposalot CCRs (non-hazardous), establishing national standards regarding landtilldesign, structural integrity design and assessment criteria tor surface impoundments, groundwater moniloring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRS from electric generating planls.

Based on an assessment ofthe tinalized regulations, the future cost ofcompliance and expected timing of spend had no significant impact on FirstEnergy's or FES' existing AROS associated with CCRS. Although none are currently expected, any changes in timingand closure plan requirements in the future could materially and adversely impact FirstEnergy's and FES'AROS.Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRS by December 31, 2016 and FG to provide bonding tor 45 years of closure and post-closure activilies and to complete closure within a 12-year period, but authorizing FG to seek a permit modification based on"unexpected siteconditions that have or willslow closure progress." The permitdoes not require active dewatering ofthe CCRS, butdoes require a groundwater assessmenlfor arsenic and abatement if certain conditions in the permit are met. The Bruce Mansfield plant is pursuing several options for disposal ol CCRS following December 31, 2016 and expects benelicial reuse and disposaloptions wilf be sufficient for the ongoing operation of the plant. On May 22,2015 and September 21, 2015, the PA DEP reissued a permit forthe Hatfield's Ferry CCR disposal facility and then modified that permitto allowdisposalof Bruce Mansfield plant CCR. OnJuly 6, 2015 and Oclobet 22,2015, the Sierra Club filed Notices of Appeal with the Pennsylvania Environmental Hearing Boardchallenging 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 disposalsites, which may require cleanupunder the CERCLA. Allegations ol disposal of hazardous substances at historical siles and lhe iiability involved are often unsubstantiated and subjectto disputei howswr, f*d*rallaw provides that all potentially responsible parties fora particular site maybe liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of September 30,2016 based on estimates otthe totalcosts of cleanup, FE's and its subsidiaries' proportionate responsibility forsuch costs and the linancial ability ot other unafiiliated entitiesto pay. Totalliabilities ofapproximately

$121 million have been accrued through September 30, 2016. Included in the totalare accrued liabilities ofapproximately$89 million for environmental remediation of tormer manufactured gas plants and gas holder facilities in NewJersey, which are being recovercdby JCP&L through a non-bypassable SBC. FirstEnergy or its subsidiari*s could be tound potentially responsible for additionalamounls or additional sites, but the loss or range of losses drnnot be determined or reasonably estimated at this time.OTHER LEGAL PROCEEDINGSNucleat Plant Matters Under NRC regulations, FirstEnergy must *nsure that adequate funds will be available to decommission ils nuclear facilities. As otSeptember 30, 2016, FirstEnergy had approximately

$2.5 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.

lf 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 atfect the values of theNDTs. FE and FES have also entered into a total ot

$24.5 milljon in parental guarantees in support of the decommissioning of the spent fuelstorage tacilities located at the nuclear tacilities. However, as FES no longer maintains investment grade credit ratings fromeither S&P or Moody's, NG plans to fund a supplemental trust in lieu of a parental guarantee that would be required to support thedecommissioning oI the spent fuel storage facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts theamount ot its parental guaranlees, as appropriate.In August 2010, FENOC submitted an application to the NRC for renewal ot the Davis-Besse operating license for an additional twenty years. On December 8, 2015, the NRC renewed the operating license for Davis-Bess6, which is nowauthorized lo continueoperation through Aptil22,2037. Ptiot lolhat decision, the NRC Commissioners denied an inlervenor's request to reopen the recordand admit a contenlion on the NRC'S Continued Storage Rule. On August 6, 2015, this intervenor sought review of lhe NRC Commissioners'decision before the U.S. Court ofAppeals forthe DC Circuit. FENOC intervened in that proceeding.

On September 2'1 , 2016, the U.S. Court of Appeals for the DC Circuit granted the intervenor's unopposed motion and dismissed this case.

As part ot routine inspections of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 201 1. These inspections revealed that the cracking condition had propagated a smallamount in select areas. FENOC'S analysis confirms thatthe building continuesto maintain its structural integrity, and its abilityto salely perform all of its tunctions. 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 ofevaluating the significance of the shield building cracking. The NRC also concluded that the shield building remained capable ol performing its design salety functions despite the identified laminar cracking and that this issue was ofvery low satety significance.

FENOC plans to submit a license amendment application to the NRC related to the laminar cracking in the Shield Building.On March 12, 2012, the NRC issued orders requiring salety enhancements at U.S. reactors based on recommendations from thelessons learned Task Force reviewotthe accident at Japan's Fukushima Daiichinuclear power plant.

These orders require additional mitigation strategies tor beyond-design-basis external events, and enhanced equipment tor monitoring water levels in spent fuel pools. The NRC also requested that licensees including FENOC:

re-analyze earthquake and flooding risks using the latest 101 information available; conduct earthquake and flooding hazard walkdowns at their nuclear plants; assess the ability of cunent communications systems and equipment to p*rform under a prolonged loss ofonsite and ofisite electrical pot/r*r; and assess plantstafiing levels needed to till emergency positions.

These and other NRC requirements adopted as a result of the accident atFukushima Daiichi are likely to result in additional malerialcosts from plant modifications and upgrades at FirstEnergys nuclear facililies.Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure)and proceedings related to FirstEnergy's normalbusiness operations pending against FirstEnergy and its subsidiaries. The loss or range of loss in these matters is not expected to be materialto FirstEnergy or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 11,Regulatory Matters ot 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 estimale the amount of such costs. In cases where FirstEnergy determinesthat it is not probable, but reasonably possible that it has a materialobligation, it discloses such obligations and the possible loss or range of loss ifsuch estimate can be made. lf itwere ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based onany 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.NEW ACCOUNTING PRONOUNCEMEI{TSIn May 2014, the FASB issuedASU 2014-09, 'Revenue from Contracts with Customers". Subsequent accounting standards updates have been issued which amend an*Uor clarify the application ofASU 2014-09. The core principle ofthe newguidance isthatan entityrecognizes revenue to depictthe transferof promised goods orservicesto customers in an amountthat reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. More detailed disclosures will also be required toenable users of financialstatements to understandthe nature, amount, timing and uncertaintyol revenue and cash flows arisingfrom contracts with customers. For public business entities, the new revenue recognition guidancewillbe efiective for annual and interim reporting periods beginning atter December 15,2017.

Earlieradoption is permitted lor annualand interim reporting periods beginningafter December 15, 2016. The standards shall be applied retrospectively to each period presented or as a cumulative-effectadjustment as of the date of adoption. FirslEnergy is currently evaluating the impact on its financial statements of adopting these slandards.

In February 2015, the FASB issued ASU 2015-02, "Consolidations: Amendments to the Consolidation Analysis", which amendscurrent consolidation guidance including changes to both the variable and voling interest models used by companies to evaluatewhether an entity should be consolidated. A reporting entity must apply the amendments using a modified retrospective approach byrecording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments retrospectively.

FirstEnergy's adoption ofASU 2015-02, on January 1, 2016, did not result in a change in the consolidation of VlEs by FE or its subsidiaries.

In April2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt lssuance Costs", which requires debt issuancecosts to be presented on the balance sheet as a direct deduction trom the carrying value of the associated debt liability, consistentwith the presentation of a debt discount.

In addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of Debt lssuance CostsAssociated with Line-of-Credit Arrangements', which allows debt issuance cosls related to lineof credii arrangements to be presented as an asset and amortized ratably overthe term of the arrangement, regardless ofwhetherthere are any oulstanding borrowings on the line-of-credit. FirstEnergy adopted ASU 2015-15 and ASU 2015-03 beginning January

'1 ,2016. As of December 31, 2015, FirstEnergy and FES reclassified

$93 million and $17 million of debt issuance cosls included inDeterred charges and otherassets to Long-term debt and Other long-term obligations. FirstEnergy has elected to continue presenlingdebt issuance costs relating to its revolving credit facilities as an asset.In January ot 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall:

Recognition and Measurement of FinancialAssets and Financial Liabilities", which primarily affects the accounting lor equity investments, financial liabilities under the fah valueoption, and ihe presentation and disclosure requirements forfinancial inslruments. In addition, the FASB clarified guidance related to the valuation allowan@ assessment when recognizing deferred tax assets resulting lrom unrealized losses on availablefoFsaledebt securities.

The ASU will be efiective in fiscal years beginning after December 15, 2017, including interim periods within those liscal years. Early adoption lorcertain provisions can be elected for allfinancialslatements offiscalyears and inlerim periods that have not yet been issued orthat have not yet been made available for issuance. FirstEnergy is currently evaluating the impact on itsfinancialstatemenls of adopting this standard.In February 2016, the FASB issuedASU 20'16-02, "Leases (Topic 842)", which will require organizations thal lease assets with leaseterms of more than 12 months to re@gnize assets and liabilities tor the rights and obligations created by lhose leases on theirbalance sheets. In addition, newqualitative and quantitative disclosures ofthe amounts, timing, and uncertainty of cash flovl* arisingfrom leases will be required. TheASU will be etfective for fiscalyears, and interim periods within those fiscalyears, beginning atterDecember 15, 2018, with early adoption permitted.

Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period 102 presented in the adoption-period financialstatements. Any leases that expire before the initial application date will not require anyaccounting adjustment. FirstEnergy is currently evaluating the impact on its tinancial statements of adopting lhis standard.In March of 2016, the FASB issued ASU 2016-09, "lmprovements to Employee Share-Based PaymentAccounting", which simplifiesseveralaspects of the accounling for employee share-based payment. The new guidance willrequire allincome lax effecb of awardsto be recognized in the income statement when the awards vest or are settled. lt also will not require liability accounting when anemployer repurchases more of an employee's shares for tax withholding purposes. The ASU will be etfective for tiscal years, and interim periods within those tiscalyears, beginning atter December 15,2016, with early adoption permitted.

FirstEnergy is currentlyevaluating the impact on its linancial statements ot adopting this standard.

In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instrumenls," which removes all recognition thresholds and will require companies to recognize an allowance for creditlosses for lhe difference between the amortized cost basis of a financial instrument and the amount ot amortized cost that thecompany expects to collect over the instrument's contractual lite. The ASU is effective for fiscal years, and interim periods withinthose fiscal years, beginning after December 15, 2019. Early adoption is permitted for fiscal years beginning atter Decembel 15,2018. FirstEnergy is currently evaluating the impact on its financial statemenls ol adopting this standard.In August 2016,ihe FASB issued ASU 201615, 'Statement of Cash Flolvs (Topic 230): Classification of Cerlain Cash Receipts and Cash Payments". The standard is intended to eliminate diversity in practice in how certain cash receipts and cash paymenls arc presented and classified in the siatement of cash flows. The guidance is effective lorfiscalyears, and lor interim periods within those fiscalyears, beginning ater December 15, 2017. Early adoption is permitted for all entities. FirstEnergy does not e)pect this ASU tohave a material effect on its financial statements.

In October 2016, the FASB issued ASU 2016-16, " Accounting for Income Taxes: Intra-Entity Asset Transters of Assets Othsr thanInventory." ASU 201Gl6 eliminates the exception for all intra-entity sales of assets othe; than inventory which allows companies iodefer the tax effects of intra-entity asset transfers.

As a result, a reporting entitywould recognize the tax e)pense from the sale oftheasset in the seller's iax jurisdiction when the intra-entity lransfer occurs, even though the pre-tax effects of that transaction areeliminated in consolidation.

Any deferred tax asset that arises in the buyer's iurisdiction would also be recognized atthetime ofthetransfer. The guidance is elfective tor liscal years, and for interim periods within those fiscal years, beginning after December 15,2017. Earlyadoption is permitted andthe modified retospective approach willbe required fortransition to the newguidance, with a cumulative-effect adjustment recorded in retained eamings as of the beginning of the period of adoption.

FirstEnergy is currenllyevaluating the impact on its financial statemenls of adopting this standard.

Additionally, during 2016, the FASB issued the tollowing ASUS:. ASU 2016-05, 'Effect ot Derivative Contracl Novations on Existing Hedge Accounting Relationships,". ASU 2016-06, 'Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging lssues Task Force),". ASU 2016-07, 'Simplifying the Transition to the Equity Method ol Accounting,'and. ASU 2016-17, 'Consolidation Cfopic 8'10): Interests Held through Related Parties That Are under Common Control." FirslEnergy does not expect these ASUS to have a material effect on its financial statements.

103 FIRSTENERGY SOLUTIONS CORP.MANAGEIIENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONSFES is awholly owned subsidiary of FE. FES provides energy-related products and servicesto retailand wholesale cuslomers, andthrough its principal subsidiaries, FG and NG, owns or leases, operates and maintains FirstEnergy's fossil and hydroelectric generation facilities (excluding AE Supply and MP), and owns, through its subsidiary NG, FirstEnergy's nuclear generation facilities.

FENOC, a wholly owned subsidiary of FE, operales and mainlains the nuclear generating facilities.

FES purchasesthe entireoutputof the generation facilities owned by FG, NG and AE Supply, as well as the output relating to leasehold interests of OE and TE inBeaver Valley Unit 2 which remains subject to sale and leaseback arrangements, and pursuantto fulloutput, cost-of-service PSAS.FES'revenues are derived prjmarily from sales to individual retail customers, sales to customers in the form ol governmental aggregation programs, and participation in atliliated and non-affiliated POLR auctions. FES'salesare primarily concentrated in Ohio, Pennsylvania, lllinois, Michigan, New Jersey and Maryland. The demand tor electricity produced and sold by FES, along with the price of that electricity, is principally impacted by conditions in competitive power markels, global *conomic activity as well aseconomic activity and weather conditions in the Midwest and Mid-Atlantic regions ol the United States.

As part of FirstEnergy's long-term strategy to be a lully regulated utility, FirstEnergy has begun a strat*gic review of its compelitiveoperations focused on the sale of gas and hydroelectric units as well as exploring all allernatives lor the remaining generation asseb at FES andAE Supply. These include, but are not limited lo,legislative efiorts to convert generation from competilive operations to a regulated or regulatediike construct such as a regulatory restructuring in Ohio, offering generation into any prccess designed toaddress MP's generation shortfall included in its lRe and/or a solution for nuclear generation that recognize their environmentalbenefits. Management anticipales that the viability ol these ahernatives will be determined in the near term with a taryet to implemefithese strategic options within the next 12 to 18 months and could result in material asset impairments.Based on current market forwards, FES expects to have more than sulficient cash flow from operations in 201 7 and 201 8 to fund anticipated capital ependitures with no equity contributions from FirstEnergy. However, in addition to eposure to market price volatility and operationalrisks, FES faces significant financialrisks that could impact its anticipated cash flowand liquidity including,but not limited to, the following:

Requests to post additional collateral or accelerated payments of up to $355 million resulting from current credit ratings atFES, including Moody's downgrade of the Senior Unsecured debt rating for FES to Caal as wellas S&P's downgrade of theSenior Unsecured debt rating at FES to B, both of which occurred on November 4,2016.Adverse outcomes in the previously disclosed disputes regarding long-term coaltransportation contracts.

The inability to extend or refinance debt maturities at FES subsidiaries in 2017 and 2018 of $130 million and

$515 million, respectively.A sig nificant collateral callor the inabitity to refinance 2017 debt maturities at FES subgidiaries is expected to be addressed by FESthrough a combination of cash on hand, additional capiial expenditure reductions, asset sales, and/or bormwings under theunregulaled money pool. However, adverse outcomes in the coal transportation contracb disputes, the inability to refinance 2018 debt maturilies, or lack of viable alternative strategies could cause FES to take one or more of the following actions: (i) restructuringof debt and other financial obligations, (ii) additional borrowings under the unregulated money pool, (iii) further assei sales oI plantdeactivations, and/or (iv) seek protection under bankruptcy laws. In the event FES seeks such proteclion, FENOC may similarly seek plotection under bankruptcy laws.Materialasset impairments resulting from the sale ordeactivation otgeneration assets orfrom a determlnation bymanagementof itsintent to exit competitive generation assets before the end of their estimated useful life resulting trom lhe inabilily to implement alternative strategies discussed above, adverse judgments or a FES bankruptcytiling could result in an event of default undervariousagreements related to the indebtedness of FES.During this period oltransition, subject to strategic decisions regarding competitive generation assets, it is anticipated that FES will produce or purchase from afliliates approximately 70 to 75 million MWHS ot electricity annually, with up to an additional live millionMWHs availabletrom purchased power agreements forwind, solar, and FES'entitlemern inOVEC. In 2017 and 2018 FES expectstohedge 75% - 85% of itsgeneration output by targeting approximalely 50 to 65 million MWHs in annualcontract sales and maintainingup to 25 million MWHS as reserve margin. Forthe period October 1, 2016 to Dgcember 31, 2016, FES'committed sales are 82%hedged against generation supply, including commitled purchases, assuming normalweather conditions. As of September 30, 2016,contractual sales obligations for 2017 and 2018 are approximately 48 million lvlvvHs and 28 million LlWHs, respectively. Contraclualsales obligations for 2016 ar6 approximately 67 million lvlwHs.FES willcontinue to make prudent investments in its nuclear units in order to maintain safe and reliable operations in accordance with nuclear standards, but will continue to focus on costs given current market conditions, specifically surrounding its lossil fleet.104 Management currently anticipates totalcapital expenditures of

$325 million and

$270 million in 2017 and 2018, respectively, which represents a significant reduction from 2016 forecasted capital expenditures ot $490 million.Foradditional information with respectto FES, pl*ase seethe information contained in FirstEnergy's Management's Discussion and Analysis of Financial Condition and Results of Operations under the tollowing subheadings, which intormation is incorporated byreference herein: FirstEnergy's Business, Executive Summary Capital Resources and Liquidity, Guarantees and OtherAssurances,Ofi-Balance Sheet Arrangements, Market Risk Intormation, Credil Risk and Outlook, as well as the information contained in the Forward-Looking Statements and Risk Faclors, which intormation is incorporated by refelence herein.Results of OporatlonsOperating results decreased

$363 million in the first nine months of 2016, compared to the same period of 2015, primarily resulting from charges associated with impairments of goodwill, Units 1-4 of the w. H. Sammis generating station and the Bay Shore Unit 1 generating station, as discussed above, termination and settlement costs on coal contracts, and lower mark-to-market gains oncommodity contract positions.

In addition to these items, operating results were impacted by higher capacity revenues, lower tuelcosts and lower purchased power, partially offset by lowersales volumes and atermination charge associated with a FES customer contract.Revenues -Totalrevenues decreased

$433 million in thefirst nine months of 2016, compared to the same period of2015, primarily dueto lowersales volumes. Revenues were also impacted by higher capacity revenues and higher net gains on financially settled contracts, as further described below The change in total revenues resulted trom lhe following sources: For the Nine Months Ended September 30 Increase Revenues by Type of Service 2016 2015 (Decrease)(ln millions)1,014 802 222 585 410 2,209 1,015 53 124 3,033 558 102 141 (824)457 (4e)(17)3,401 $3,834 $(433)For the Nine Months Ended September 30 MWH Sales by Channel 2016 2015 (Decrease)(ln thousands) 11,391 10,798 1,912 7,526 8,863 8,461 Contract Sales: Direct Govern mental Agg regationMass Market POLR Structured Sales Total Contract Sales Wholesale Transmission Other Total Revenues 610 $666 133 447 353 (404)(136)(8e)(138)(57)Contract Sales:

DirectGovern mental Agg regationMass Market POLR Structured Sales WholesaleTotal MWH Sales NM - Not Meaningful 18,860 12,278 3,246 9,910 9,465 951 (3e.6)%

(12.1)%(41.1)/" (24.1)/" (6.4)%NM 105 48,951 54,710 (10.5)%

The following table summarizes the price and volume factors contributing to changes in revenues in the first nine months of 2016, compared with the same period of 2015: Source of Change in Revenues Increase (Decrease)

MWH Sales Channel: Prices Gain on Settled Contracts Total Sales Volumes Capacity Revenue Direct Govern mental Agg regation Mass Market POLR Structured Sales WholesaleOperating Expenses (401) $(e7)(e1)(140)(26)167 (ln millions)(3) $ $(3e)2 2 (31)42 113 (404)(136)(8e)(138)(57)457 135 Lower sales volumes in Direct, GovernmentalAggregation and Mass Market channels primarily reflects the continuation of FES'strateoy to more efiectively hedge its generation. The Direcl, GovernmentalAggregation and Mass Market customer base was 1.4 million as of September 30,2016, compared to 1.7 million asot September 30,2015. Atthough unit pricing was lower year-over-lrear in the Governmental Aggregation channel, the decrease was primarily attributable to lower capacity epense as discussed below,which is a component of the retail price.The decrease in POLR sales ol $138 million was primarily due to lowervolumes. Structured Sales decreased

$57 million, primarilydue to the impact of lower market prices and lower structured transaction volumes.Wholesale revenues increased

$457 million, primarily due to an increase in capacity revenue trom capaclty auctions, highernet gains on linancially settled contracts and an increase in short-term (net hourty positon) transactions at higher rates. Although wholesaleshort-term transactions increased year-over-year, low average spot maftet energy prbes reduced the economic dispatch of iossil generating units, limiting additional wholesale sales.

Transmission revenue decreased

$49 million, primarily due to lower congestion revenues associated with less volatile market conditions.

Other revenues decreased

$17 million, primarily due to the abgence ofa pre-tax gain on the sale of property to a regulated affiliate inthe second quarter of 2015 and lower lease revenues from the expilation of a nuclear saleleaseback agreement, O@ruting Expenses -Toial operating expenses increased

$63 million in the first nine months of 2016, compared to the same period of 2015.Thetollowing table summarizes the factors contributing to thechanges in fueland purchased power costs in the first nine months of 2016, compared t/uith the same period of 201 5:Source ol Change Increase (Decrease)

VolumesLoss on Settled Prices Contracts Total Gapacity Expense Fossil FuelNuclear FuelAtfiliated Purchased PowerNon-affiliated Purchased Power (e4) $(26)(3e6)(ln millions)(50) $ 70 $3(41) 257 (27) 27$ (74)3 190 (111) (507)Fossil and nuclear fuel costs decreased

$71 million, primarily due to lower generation associated with outages and economicdispatch of fossil units resulting from lowwholesale spot market energy prices, as described above, as well as lower unit prices onfossilfuel contracts. Additionally, fuel costs were impacted by higher settlement and termination costs on coal contracts.

106 Atfiliated purchased power costs increased

$190 million, primarily associated with net gains on settled contracts with AE Supply in2015 resulting from higherwholesale spot ma*et prices in 2015. Effective April1,20'16, FES began lo physically purchase lhe entireoutpul of AE Supplys generation facilities under a cost-of-service PSA.Non-affiliated purchased power costs decreased

$507 million due to lower volumes

($395 million), lower prices ($27 million) and lower capacity expenses

($111 million), partially otbet by higher losses on financially settled purchased power conlracts trom lower wholesale spot maket prices ($27 million). Lotyer volumes primarily resulted trom lower contract sales as discussed above, partiallyoffset by economic purchases resulting lrom lhe low wholesale spot market price environment.

The decrease in capacity expense,which is a component ol FES' retail price, was primarily the result ot lower contract sales and lower capacity lates associated withFES' retail sales obligation.Other operating expenses decreased

$71 million in the first nine months of 2016, compared to the same period of 2015, due to the following:. Nuclear operating costs decreased

$31 million, primarily as a result of lower refueling outag* cosb, partially ofiset by higheremployee beneft costs. There was one refueling outage dudng the lirst nine months of 2016 as compared to two refueling outages during the same period of 2015.. Retirement benefit costs increased $23 million.. Transmission e{censes decreased

$134 million, primarily due to lower congestion and market-based ancillary cosb associated with less volatile market conditions as comoared to the filst nine months of 2015, as well as lo$,cl load requirements.. Other operating expenses increased

$71 million, primarily due to lower mark-temarket gains on commodity contract positions ot $54 million and a

$32 million charge associated with the termination charge on a FES cusbmer cofirilct, parlially oftset by lower retail-related costs.

Depreciation expense increased

$10 million as a result of a higher asset base.General laxes decreased

$'12 million, primarily due to lower gross receipts taxes associated with docreased retail sales volumes.lmpairment of assets increased

$524 million due to the impairment ol goodwill and a decision to exit opsrations of Units 1-4 of the W.H. Sammis generating stalion by May 31, 2020, and the Bay Shore Unit 1 generating station by October 1, 2020.Other Expense -Total other expense decreased

$6,4 million in the first nine months of 2016, compared to the same period of 2015, primarily due tolower OTTI on NDT investments.ln@me Tax Benefr's

-FES'etfective iax rate forthe nine months ended September 30, 2016 and 2015 was 1.87o and 40.0%, respectively. The decrease inthe effective tax rate is primarily due to valuation allowances of

$65 million recorded against slate and local NOL caftyfo]wards thatmanagement believes, more likely than not, will not be realized as wellasthe impairment ol goodwillwhich is non-deductible for tax purposes.ITEII 3. OUAiITITATIVE AND OUALITATIVE DISCLOSURES ABOUT MARKET RISKSee'Management's Discussion andAnalysis of FinancialCondition and Results of Operations - Market Risk Information'in ltem 2 above,ITEM 4. CONTROIS AND PROCEDURES (al Evaluatlon ol Dlsclosurc Controb and Procedurcs The management of FirstEnergy and FES, with lhe participation of each registranfs chief executive otficer and chief financial ofiicer,have reviewed and evaluated the effectiveness ottheir registranfs disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules l3a-15(e) and 15d-15(e), as of the end of the period covered by this report. Based on thatevaluation, the chiet executive ofiicer and chief financial officer of FirstEnergy and FES have concluded that their respectiveregistrant's disclosure controls and procedures were effective as of the end ot the period covered by this report.107 During the quarter ended September 30,2016, there were no changes in internalcontrol overlinancial reportirE that have materially affected, or are reasonably likely to materially affect, FE's and FES' internal control over financial reporling.PART II. OTHER INFORMATION ITEM 1.LEGAL PROCEEDINGSInformation required for Part ll, ltem 1 is incorporated by reference to the discussions in Note 1 1 , Regulatory Matters, and Nole 12,Commitments, Guarantees and Contingencies, ofthe Combined Notes to the Consolidated FinancialStatements in Pan l, ftem 1 of this Form 10-Q.

ITEM 1A.RISK FACTORSYou should carefullyconsiderthe risk factors discussed in "ltem 1A. Risk Factors' in the R*gistrants'Annual Report on Form 10-K for the year ended December 31,2015, which could materially afiect the Registrants' business, financial condition or tuture results. The information set forth in this report, including without limitation, the updated disclosure related to the ESP lV proceodings and the risk factors presented below updates and should be read in conjunction with, the risk factors and information disclosed it the Registlanls'Form 10-K and previously tiled Forms 10-Q.Any Sub*quant Modfflcatlons to, Dental or, or Delay in th6 EffectlveneF,s ot the PUCO'S apryoval of the AsfibulionModemha on Rider could lmpoae slgnlflcant rlsks on HBtEnerW's oryrations and Il/flte alty antt Adverg*,ly lmpactthe Credlt na ngs, Besults ol Operatlons and Flnarrclat Comtltlon ol FhstEnetwOn October 12, 2016, the PUCO denied the Ohio Companies' modified Rider RRS and, in accordance with the PUCO Staff's recommendation, approved a new Distribution Modernization Rider providing forthe collection of

$204 million annually (grossed upfor income taxes) for three years with a possible extension for an additional two years. However, the PUCO'S order approving theDistribution Modernization Rider remains subject to rehearing by the PUCO and appeal to the Supreme Court of Ohio. Any subsequent modification to, denial of, or delay in the etfectiveness ot, the PUCO'S order approving the Distribution ModernizationRidercould impose risks on our operations and materially and adversely impactthe credit ratings, results ot operations and financialcondition of FirstEnergy.Fallurc to Succflastut,y lmptement Sl/?,teglc Altemaltves lor the CES *gmant May Funher l,lagatlvely and Ma'f, atlyImpact tha Future Besuks ol Wrations and Hnanclal Conduon ot HrstE pryy and FES, amt nega.d,l**'s ot thewabltlty or Succsss ol Theg* Stuatrgltc Atonatives, &rbin Events May Slgnlticantty tncreasr Cash Flow aN Liquldlty n/6'ks, and Ulay Cause FES to Take Other Actlons, tnctudlng Debt Restructu ng or *eklng Probctlon under theBanhruptcy Laws, Whlch Coukt nesutt tn Events o, Derautt undet Va ous Agrcements Retated to tl'* lmbbtectness of FE Depressed prices in thewholesale energy and capacity markets continueto challengethe generating unib within the CES segment,including those ol FES. Additionally, because the ESP lV PPA remains suspended, FES will not realize the revenuos originallyintended bythe arrangement, which could have further materialand adverse impacts to the credit ratings, results of operations andfinancial condition of FES.Consequently, as turther discussed in FirstEnergy's Management's Discussion and Analysis of Financial Condition and Results ofOperations and FES'Narrative Analysis of Results of Operations in this Quarterly Report on Form '10-Q, FirstEnergy has begun a strategic review of its competitive operations focused on the sale of gas and hydroelectric units as wellas exploring all altornatives for the remaining generation assets at FES andAE Supply. These include, but are not limitedto, legislative efforts to convert generation lrom competitive operationsto a regulated or regulated-like construct such as regulatory restructuring in Ohio, offering generation into any process designed to address MP's generation shortfall included in its IRE ancuor a solution for nucleargeneration that recognizestheir environmental benefits.

Management anticipates that the viability of these alternatives will be determined in the near term with a target to implement these strategic options within the next '12 to 18 months. No assurance can begiven, however, thatthese stralegic alternatives are viable orwill be achieved or sufficiently realized and even if realized the entities within the CES segment may take substantial write-downs and impairments of assets currently on those companies' balance sheets, which could have a matefialadverse effect on the results of operations and financial condition of FirstEnergy and FES.Additionally, regadless ofthe viability or success of the strategic alternatives for the CES business discussed above, CES, includingFES, faces signilicant cash flow and liquidity risks including, but not limited to the following possibilities:

requests to post additionalcollateral or accelerated payments of up to $355 million resulting from current credit ratings at FES, including Moody's downgrade of the Senior Unsecured debt rating for FES to Caal as well as S&P'sdowngrade of the Senior Unsecured debt rating at FES to B, both of which occurred on November 4,2416;adverse outcomes in previously disclosed disputes regarding longterm coal and coal transportation contracts; and the inability to refinance debt maturities at FES subsidiaries of $130 million, $515 million, and

$323 million in 2017,2018 and 2019, respectively, and $1 55 million in 2019 at AE Supply at attractive rates or at all; 108 Any one of these events or the lack of success implementing the alternatives previously outlined or any other viable businessalternatives could require FES to restructure debt and other financial obligations, bonow additional funds under the unregulated money pool, sell additional assets or deactivate additional plants and/or seek protection under bankruptcy laws. In the event FES seeks such potection, FENOC may similarly seek protection under bankruptcy layvs.Material impairments or charges or adverse judgments or outcomes in ongoing disputes could result in one or more events of deiault undervarious agreements relaled to the indebtedness of FE and FES. Furthemore, a FES bankuptcyfiling would result in one or more events of deiault under various agreements related to the indebtedness of FE. In particular a bankruptcy ol FES would result inthe deconsolidation of FES, which would result in a violation of the debt to total cafitalization ratio covenant under FiFtEnergys credit facilities. lf lhe delaults underthe FirstEnergy's credit facilities are not resolved through waivers or othenflise cured, lenders couldaccelerate the matudty of such debt, and FE would lacksufficient liquidityto pay the accelerated amount in full. Thetailurelo obtainthe waiver or the acceleration of such debt would have a material adverse efiec{ on FirslEnergy's business, financial condition, resulbof operations, liquidity and the trading price of FirstEnergys securilies. No assurance can be given that such waiverswillbe obtainedon satisfactory terms or at all.The CES gEg,rnent ltae a Signiflef,nt Amount ot hldeb'*drrl9E., Which C.ould Adwr5*,ly Afiect FE s an t FES'S Cash Howand Llqudlty and the Ab lty ol the Entltl$ wlthln the CES *g,',ent to Futfill ttt*/lr Obt6atlorc, Whlch CouLt tusult lnan Everrt ot Defutft uttd*r Vadoua Agr**'niF,rts nelabd to the tn(tr,b'*ldr'*rss of FE and Cauc* FES to *k Ptgbctlon undar tll6 Bankrupw Laws The entities within the CES segment have a significant amount of indebtedness, a matedal perceniage of which is secured.spEcifically, as of September 30, 2016, the entiti$ within the CES businEss s6gment had

$3.6 billion (FES: $3 billion; AE supply:

$621 million) of outstanding long-term debt, of which approximately

$836 miltion (FES: $620 million; AE Supply:

9216 million) issecur*d and approximably

$2.8 billion (FES: $2.4 billion; AE Supply:

$405 million) b unsecuGd.

As a resull ofthis debt, a substantial portion of cash flow from the operations of CES must be used to malG payments on this debt, including the payment of principal and interest. Furthermore, since a material peroentage of the CES assets are used to secure thisdebt, this reduces the amount of collateral that is available for future secured debt or credit support and leduces FirstEnergy's andFES'fleibility in dealing with future liquidity needs or financial difficulties.

This high level of indebtedness and related collateral pledges could have other adverse consequences to FES creditors, including:. difiiculty satisfying debt seMce and other obligations at FES and/or its individual subsidiaries;. the inability to refinance debt maturities at FES subsidiaries of

$130 million, $515 million, and $323 million in 2017, 2018 and 2019, respoctivsly, and $155 million in 2019 at AE Supply at atbactive rates or at all;. the inability to exend or refinance on comparable terms the FES/AE Supply revolving credit facility, which epkes in March of 201 9:. a credit rating downgrade ol FES debl, which could cause luture debt costs and/or payments to increase and consumean even greater portion of cash flow and require additional posting ot collateral or acceleration of paymefis of up to$355 million;. increasing the vulnerability of the business ol FirstEnergy ard CES, including FES, to general adverse industry andeconomic conditions:. reducing the availability ol FES and AE Supply cash flow to fund oher corporate purposes, including the ability to paydividends to FirstEneryy;. limiting flexibility of FirstEnergy and the CES business, including FES, in planning for, or reacting to, changes in theirbusiness and the induslry;. placing FirstEnergy and the CES business, including FES, at a compelitive disadvantage to iis competitors that are notas highly leveraged; and. limiting, along with the financial and other restdctive covenants relating to such indebtedness, among other things, FE'sand the CES business', including FES, ability to borrow additional funds as needed, take advantage of businessopportunities as lhey arise or pay cash dividends.ll market conditions in the wholesale energy and capacity markets continue to be depressed and the CES strategy disqJssed inFirstEnergy's Management's Discussion and Analysis of FinancialCondition and Resdb of Operations ald FES'S Narrative Analysb of Results of Operations in this Quartedy Report on Form '10-Q and the above risk fac'tor is not viable, achieved or sufficiently realized, then lhe cash flows ofthe CES segment may not be sufiicient to fund debt service obligations, including the repayment at matudty all of the outstanding debt as it becomes due.

In that event, the CES segment, including FES, may not be able to borrow money, sell assets, raise equity or otherwise raise funds on acceptable terms or at all to refinance its debt as it becomes due, which could have a material adverse elfect on the results of operations, financial condition and liquidity of FirstEnergy and FES, result inone or more evenb of default being declared under various agreements related to the indebtedness ol FirstEnergy and FES and cause FES to seek prolection under the bankruptcy laws.Additionalu if any potential defaulb at FirstEnergy orthe CES segment are not resolved through waivers orotherwisecured,lenderscould accelerate the maturity of the applicable debt.

These defaufts would create uncertainty associated with the repayn'lent of 109 outstanding FE-related long-term debt obligations as they become due and would have a material adverse efiect on FirstEnergy's business, financial condition, results of operations, liquidity and the trading price of FirstEnergy securities.ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS (c) The table below sets forth intormation on a monthly basis regarding FirstEnergy's purchases of its common stock during the third quarter of 2016: PeriodTotal Number of Shares Purchased(l)Average Price Paid per Share Total Number of Shares PurchasedAs Part of Publicly Announced Plans or Programs(z)

Maximum Number (or Approximate Dollar Value) of Shares that May YetBe Purchased Under the Plans or Programs July 1-31 , 2016August 1-31 , 2016 September 1-30,2016 Third Quarter$1,782 $20$32.44 32.52 1,802 $32.44 (1) Share amounts reflect shares that were surrendered to FirstEnergy by a panicipant under our 2007 Inceniive Plan to satisfy tax wilhholdingobligations relating to the vesting of a restricted stock award and the subsequenl dividend reinvestmenb on such Equily award. The totalnumberol shares repurchased represents lhe net shares surrendered lo FirstEnergy to satisfy tax withholding. All such repurc+rased shar*a are now heldas [easury snares.(a FirstEnergy do*s not currenlly have any publicly announced plan or program for share purchases.

ITEM 3.NoneITEM 4.Not Applicable ITEM 5.None DEFAULTS UPON SENIOR SECURITIES MINE SAFETY DISCLOSURES OTHER INFORMATION 110 ITEM 6. EXHIBITSExhibit Number FirstEnergy (A) 12 (A) 31,1 (A) 31.2 (A) 32 101 FES4.1 Fifth Supplemental Indsnture, dated as of Auoust 15, 2016, to Open-End Mortoage, General Mongage Indenture andDeed oftrust, dated as ol June 1, 2009, by and between Fi6tEneroy Nuclearcaneration, LLC and The Bank ol NewYork Mellon Trust Company. N.A.;as truste* (incorporated herein ty reterence to FES' Form 8-K liled Augusl 18, 2016,Exhibit 4.1, File No.

000-53742).4.11a) Form of First l\,longage Bonds, GuarantEe Ssries F of 2016 due 2035 (incorporated herein by refgrerrce lo FES'Form 8-K filod August 18, 2016, Exhibit 4.1(a), File No. 000-53742)(included in Exhibit 4.1).

4.1(b) Form ot Filst Mongage Bonds, Guarantee Series G ol 2016 dus 203ii (incorporaled herein by relerence to FES' Form 8-K tiled Augusl 18, 2016: Exhibit 4.1(b), File No.

oo0-53742)(includEd in Eihibit 4.l ).4.2 Eighth Supplemental Indenture, dated as ol August

,l5. 2016, to Open-End Mortgage. Gener4 Molgage Ind*nlure andDeed of Tiust, dated as ol June 19, 2008, by aid between FirstEnbrgy Generation; LLC and Tho Bank ol New YorkMellon Trust Company, N.A. (lomerly knowir as ThE Bank ol New Yori Trust Company, N.A.), as truslee (incoForated herein by relersnie td FES Form 8-K fibd August 18, 2o'16. Exhibit 4.2, File No, 00G53742).

4.2lal Form ol Firsl Modgage Bonds, Guarantee Series I ol2016 due 2028 (incorporaled herein by relerence to FES' Form &K liledAugusl 18, 2016, Exhibil 4.2(a), File No.

000-53742xincluded in Exhibit 4.2).

4.2(b) Form ol Firsl Mortgaoe Bonds, Guaranlee Series J ol 2016 due 2029 (incorporat*d herein by reference to FES' Fom 8-Kfiled August 18, 2016, Exhibil 4.2(b), File No.

000-53742xincluded in Exhibil 4.2).4,21c) Form ol First l\,lortgage Bonds. Guaranl88 Series K of 2016 due 2047 (incorporated herein by rEl*rence to FES' Form 8-K

' filed August 18, 2o-16: Exhibir 4.2(c), File No. ooGssT42xincluded in Exhibit 4.2).4.2(d) Form ol First l\,lortgags Bonds, Guarantee Sgries L of 2016 due 2028 (incorporated herein by refer*rrce lo FES' Form 8-Kfiled August 18,2016, Exhibit 4.2(d), File No.

000-53742)(included in Exhibil4.2).(A) 10.'l Nolice of Borrower Sublimit Beduction Negalive Consenl, datod as ol August 30. 20'16, to the Credil Agreement, dalgd asof June 17, 2011, as amended as ol Octob'er 3, 2011, Mai 8, 2012, May 6, 2013, Octob*r 31. 2013 and March 31, 2014,amonq FirslEnerov Solutions Com. and Alleohenv Enerqi suDolv com'Panv, LLc, as borrowers, and JPMorgan chase Bank,-N.A., as adininistrative ageht. and the-lending baiks, lrbhting bairks'and swing line lenders idenlifed ther*in.(A) 31.1 Certification ot chief executive oflicer, as adopted pursuant to Rule 13a-14(a)(A) 31.2 C*rtification ol chief financial oflicer, as adopted pursuanl to Rule 13a-14(a)(A) 32 Cenification ol chigf BxecutivE olticer and chief linancial otficer, pursuant to 18 U.S.C. Section 1350101 Ths lollowino materials from the Ouaderlv Reoort on Form 104 of FirstEn*roy Solutions Corp. tor the period endedSept*mber 3-0,2016, formatted in XBRL (Eilensible Business Reporting Languag-B);(i) Consolidated Statements of Income (Ldss) and Coinprehensive Income (Losi), (ii)

Consolidated Baldnc* Sleets, (iii) Coir'solidatsd Statements of Cash Flows, (iv) relat*d notes to th*6e linancial statements and (v) document and entity inlonnation.(A) Provided herein in electronic lormat as an exhibit.

Pursuant to paragraph (b)(axiiiXA) ot ltem 601 of Regulation S-K, neither FirstEnergy nor FES have liled as an exhibil to this Form'10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% ol its respective total assets, but each hereby agrees to furnish to the SEC on request any such documenls.

Fixed charge ratio Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)

Certification of chief financial off icer, as adopted pursuant to Rule 13a-14(a)Gertification of chiel executive officer and chief financialofficer, pursuant to 18 U,S,C. Section 1350The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended September 30,2016, formatted in XBRL (Extensible Bu6ineds Reporting Language): (i)Consolidated Statements of Incom^e (Loss) and Consblidated Statements df Comprenensive Incom6 llos$, (ii) eonSoiiddfed Balance Sheets, (iii) Consolidated Statements ofCash Flows, (iv) related notes to these financialstatements and (v) document and entity information.

111 SIGNAIURES Pursuant to the requirements of the Securities bahange Act of 1934, each Regisirant has duly caused this report to be signed on ibbehalf by the undersigned thereunto duly authorized.November 4, 2016FIRSTENERGY CORP.

RegistrantFI RSTENERGY SOLUTIONS CORP.RegistrantlslK. Jon Taylor K. Jon TaylorVice President, Controllerand Chief Accounting Officer 112 Exhibit NumberEXHIBIT INDEX Fixed charge ratio Certification o{ chief executive officer, as adopted pursuant to Rule 13a-14(a)Certification ol chief financial officer, as adopted pursuant to Rule 13a-14(a)Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C, Section 1350The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended September 30,2016, formalted in XBRL (Extensible Buiineds Reporting Language): (i) Consolida'ted Stateinents of Incom_e (Loss) andConsolidated Statements o'f Comprehensive Incomd (Losi), (ii) don5oliddied Balance Shee-ts, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements and (v) document and entity information.

FirstEnergy (A) 12 (A) 31.1 (A) 31.2 (A) 32 101 FES4.1 Fifth Suoolemental lndenlure. dated as ol Auoust 15. 2016. to Ooen-End Mortqaoe. General l\4on0a0e Indenture andDeed oftrust, daled as of Juhe 1, 2009, bv a-nd between FirstEnBrgy Nuclearcaneration, LLC ani, The Bank of NewYork l\rgllon Tiust Company. N.A.. as trust6e (incorporated herein ty relerence to FES' Form 8-K liled Augusl 18, 2016,Exhibit 4.1, File No. 000-53742).

4.1(a) Form ol First Mortoaoe Bonds. Guarantee Series F of 2016 due 2035 (incorporaled h*rein by relefence lo FES' Form 8-K' liled Auoust 18, 2016: Exhibit 4.1(a), File No.

000-53742)(included in Exhibii 4.1).

4.1(b) Form ol First l\,lodgage Bonds, Guarantee Series G ol 2016 due 2033 (incorporatsd herein by ref*rgnce lo FES' Form 8-Ktiled August 18, 2016, Exhibil 4.1(b), File No.

000-53742)(includod in Exhibil 4.1).4,2 Eiohth SuoDlemenlal lndenture. daled as olAuousl 15. 2016. to Ooen-End Mortoaoe. General Mortoao8 Indenture andD;ed of Tiist, dated as ol Juns 19, 2008, by a;d between FirstEnbrgy Generation;Llc and The Bank ol New YorkMellon Trust Company, N.A. (fomdrly knorvir as The Bank of New Ydrk Trust Company. N.A.), as lrustee (incoForated her*in by r*lersnce to FES'Form 8-K filed August 18, 20'16, Exhibit 4.2, Fils No. 000-53742), 4'2lal Form of First Monoaqe Bonds. Guarantee Series I ol2016 due 2028 (incorporat*d hersin by reference to FES'Form 8-K' filed August 18, 20-16: Exhibir 4.2(a), File No.

000-53742xincluded in Exhibit 4.2).4.2(b) Form of First Mongage Bonds, cuarantee Series J o12016 due 2029 (incorporated herein by r8ference to FES'Fom 8-Kfiled Augusl 18, 2016, Exhibit 4.2(b), File No.

000-53742xincluded in Exhibit 4.2).4.2G1 Form of First Mortoaoe Bonds. Guarant** Series K of 2016 due 2047 (incomorated herein by refererrce lo FES'Form 8-K

' liled August 18, zoi 6: Exhibit 4.2(c), File No. 000-53742)(included in Exhibit a.2).4.2ldl Form ol First Mortoaoe Bonds. Guarantee Series Lof 2016 dug 2028 (incomorated hsr*in by refer*nce to FES'Form 8'K' liled August 't 8, 2016; Exhibir 4.2(d), File No, ooo-53742)(included in Exhibii 4.2).(A) 10.1 Noticg ol Borrowsr Sublimit R*duction N*gativ* Consenl, daled as ol August 30, 2016, to the Credil Agreemen\ dalgd asol June 17, 2011, as amended as ol Octobier 3, 2011, May 8. 2012, May 6, 2013. Oclober 31, 2013 and March 31, 2014, amonq FirdtEnerAv solutions corD and Alleohenv Enerqi supDlv com-panv, LLc, as borrowers, and JPMorgan chase Bank,-N.A., as adininistrative ageht, and the-lending baiks, frbhtlng bairks'and swing line lenders identified therein.(A) 31.1 Certification of chiel Executivs otticsr, as adopted pursuanl lo Rule 13a-14(a)(A) 31.2 Cenification of chiel linancial ollicer, as adopted pursuanl lo Rule l3a-14(a)(A) 32 Certificalion ol chiel executive otficer and chief finarrcial oflicer.

pursuanl lo 18 U,S.C. Section 1350101 The lollowino materials from the Quadedv Reoorl on Form'to-O of FirstEneroy Solulions Corp, for ihe period endedSeptember 30, 2016, formatted in XBRL (Eitensible Business Reponing tanguag-e): (i) Consolidaled Statements ol Income (Ldss) and Comprehensive Income (Losi), (ii) Consolidated Baldnce Sleeb, (iii) Consolidated Statements of Cash Flows, (iv) relaled noles to these financial statements and (v) document and entity inlormation.(A) Provided herein in electronic lormat as an erhibit.

Pursuant to paragraph (bx4xiiiXA) of ltem 60 l of Regulation S-K, neither FirstEnergy nor FES have tiled as an exhibit to lhis Form 10-Q any instrumentwith respect to long-term debt ifthe respective totalamount of securities authorized thereunder does not exceed10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.

113