UNITED
STATES SECURITIES AND EXCHANGE COMMISSION


Washington,
D. C.  20549





FORM
10-Q


(Mark
One)


[X]  QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE


SECURITIES
EXCHANGE ACT OF 1934





For
the quarterly period ended September 30, 2008





OR





[  ]  TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE


SECURITIES
EXCHANGE ACT OF 1934





For
      the transition period from
            
            to





Commission
            Registrant;
      State of Incorporation;
            I.R.S.
      EmployerFile
      Number
            Address; and Telephone
      Number
            Identification
      No.333-21011
            FIRSTENERGY
      CORP.
            34-1843785(An
      Ohio Corporation)76
      South Main StreetAkron,
      OH  44308Telephone (800)736-3402333-145140-01
            FIRSTENERGY
      SOLUTIONS CORP.
            31-1560186(An
      Ohio Corporation)c/o
      FirstEnergy Corp.76
      South Main StreetAkron,
      OH 44308Telephone
      (800)736-34021-2578
            OHIO
      EDISON COMPANY
            34-0437786(An
      Ohio Corporation)c/o
      FirstEnergy Corp.76
      South Main StreetAkron,
      OH  44308Telephone (800)736-34021-2323
            THE
      CLEVELAND ELECTRIC ILLUMINATING COMPANY
            34-0150020(An
      Ohio Corporation)c/o
      FirstEnergy Corp.76
      South Main StreetAkron,
      OH  44308Telephone (800)736-34021-3583
            THE
      TOLEDO EDISON COMPANY
            34-4375005(An
      Ohio Corporation)c/o
      FirstEnergy Corp.76
      South Main StreetAkron,
      OH  44308Telephone (800)736-34021-3141
            JERSEY
      CENTRAL POWER & LIGHT COMPANY
            21-0485010(A
      New Jersey Corporation)c/o
      FirstEnergy Corp.76
      South Main StreetAkron,
      OH  44308Telephone (800)736-34021-446
            METROPOLITAN
      EDISON COMPANY
            23-0870160(A
      Pennsylvania Corporation)c/o
      FirstEnergy Corp.76
      South Main StreetAkron,
      OH  44308Telephone (800)736-34021-3522
            PENNSYLVANIA
      ELECTRIC COMPANY
            25-0718085(A
      Pennsylvania Corporation)c/o
      FirstEnergy Corp.76
      South Main StreetAkron,
      OH  44308Telephone (800)736-3402











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 Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.





Yes (X)  No (  )
            FirstEnergy
      Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company,
      The Toledo Edison Company, Jersey Central Power & Light Company,
      Metropolitan Edison Company and Pennsylvania Electric
    CompanyYes (  )  No (X)
            FirstEnergy
      Solutions Corp.





Indicate by check
mark whether the registrant is a large accelerated filer, an accelerated filer,
a non-accelerated filer, or a smaller reporting company. See the definitions of
"large accelerated filer,” “accelerated filer” and “smaller reporting company"
in Rule 12b-2 of the Exchange Act.





Large
      Accelerated Filer
              (X)
            FirstEnergy
      Corp.Accelerated
      Filer
              (  )
            N/ANon-accelerated
      Filer (Do not check if a smaller reporting company)
              (X)
            FirstEnergy
      Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating
      Company, The Toledo Edison Company, Jersey Central Power & Light
      Company, Metropolitan Edison Company and Pennsylvania Electric
      Company





Smaller
      Reporting Company
              (  )
            N/A





Indicate by check
mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act).





Yes (  )No (X)
            FirstEnergy
      Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland
      Electric Illuminating Company, The Toledo Edison Company, Jersey Central
      Power & Light Company, Metropolitan Edison Company, and Pennsylvania
      Electric Company





Indicate the number
of shares outstanding of each of the issuer’s classes of common stock, as of the
latest practicable date:





OUTSTANDINGCLASS
            AS
      OF November 6, 2008FirstEnergy
      Corp., $0.10 par value
            304,835,407FirstEnergy
      Solutions Corp., no par value
            7Ohio Edison
      Company, no par value
            60The Cleveland
      Electric Illuminating Company, no par value
            67,930,743The Toledo
      Edison Company, $5 par value
            29,402,054Jersey Central
      Power & Light Company, $10 par value
            14,421,637Metropolitan
      Edison Company, no par value
            859,500Pennsylvania
      Electric Company, $20 par value
            4,427,577





FirstEnergy Corp. is
the sole holder of FirstEnergy Solutions Corp., Ohio Edison Company, The
Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey
Central Power & Light Company, Metropolitan Edison Company and Pennsylvania
Electric Company common stock.





This combined Form
10-Q is separately filed by FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio
Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison
Company, Jersey Central Power & Light Company, Metropolitan Edison Company
and Pennsylvania Electric Company. Information contained herein relating to any
individual registrant is filed by such registrant on its own behalf. No
registrant makes any representation as to information relating to any other
registrant, except that information relating to any of the FirstEnergy
subsidiary registrants is also attributed to FirstEnergy Corp.





OMISSION OF CERTAIN
INFORMATION





FirstEnergy
Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating
Company, The Toledo Edison Company, Jersey Central Power & Light Company,
Metropolitan Edison Company and Pennsylvania Electric Company meet the
conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are
therefore filing this Form 10-Q with the reduced disclosure format specified in
General Instruction H(2) to Form 10-Q.











Forward-Looking Statements:
This Form 10-Q includes forward-looking statements based on information
currently available to management. Such statements are subject to certain risks
and uncertainties. These statements include declarations regarding management’s
intents, beliefs and current expectations. These statements typically contain,
but are not limited to, the terms “anticipate,” “potential,” “expect,”
“believe,” “estimate” and similar words. Forward-looking statements involve
estimates, assumptions, known and unknown risks, uncertainties and other factors
that may cause actual results, performance or achievements to be materially
different from any future results, performance or achievements expressed or
implied by such forward-looking statements.





Actual results may
differ materially due to:


·
            the speed and
      nature of increased competition in the electric utility industry and
      legislative and regulatory changes affecting how generation rates will be
      determined following the expiration of existing rate plans in Ohio and
      Pennsylvania,


·
            the impact of
      the PUCO’s rulemaking process on the Ohio Companies’ ESP and MRO
      filings,


·
            economic or
      weather conditions affecting future sales and
  margins,


·
            changes in
      markets for energy services,


·
            changing
      energy and commodity market prices and
  availability,


·
            replacement
      power costs being higher than anticipated or inadequately
      hedged,


·
            the continued
      ability of FirstEnergy’s regulated utilities to collect transition and
      other charges or to recover increased transmission
  costs,


·
            maintenance
      costs being higher than
anticipated,


·
            other
      legislative and regulatory changes, revised environmental requirements,
      including possible GHG emission
regulations,


·
            the impact of
      the U.S. Court of Appeals’ July 11, 2008 decision to vacate the CAIR
      rules and the scope of any laws, rules or regulations that may ultimately
      take their place,


·
            the
      uncertainty of the timing and amounts of the capital expenditures needed
      to, among other things, implement the Air Quality Compliance Plan
      (including that such amounts could be higher than anticipated) or levels
      of emission reductions related to the Consent Decree resolving the NSR
      litigation or other potential regulatory
  initiatives,


·
            adverse
      regulatory or legal decisions and outcomes (including, but not limited to,
      the revocation of necessary licenses or operating permits and oversight)
      by the NRC (including, but not limited to, the Demand for Information
      issued to FENOC on May 14,
2007),


·
            the timing and
      outcome of various proceedings before the PUCO (including, but not limited
      to, the ESP and MRO proceedings as well as the distribution rate cases and
      the generation supply plan filing for the Ohio Companies and the
      successful resolution of the issues remanded to the PUCO by the Ohio
      Supreme Court regarding the RSP and RCP, including the recovery of
      deferred fuel costs),


·
            Met-Ed’s and
      Penelec’s transmission service charge filings with the PPUC as well as the
      resolution of the Petitions for Review filed with the Commonwealth Court
      of Pennsylvania with respect to the transition rate plan for Met-Ed and
      Penelec,


·
            the continuing
      availability of generating units and their ability to operate at or near
      full capacity,


·
            the ability to
      comply with applicable state and federal reliability
      standards,


·
            the ability to
      accomplish or realize anticipated benefits from strategic goals (including
      employee workforce initiatives),


·
            the ability to
      improve electric commodity margins and to experience growth in the
      distribution business,


·
            the changing
      market conditions that could affect the value of assets held in the
      registrants’ nuclear decommissioning trusts, pension trusts and other
      trust funds, and cause FirstEnergy to make additional contributions
      sooner, or in an amount that is larger than currently
      anticipated,


·
            the ability to
      access the public securities and other capital and credit markets in
      accordance with FirstEnergy’s financing plan and the cost of such
      capital,


·
            changes in
      general economic conditions affecting the
  registrants,


·
            the state of
      the capital and credit markets affecting the registrants,
    and


·
            the risks and
      other factors discussed from time to time in the registrants’ SEC filings,
      and other similar factors.





The foregoing review
of factors should not be construed as exhaustive. New factors emerge from time
to time, and it is not possible for management to predict all such factors, nor
assess the impact of any such factor on the registrants’ business or the extent
to which any factor, or combination of factors, may cause results to differ
materially from those contained in any forward-looking statements. Also, a
security rating is not a recommendation to buy, sell or hold securities, and it
may be subject to revision or withdrawal at any time and each such rating should
be evaluated independently of any other rating. The registrants expressly
disclaim any current intention to update any forward-looking statements
contained herein as a result of new information, future events or
otherwise.

















TABLE
OF CONTENTS











PagesGlossary of Terms
            iii-vPart
      I.     Financial InformationItems 1. and 2. - Financial
      Statements and Management’s Discussion and Analysis ofFinancial Condition
      and Results of Operations.FirstEnergy Corp.Management's
      Discussion and Analysis of Financial Condition andResults of Operations
            1-46Report of
      Independent Registered Public Accounting Firm
            47Consolidated
      Statements of Income
            48Consolidated
      Statements of Comprehensive Income
            49Consolidated
      Balance Sheets
            50Consolidated
      Statements of Cash Flows
            51FirstEnergy Solutions
      Corp.Management's
      Narrative Analysis of Results of Operations
            52-54Report of
      Independent Registered Public Accounting Firm
            55Consolidated
      Statements of Income and Comprehensive Income
            56Consolidated
      Balance Sheets
            57Consolidated
      Statements of Cash Flows
            58Ohio Edison
    CompanyManagement's
      Narrative Analysis of Results of Operations
            59-60Report of
      Independent Registered Public Accounting Firm
            61Consolidated
      Statements of Income and Comprehensive Income
            62Consolidated
      Balance Sheets
            63Consolidated
      Statements of Cash Flows
            64The Cleveland Electric
      Illuminating CompanyManagement's
      Narrative Analysis of Results of Operations
            65-66Report of
      Independent Registered Public Accounting Firm
            67Consolidated
      Statements of Income and Comprehensive Income
            68Consolidated
      Balance Sheets
            69Consolidated
      Statements of Cash Flows
            70The Toledo Edison
      CompanyManagement's
      Narrative Analysis of Results of Operations
            71-73Report of
      Independent Registered Public Accounting Firm
            74Consolidated
      Statements of Income and Comprehensive Income
            75Consolidated
      Balance Sheets
            76Consolidated
      Statements of Cash Flows
            77





i





TABLE
OF CONTENTS (Cont'd)











Jersey Central Power & Light
      Company
            PagesManagement's
      Narrative Analysis of Results of Operations
            78-79Report of
      Independent Registered Public Accounting Firm
            80Consolidated
      Statements of Income and Comprehensive Income
            81Consolidated
      Balance Sheets
            82Consolidated
      Statements of Cash Flows
            83Metropolitan Edison
      CompanyManagement's
      Narrative Analysis of Results of Operations
            84-85Report of
      Independent Registered Public Accounting Firm
            86Consolidated
      Statements of Income and Comprehensive Income
            87Consolidated
      Balance Sheets
            88Consolidated
      Statements of Cash Flows
            89Pennsylvania Electric
      CompanyManagement's
      Narrative Analysis of Results of Operations
            90-91Report of
      Independent Registered Public Accounting Firm
            92Consolidated
      Statements of Income and Comprehensive Income
            93Consolidated
      Balance Sheets
            94Consolidated
      Statements of Cash Flows
            95Combined Management’s Discussion
      and Analysis of Registrant Subsidiaries
            96-111Combined Notes to Consolidated
      Financial Statements
            112-147Item 3. Quantitative
      and Qualitative Disclosures About Market Risk.
            148Item 4. Controls and
      Procedures – FirstEnergy.
            148Item
      4T.          Controls and
      Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and
    Penelec.
            148Part
      II.    Other InformationItem 1. Legal
      Proceedings.
            149Item
      1A.         Risk
      Factors.
            149Item 2. Unregistered
      Sales of Equity Securities and Use of Proceeds.
            149Item 6. Exhibits.
            150

















ii
 GLOSSARY
OF TERMS





The
following abbreviations and acronyms are used in this report to identify
FirstEnergy Corp. and its current and former subsidiaries:





ATSI
            American
      Transmission Systems, Incorporated, owns and operates transmission
      facilitiesCEI
            The Cleveland
      Electric Illuminating Company, an Ohio electric utility operating
      subsidiaryFENOC
            FirstEnergy
      Nuclear Operating Company, operates nuclear generating
      facilitiesFES
            FirstEnergy
      Solutions Corp., provides energy-related products and
    servicesFESC
            FirstEnergy
      Service Company, provides legal, financial and other corporate support
      servicesFGCO
            FirstEnergy
      Generation Corp., owns and operates non-nuclear generating
      facilitiesFirstEnergy
            FirstEnergy
      Corp., a public utility holding companyGPU
            GPU, Inc.,
      former parent of JCP&L, Met-Ed and Penelec, which merged with
      FirstEnergy on
              November 7,
      2001JCP&L
            Jersey Central
      Power & Light Company, a New Jersey electric utility operating
      subsidiaryJCP&L
      Transition
              Funding
            JCP&L
      Transition Funding LLC, a Delaware limited liability company and issuer of
      transition
              bondsJCP&L
      Transition
              Funding
      II
            JCP&L
      Transition Funding II LLC, a Delaware limited liability company and issuer
      of transition
              bondsMet-Ed
            Metropolitan
      Edison Company, a Pennsylvania electric utility operating
      subsidiaryNGC
            FirstEnergy
      Nuclear Generation Corp., owns nuclear generating
    facilitiesOE
            Ohio Edison
      Company, an Ohio electric utility operating subsidiaryOhio
      Companies
            CEI, OE and
      TEPenelec
            Pennsylvania
      Electric Company, a Pennsylvania electric utility operating
      subsidiaryPenn
            Pennsylvania
      Power Company, a Pennsylvania electric utility operating subsidiary of
      OEPennsylvania
      Companies
            Met-Ed,
      Penelec and PennPNBV
            PNBV Capital
      Trust, a special purpose entity created by OE in 1996Shippingport
            Shippingport
      Capital Trust, a special purpose entity created by CEI and TE in
      1997Signal
      Peak
            A joint
      venture between FirstEnergy Ventures Corp. and Boich Companies, that owns
      mining and
              coal
      transportation operations near Roundup, Montana, formerly known as Bull
      MountainTE
            The Toledo
      Edison Company, an Ohio electric utility operating
    subsidiaryUtilities
            OE, CEI, TE,
      JCP&L, Met-Ed and PenelecThe following
      abbreviations and acronyms are used to identify frequently used terms in
      this report:ACO
            Administrative
      Consent OrderAEP
            American
      Electric Power Company, Inc.ALJ
            Administrative
      Law JudgeAMP-Ohio
            American
      Municipal Power-Ohio, Inc.AOCL
            Accumulated
      Other Comprehensive LossARB
            Accounting
      Research BulletinARO
            Asset
      Retirement ObligationASM
            Ancillary
      Services MarketBGS
            Basic
      Generation ServiceCAA
            Clean Air
      ActCAIR
            Clean Air
      Interstate RuleCAMR
            Clean Air
      Mercury RuleCBP
            Competitive
      Bid ProcessCO2
            Carbon
      DioxideDFI
            Demand for
      InformationDOJ
            United States
      Department of JusticeDRA
            Division of
      Ratepayer AdvocateEIS
            Energy
      Independence StrategyEITF
            Emerging
      Issues Task ForceEMP
            Energy Master
      PlanEPA
            United States
      Environmental Protection AgencyEPACT
            Energy Policy
      Act of 2005ESP
            Electric
      Security PlanFASB
            Financial
      Accounting Standards BoardFERC
            Federal Energy
      Regulatory CommissionFIN
            FASB
      InterpretationFIN
      46R
            FIN 46
      (revised December 2003), "Consolidation of Variable Interest
      Entities"





iii
 GLOSSARY
OF TERMS, Cont’d.





FIN
      47
            FIN 47,
      "Accounting for Conditional Asset Retirement Obligations - an
      interpretation of FASB
              Statement No.
      143"FIN
      48
            FIN 48,
      “Accounting for Uncertainty in Income Taxes - an interpretation of FASB
      Statement
              No.
      109”FMB
            First Mortgage
      BondFTR
            Financial
      Transmission RightsGAAP
            Accounting
      Principles Generally Accepted in the United StatesGHG
            Greenhouse
      GasesIRS
            Internal
      Revenue ServiceISO
            Independent
      System OperatorkV
            KilovoltKWH
            Kilowatt-hoursLIBOR
            London
      Interbank Offered RateLOC
            Letter of
      CreditMEIUG
            Met-Ed
      Industrial Users GroupMEW
            Mission Energy
      Westside, Inc.MISO
            Midwest
      Independent Transmission System Operator, Inc.Moody’s
            Moody’s
      Investors ServiceMRO
            Market Rate
      OfferMW
            MegawattsNAAQS
            National
      Ambient Air Quality StandardsNERC
            North American
      Electric Reliability CorporationNJBPU
            New Jersey
      Board of Public UtilitiesNOV
            Notice of
      ViolationNOX
            Nitrogen
      OxideNRC
            Nuclear
      Regulatory CommissionNSR
            New Source
      ReviewNUG
            Non-Utility
      GenerationNUGC
            Non-Utility
      Generation ChargeNYMEX
            New York
      Mercantile ExchangeOCA
            Office of
      Consumer AdvocateOTC
            Over the
      CounterOVEC
            Ohio Valley
      Electric CorporationPCRB
            Pollution
      Control Revenue BondPICA
            Penelec
      Industrial Customer AlliancePJM
            PJM
      Interconnection L. L. C.PLR
            Provider of
      Last ResortPPUC
            Pennsylvania
      Public Utility CommissionPRP
            Potentially
      Responsible PartyPSA
            Power Supply
      AgreementPUCO
            Public
      Utilities Commission of OhioPUHCA
            Public Utility
      Holding Company Act of 1935RCP
            Rate Certainty
      PlanRECB
            Regional
      Expansion Criteria and BenefitsRFP
            Request for
      ProposalRPM
            Reliability
      Pricing ModelRSP
            Rate
      Stabilization PlanRTC
            Regulatory
      Transition ChargeRTO
            Regional
      Transmission OrganizationS&P
            Standard &
      Poor’s Ratings ServiceSB221
            Amended
      Substitute Senate Bill 221SBC
            Societal
      Benefits ChargeSEC
            U.S.
      Securities and Exchange CommissionSECA
            Seams
      Elimination Cost AdjustmentSFAS
            Statement of
      Financial Accounting StandardsSFAS
      133
            SFAS No. 133,
      “Accounting for Derivative Instruments and Hedging
    Activities”





iv
 GLOSSARY
OF TERMS, Cont’d.








SFAS
      142
            SFAS No. 142,
      “Goodwill and Other Intangible Assets”SFAS
      143
            SFAS No. 143,
      “Accounting for Asset Retirement Obligations”SFAS
      157
            SFAS No. 157,
      “Fair Value Measurements”SFAS
      159
            SFAS No. 159,
      “The Fair Value Option for Financial Assets and Financial Liabilities –
      Including an
              Amendment of
      FASB Statement No. 115”SIP
            State
      Implementation Plan(s) Under the Clean Air ActSNCR
            Selective
      Non-Catalytic ReductionSO2
            Sulfur
      DioxideTMI-1
            Three Mile
      Island Unit 1TMI-2
            Three Mile
      Island Unit 2TSC
            Transmission
      Service ChargeVIE
            Variable
      Interest Entity





v





PART I. FINANCIAL
INFORMATION





ITEMS
1. AND 2. FINANCIAL STATEMENTS AND MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS.





FIRSTENERGY
CORP.





MANAGEMENT’S
DISCUSSION AND ANALYSIS OF


FINANCIAL
CONDITION AND RESULTS OF OPERATIONS





EXECUTIVE
SUMMARY





Net income in the
third quarter of 2008 was $471 million, or basic earnings of $1.55 per share of
common stock ($1.54 diluted), compared with net income of
$413 million, or basic earnings of $1.36 per share of common stock
($1.34 diluted) in the third quarter of 2007. Net income in the first nine
months of 2008 was $1.01billion, or basic
earnings of $3.32per share of common
stock ($3.29diluted), compared with
net income of $1.04 billion, or basic earnings of $3.39 per share of common
stock ($3.35 diluted) in the first nine months of 2007.





Three
      Months
            
            Nine
      MonthsChange
      in Basic Earnings Per Share
            
            Ended
            
            EndedFrom
      Prior Year Periods
            
            September
      30
            
            September
      30Basic Earnings
      Per Share – 2007
            
            $
            1.36
            
            $
            3.39Gain on
      non-core asset sales – 2008/2007
            
            
            (0.04
            )
            
            0.02Litigation
      settlement – 2008
            
            
            -
            
            
            0.03Saxton
      decommissioning regulatory asset – 2007
            
            
            -
            
            
            (0.05
            )Trust
      securities impairment
            
            
            (0.05
            )
            
            (0.09
            )Revenues
            
            
            0.57
            
            
            1.36Fuel and
      purchased power
            
            
            (0.34
            )
            
            (1.16
            )Depreciation
      and amortization
            
            
            (0.02
            )
            
            (0.07
            )Deferral of
      new regulatory assets
            
            
            (0.10
            )
            
            (0.23
            )Investment
      Income – decommissioning trusts
              and
      corporate-owned life insurance
            
            
            0.04
            
            
            (0.05
            )Income tax
      adjustments
            
            
            0.12
            
            
            0.12Other expense
      reductions
            
            
            0.01
            
            
            0.02Reduced common
      shares outstanding
            
            
            -
            
            
            0.03Basic Earnings
      Per Share – 2008
            
            $
            1.55
            
            $
            3.32







Recent
Market Developments
 
 In
response to the recent unprecedented volatility in the capital and credit
markets, FirstEnergy continues to assess its exposure to counterparty credit
risk, its access to funds in the capital and credit markets, and market-related
changes in the value of its postretirement benefit trusts, nuclear
decommissioning trusts and other investments. FirstEnergy has taken
several  steps to strengthen its liquidity position and provide
additional flexibility to meet its anticipated obligations and those of its
subsidiaries. While FirstEnergy believes its existing sources of liquidity will
continue to be available to meet its anticipated obligations, management is
reviewing its 2009 plans to determine what adjustments should be made to
operating and capital budgets in response to the economic climate to reduce the
need for external sources of capital. Although this process is not yet complete,
management expects that FirstEnergy's capital expenditures will be reduced from
the levels previously anticipated; however, it expects to continue to meet
commitments for required capital projects and necessary operational
expenditures.
 Liquidity
 
 FirstEnergy has
access to more than $4 billion of liquidity, of which approximately
$1.9 billion was available as of October 31, 2008. FirstEnergy and its
subsidiaries have approximately $404 million available under a $2.75
billion revolving credit facility, with no one financial institution having more
than 7.3% of the total commitment. An additional $1.1 billion was available
through other commitments including: bank credit facilities totaling
$420 million; a $300 million term loan with Credit Suisse, discussed below;
and $550 million of accounts receivable financing facilities. FirstEnergy
had $456 million of cash and cash equivalents as of October 31,
2008.
 FirstEnergy’s
currently payable long-term debt includes approximately $2.1 billion of
variable-rate PCRBs. The interest rates on these PCRBs are reset daily or
weekly. Bondholders can tender their PCRBs for mandatory repurchase prior to
their maturity with the purchase price payable from remarketing proceeds or, if
the PCRBs are not successfully remarketed, by drawings under irrevocable direct
pay LOCs. Prior to September 18, 2008, FirstEnergy had not experienced any
unsuccessful remarketings of these variable-rate PCRBs.


1





Coincident with
recent disruptions in the variable-rate demand bond and capital markets
generally, certain of the PCRBs have been tendered by bondholders to the
trustee. As of October 31, 2008, $72.5 million of the PCRBs, all of which are
backed by Wachovia Bank LOCs, had been tendered and not yet successfully
remarketed. Of these, draws on the applicable LOCs were made for $72.4 million,
all of which Wachovia honored. The reimbursement agreements between the
subsidiary obligors and Wachovia require reimbursement of outstanding LOC draws
by March 2009.





As a further
safeguard in the event of future draws on these LOCs, in early October 2008
FirstEnergy negotiated with the banks that have issued the LOCs to extend the
term of the respective reimbursement obligations. Approximately $902 million of
LOCs that previously required reimbursement of LOC draws within 30 days or less
were modified to extend the reimbursement obligations to six months or June
2009, as applicable.





FirstEnergy also
enhanced its liquidity position during this period of turmoil in the credit and
capital markets by securing, on October 8, 2008, a $300 million secured term
loan facility with Credit Suisse. Under the facility, FGCO is the borrower and
FES and FirstEnergy are guarantors. Generally, the facility is available to FGCO
until October 7, 2009, with a minimum borrowing amount of $100 million and with
repayment due 30 days after the borrowing date subject to extension at the end
of each quarter until two days after the release of results of operations.
Advances under the facility are not available for re-borrowing after they are
repaid.





Access to the
capital markets and costs of financing are influenced by the ratings of the
securities of FirstEnergy and its subsidiaries. On August 1, 2008, S&P
changed its outlook for FirstEnergy and its subsidiaries from “negative” to
“stable.” Moody’s outlook for FirstEnergy and its subsidiaries remains “stable.”
The credit ratings of FirstEnergy or its subsidiaries also govern the collateral
provisions of certain contract guarantees. Subsequent to the
occurrence of a credit rating downgrade to below investment grade or a “material
adverse event,” the immediate posting of cash collateral may be required. As of
September 30, 2008, FirstEnergy’s maximum exposure under these collateral
provisions was $573 million, consisting of $64 million due to “material adverse
event” contractual clauses and $509 million due to a below investment grade
credit rating. Stress case conditions of a credit rating downgrade or “material
adverse event” and hypothetical adverse price movements in the underlying
commodity markets would increase this amount to $648 million, consisting of $58
million due to “material adverse event” contractual clauses and $590 million due
to a below investment grade credit rating. FirstEnergy’s revolving credit
facility does not contain provisions that either restrict the ability to borrow
or accelerate repayment of outstanding advances as a result of any change in
these credit ratings although a change in credit rating could increase
FirstEnergy’s cost of borrowing. FirstEnergy does not anticipate current market
conditions to result in any events that will result in posting additional
collateral or that will impact its ability to remain in compliance with its debt
covenants.





Long-Term Financing





On October 20, 2008,
OE issued $300 million of FMBs, comprised of $275 million 8.25% Series of
2008 due 2038 and $25 million 8.25% Series of 2008 due 2018. OE will use
the net proceeds from these offerings to fund capital expenditures and for other
general corporate purposes. CEI, TE and Met-Edeachhave regulatory
authority to issue up to $300 million of long-term debt, and requests are
pending before the NJBPU and PPUC for authority to issue up to an aggregate $400
million of additional utility long-term debt. FirstEnergy intends to execute
these long-term financings as it deems appropriate and as market conditions
permit.





Counterparty Credit Risk





FirstEnergy and its
subsidiaries are subject to credit risk, which relates to the ability of
counterparties to meet their contractual payment obligations or the potential
non-performance of counterparties to deliver contracted commodities or services
at the contracted price. FirstEnergy routinely performs counterparty risk
evaluations including monitoring of credit default spreads of counterparties,
monitors portfolio trends and uses collateral and contract provisions to
mitigate exposure. Recent market events including, but not limited to, the
default of Lehman have resulted in a more stringent approach to counterparty
credit evaluations resulting in a decrease in the number of approved
counterparties. FirstEnergy’s subsidiaries have long-term power and coal
contracts with certain counterparties that, in the event of the counterparty’s
default, would likely be replaced with contracts having less favorable terms
that may negatively impact financial condition and results of operations.
FirstEnergy has reviewed its insurance coverage and believes that the
availability and cost of liability, property, nuclear risk and other forms of
insurance have not been materially impacted by recent events, but will continue
to monitor the events and ratings of the companies which provide insurance
coverage for FirstEnergy and its subsidiaries.





Investments





Despite recent
declines in the value of FirstEnergy’s pension plan investments, contributions
to the plan will not be required in 2009. The overall actual investment return
as of October 31, 2008 was a loss of 25.4% compared to an assumed 9% positive
return. Based on an 8% discount rate assumption, if the ultimate return for 2008
was to remain at a loss of 25.4%, 2009 pre-tax net periodic pension expense
would be approximately $145 million, an increase of approximately $180 million
compared to the year 2008. If the ultimate return for 2008 was to remain at a
loss of 25.4%, FirstEnergy would also not be required to make contributions in
2010. However, if assets were to decline an additional 1% from October 31,
2008 through the end of 2008, contributions of approximately $65 million would
be required in 2010.





2





This information
does not consider any actions management may take to mitigate the impact of the
asset return shortfalls, including changes in the amount and timing of future
contributions. The actuarial assumptions used in the determination of pension
and postretirement benefit costs are interrelated and changes in other
assumptions could have the impact of offsetting all or a portion of the
potential increase in benefit costs set forth above.





Nuclear
decommissioning trust funds have been established to satisfy NGC’s and the
Utilities’ nuclear decommissioning obligations. As of September 30, 2008,
approximately 47% of the funds were invested in equity securities and 53% were
invested in fixed income securities, with limitations related to concentration
and investment grade ratings.





The decommissioning
trusts of JCP&L and the Pennsylvania Companies are subject to regulatory
accounting, with unrealized gains and losses recorded as regulatory assets or
liabilities, since the difference between investments held in trust and the
decommissioning liabilities will be recovered from or refunded to customers.
NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale
securities held in their nuclear decommissioning trusts. Nuclear
decommissioning trust securities impairments totaled $63 million in the first
nine months of 2008. FirstEnergy does not expect to make additional cash
contributions to the nuclear decommissioning trusts in 2009, other than the
required annual TMI-2 trust contribution that is collected through customer
rates. However, should the trust funds continue to experience declines in market
value, FirstEnergy may be required to take measures, such as providing financial
guarantees through letters of credit or parental guarantees or making additional
contributions to the trusts to ensure that the trusts are adequately funded and
meet minimum NRC funding requirements.





In connection with
the decommissioning of TMI-2, Met-Ed, Penelec and JCP&L make a combined
annual contribution of approximately $13 million. In connection with the 2005
intra-system generation asset transfer, NGC is required to contribute $80
million to the trust by May 2010. See Note 15 to the Notes to Consolidated
Financial Statements within FirstEnergy’s 2007 Annual Report on Form 10-K for
additional information regarding the intra-system generation asset
transfer.





Economic and Operational
Risks





Results in the third
quarter of 2008 continued to reflect some adverse effects on the demand for
electricity as a result of current economic conditions – particularly with
respect to the automotive industry. This condition is expected to continue into
2009 with potentially wider application among the Utilities’ customers.
FirstEnergy expects to see the impact of slower economic growth in both sales
and distribution revenues. Earlier in the year, FirstEnergy enhanced its
collection processes with respect to current customer billings and customer
deposits. While these efforts may have a mitigating effect, FirstEnergy expects
that there could be resulting increases in uncollectible customer accounts in
future periods. In addition, the margin on wholesale and retail generation sales
may be reduced as a result of lower demand and the resulting downward pressure
on power prices.





Regulatory
Matters





Ohio Legislative Process





On July 31, 2008,
the Ohio Companies filed both an ESP and MRO with the PUCO. A PUCO decision on
the MRO was required by statute within 90 days of the filing and is required on
the ESP within 150 days. Under the ESP, new rates would be effective for retail
customers on January 1, 2009. Evidentiary hearings concluded on
October 31, 2008 and no further hearings are scheduled. The parties are
required to submit initial briefs by November 21, 2008, with all reply briefs
due by December 12, 2008.





Under the MRO
alternative, the Ohio Companies propose to procure generation supply through a
CBP. The MRO would be implemented if the ESP is not approved by the PUCO or is
changed and not accepted by the Ohio Companies. On September 16, 2008, the PUCO
staff filed testimony and evidentiary hearings were held. The PUCO failed to act
on October 29, 2008 as required under the statute. The Ohio Companies are unable
to predict the outcome of this proceeding.





In July and August
2008, the PUCO staff issued three sets of proposed rules for comment to
implement portions of SB221. Written comments and reply comments on the three
sets of proposed rules were filed during the third quarter of 2008. Following
the comment period, the PUCO considers the input from stakeholders before
adopting the final rules. The rules are then subject to review by the Joint
Committee on Agency Rule Review, which conducts a 65-day review process. The
rules become effective 10 days following the Committee’s review. On September
17, 2008, the PUCO issued a final order adopting the first set of rules. A PUCO
order adopting the second set of rules was issued on November 5,
2008.





RCP Fuel Remand





On August 8, 2008,
the Ohio Companies submitted a filing to suspend the procedural schedule in
their application to recover their 2006-2007 deferred fuel costs and associated
carrying charges, as the ESP filing contains a proposal addressing the recovery
of these deferred fuel costs. On August 25, 2008, the PUCO ordered that the
evidentiary hearing scheduled for September 29, 2008, would be held at a
later date. A revised case schedule has yet to be issued.





3





Pennsylvania Legislative
Process





On October 15, 2008,
the Governor of Pennsylvania signed House Bill 2200 into law which becomes
effective on November 14, 2008, as Act 129 of 2008. The bill addresses
issues such as: energy efficiency and peak load reduction; generation
procurement; time-of-use rates; and smart meters and alternative energy. Act 129
requires utilities to file with the PPUC an energy efficiency and peak load
reduction plan by July 1, 2009, and a smart meter procurement and installation
plan by August 14, 2009.





Major provisions of
the legislation include:




·
              power acquired
      by utilities to serve customers after rate caps expire will be procured
      through a competitive procurement process that must include a mix of
      long-term and short-term contracts and spot market
    purchases;
 
 ·
              the
      competitive procurement process must be approved by the PPUC and may
      include auctions, request for proposals, and/or bilateral
      agreements;
 
 ·
              utilities must
      provide for the installation of smart meter technology within 15
      years;
 
 ·
              a minimum
      reduction in peak demand of 4.5% by May 31,
  2013;
 
 ·
              minimum
      reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31,
      2013, respectively; and
 
 ·
              an expanded
      definition of alternative energy to include additional types of
      hydroelectric and biomass
facilities.
 Penn’s
Interim Default Service Supply





On October 21, 2008,
Penn held its third RFP to procure default service for residential customers for
the period June 2009 through May 2010. A fourth RFP for the remainder of
residential customers’ load for the period June 2009 through May 2010 is
scheduled for January 2009. The results of the four RFPs will be averaged and
adjusted for the line losses, administrative fees and gross receipts tax, and
will be reflected in Penn’s new default service rates.





Met-Ed
and Penelec Rate Cases





Several parties to
the Met-Ed and Penelec 2006 rate case proceeding filed Petitions for Review with
the Commonwealth Court of Pennsylvania in 2007, asking the Court to review the
PPUC’s determination on several issues including: the recovery of
transmission costs (including congestion); the transmission deferral;
consolidated tax savings; the requested generation increase; and recovery of
universal service costs from only the residential rate class. The Commonwealth
Court issued its decision on November 7, 2008, which affirmed the PPUC's
January 11, 2007 order in all respects, including the deferral and recovery
of transmission and congestion related costs.





Met-Ed
and Penelec Prepayment Plan





On September 25,
2008, Met-Ed and Penelec filed a voluntary prepayment plan with the PPUC. The
plan offers qualified residential and small business customers the option to
gradually phase-in future generation price increases by making modest
prepayments during the next two years, before rate caps expire at the end of
2010. Each month, customers who elect to participate would prepay an amount
equal to approximately 9.6% of their electric bill. Prepayments would earn 7.5%
interest and be applied to customers’ billings in 2011 and 2012. Met-Ed and
Penelec requested that the PPUC approve the plan by mid-December
2008.





Solar
Renewable Energy





On September 30,
2008, JCP&L filed a proposal in response to an NJBPU directive addressing
solar project development in the State of New Jersey. Under the proposal,
JCP&L would enter into long-term agreements to buy and sell Solar Renewable
Energy Certificates (SREC) to provide a stable basis for financing solar
generation projects. An SREC represents the solar energy attributes of one
megawatt-hour of generation from a solar generation facility that has been
certified by the NJBPU Office of Clean Energy. Under this proposal JCP&L
would solicit SRECs to satisfy approximately 60%, 50%, and 40% of the
incremental SREC purchases needed in its service territory through 2010, 2011
and 2012, respectively, to meet the Renewable Portfolio Standards adopted by the
NJBPU in 2006. A schedule for further NJBPU proceedings has not yet been
set.





4








New
Jersey Energy Master Plan





On October 22, 2008,
the Governor of New Jersey released the details of New Jersey’s EMP, which
includes goals to reduce energy consumption by a minimum of 20% by 2020, reduce
peak demand by 5,700 MW by 2020, meet 30% of the state's electricity needs with
renewable energy by 2020, and examine smart grid technology. The EMP outlines a
series of goals and action items to meet set targets, while also continuing to
develop the clean energy industry in New Jersey. The Governor will establish a
State Energy Council to implement the recommendations outlined in the
plan.





Operational
Matters





Record
Generation Output





FirstEnergy set a
new quarterly generation output record of 22.2 million megawatt-hours during the
third quarter of 2008, a 3.2% increase over the previous record established in
the third quarter of 2006. This generation record reflects a quarterly all-time
high for the nuclear fleet.





September
Windstorm





On September 14,
2008, the remnants of Hurricane Ike swept through Ohio and western Pennsylvania
and produced unexpectedly high winds, reaching nearly 80 mph. More than one
million customers of OE, CEI, Penn and Penelec were affected by the windstorm,
which produced the largest storm-related outage in the history of any of those
companies. Storm expenses totaled approximately $30 million, of which $19
million was recognized as capital and $11 million as O&M
expense.





FIRSTENERGY’S
BUSINESS





FirstEnergy is a
diversified energy company headquartered in Akron, Ohio, that operates primarily
through three core business segments (see Results of Operations).





·
            Energy Delivery Services
      transmits and distributes electricity through FirstEnergy’s eight utility
      operating companies, serving 4.5 million customers within 36,100
      square miles of Ohio, Pennsylvania and New Jersey and purchases power for
      its PLR and default service requirements in Pennsylvania and New Jersey.
      This business segment derives its revenues principally from the delivery
      of electricity within FirstEnergy’s service areas at regulated rates, cost
      recovery of regulatory assets and the sale of electric generation service
      to retail customers who have not selected an alternative supplier (default
      service) in its Pennsylvania and New Jersey franchise areas. The segment’s
      net income reflects the commodity costs of securing electricity from
      FirstEnergy’s competitive energy services segment under partial
      requirements purchased power agreements with FES and from non-affiliated
      power suppliers, including, in each case, associated transmission
      costs.





·
            Competitive Energy
      Services supplies the electric power needs of end-use customers
      through retail and wholesale arrangements, including associated company
      power sales to meet all or a portion of the PLR and default service
      requirements of FirstEnergy’s Ohio and Pennsylvania utility subsidiaries
      and competitive retail sales to customers primarily in Ohio, Pennsylvania,
      Maryland and Michigan. This business segment owns or leases and operates
      19 generating facilities with a net demonstrated capacity of approximately
      13,664 MW and also purchases electricity to meet sales obligations. The
      segment's net income is primarily derived from affiliated company power
      sales and non-affiliated electric generation sales revenues less the
      related costs of electricity generation, including purchased power and net
      transmission and ancillary costs charged by PJM and MISO to deliver energy
      to the segment’s customers.





·
            Ohio Transitional Generation
      Services supplies the electric power needs of non-shopping
      customers under the default service requirements of the Ohio Companies.
      The segment's net income is primarily derived from electric generation
      sales revenues less the cost of power purchased from the competitive
      energy services segment through a full-requirements PSA arrangement with
      FES, including net transmission and ancillary costs charged by MISO to
      deliver energy to retail customers.





5





RESULTS
OF OPERATIONS





The financial
results discussed below include revenues and expenses from transactions among
FirstEnergy's business segments. A reconciliation of segment financial results
is provided in Note 14 to the consolidated financial statements. Net income
by major business segment was as follows:





Three
      Months Ended September 30,
            
            Nine
      Months Ended September 30,Increase
            
            
            
            Increase2008
            
            2007
            
            (Decrease)
            
            2008
            
            2007
            
            (Decrease)(In
      millions, except per share data)Net
      IncomeBy
      Business Segment:Energy
      delivery services
            $
            283
            
            $
            269
            
            $
            14
            
            $
            655
            
            $
            695
            
            $
            (40
            )Competitive
      energy services
            
            164
            
            
            148
            
            
            16
            
            
            317
            
            
            388
            
            
            (71
            )Ohio
      transitional generation services
            
            19
            
            
            16
            
            
            3
            
            
            62
            
            
            69
            
            
            (7
            )Other and
      reconciling adjustments*
            
            5
            
            
            (20
            )
            
            25
            
            
            (24)
            
            
            (111
            )
            
            87Total
            $
            471
            
            $
            413
            
            $
            58
            
            $
            1,010
            
            $
            1,041
            
            $
            (31
            )Basic
      Earnings Per Share
            $
            1.55
            
            $
            1.36
            
            $
            0.19
            
            $
            3.32
            
            $
            3.39
            
            $
            (0.07
            )Diluted
      Earnings Per Share
            $
            1.54
            
            $
            1.34
            
            $
            0.20
            
            $
            3.29
            
            $
            3.35
            
            $
            (0.06
            )





*
Consists primarily of interest expense related to holding company debt,
corporate support services revenues and expenses, and elimination of
intersegment transactions.





Summary of Results of Operations –
Third Quarter 2008 Compared with Third Quarter 2007





Financial results
for FirstEnergy's major business segments in the third quarter of 2008 and 2007
were as follows:




OhioEnergy
              
              
              Competitive
              
              
              Transitional
              
              
              Other
      andDelivery
              
              
              Energy
              
              
              Generation
              
              
              Reconciling
              
              
              FirstEnergyThird
      Quarter 2008 Financial Results
              
              Services
              
              
              Services
              
              
              Services
              
              
              Adjustments
              
              
              Consolidated(In
      millions)Revenues:ExternalElectric
              
              $
              2,487
              
              
              $
              381
              
              
              $
              781
              
              
              $
              -
              
              
              $
              3,649Other
              
              
              170
              
              
              
              79
              
              
              
              32
              
              
              
              (26
              )
              
              
              255Internal
              
              
              -
              
              
              
              786
              
              
              
              -
              
              
              
              (786
              )
              
              
              -Total
      Revenues
              
              
              2,657
              
              
              
              1,246
              
              
              
              813
              
              
              
              (812
              )
              
              
              3,904Expenses:Fuel
              
              
              -
              
              
              
              356
              
              
              
              -
              
              
              
              -
              
              
              
              356Purchased
      power
              
              
              1,248
              
              
              
              221
              
              
              
              623
              
              
              
              (786
              )
              
              
              1,306Other
      operating expenses
              
              
              430
              
              
              
              285
              
              
              
              110
              
              
              
              (31
              )
              
              
              794Provision for
      depreciation
              
              
              99
              
              
              
              67
              
              
              
              -
              
              
              
              2
              
              
              
              168Amortization
      of regulatory assets
              
              
              263
              
              
              
              -
              
              
              
              28
              
              
              
              -
              
              
              
              291Deferral of
      new regulatory assets
              
              
              (76
              )
              
              
              -
              
              
              
              18
              
              
              
              -
              
              
              
              (58
              )General
      taxes
              
              
              169
              
              
              
              26
              
              
              
              1
              
              
              
              5
              
              
              
              201Total
      Expenses
              
              
              2,133
              
              
              
              955
              
              
              
              780
              
              
              
              (810
              )
              
              
              3,058Operating
      Income
              
              
              524
              
              
              
              291
              
              
              
              33
              
              
              
              (2
              )
              
              
              846Other Income
      (Expense):Investment
      income
              
              
              48
              
              
              
              13
              
              
              
              1
              
              
              
              (22
              )
              
              
              40Interest
      expense
              
              
              (102
              )
              
              
              (44
              )
              
              
              (1
              )
              
              
              (45
              )
              
              
              (192
              )Capitalized
      interest
              
              
              1
              
              
              
              13
              
              
              
              -
              
              
              
              1
              
              
              
              15Total Other
      Expense
              
              
              (53
              )
              
              
              (18
              )
              
              
              -
              
              
              
              (66
              )
              
              
              (137
              )Income Before
      Income Taxes
              
              
              471
              
              
              
              273
              
              
              
              33
              
              
              
              (68
              )
              
              
              709Income
      taxes
              
              
              188
              
              
              
              109
              
              
              
              14
              
              
              
              (73
              )
              
              
              238Net
      Income
              
              $
              283
              
              
              $
              164
              
              
              $
              19
              
              
              $
              5
              
              
              $
              471
  6
   OhioEnergy
              
              
              Competitive
              
              
              Transitional
              
              
              Other
      andDelivery
              
              
              Energy
              
              
              Generation
              
              
              Reconciling
              
              
              FirstEnergyThird
      Quarter 2007 Financial Results
              
              Services
              
              
              Services
              
              
              Services
              
              
              Adjustments
              
              
              Consolidated(In
      millions)Revenues:ExternalElectric
              
              $
              2,340
              
              
              $
              338
              
              
              $
              716
              
              
              $
              -
              
              
              $
              3,394Other
              
              
              180
              
              
              
              32
              
              
              
              7
              
              
              
              28
              
              
              
              247Internal
              
              
              -
              
              
              
              806
              
              
              
              -
              
              
              
              (806
              )
              
              
              -Total
      Revenues
              
              
              2,520
              
              
              
              1,176
              
              
              
              723
              
              
              
              (778
              )
              
              
              3,641Expenses:Fuel
              
              
              2
              
              
              
              325
              
              
              
              -
              
              
              
              -
              
              
              
              327Purchased
      power
              
              
              1,114
              
              
              
              229
              
              
              
              631
              
              
              
              (806
              )
              
              
              1,168Other
      operating expenses
              
              
              436
              
              
              
              264
              
              
              
              80
              
              
              
              (24
              )
              
              
              756Provision for
      depreciation
              
              
              102
              
              
              
              51
              
              
              
              -
              
              
              
              9
              
              
              
              162Amortization
      of regulatory assets
              
              
              279
              
              
              
              -
              
              
              
              9
              
              
              
              -
              
              
              
              288Deferral of
      new regulatory assets
              
              
              (82
              )
              
              
              -
              
              
              
              (25
              )
              
              
              -
              
              
              
              (107
              )General
      taxes
              
              
              166
              
              
              
              26
              
              
              
              1
              
              
              
              4
              
              
              
              197Total
      Expenses
              
              
              2,017
              
              
              
              895
              
              
              
              696
              
              
              
              (817
              )
              
              
              2,791Operating
      Income
              
              
              503
              
              
              
              281
              
              
              
              27
              
              
              
              39
              
              
              
              850Other Income
      (Expense):Investment
      income
              
              
              58
              
              
              
              5
              
              
              
              -
              
              
              
              (33
              )
              
              
              30Interest
      expense
              
              
              (120
              )
              
              
              (44
              )
              
              
              -
              
              
              
              (39
              )
              
              
              (203
              )Capitalized
      interest
              
              
              3
              
              
              
              5
              
              
              
              -
              
              
              
              1
              
              
              
              9Total Other
      Expense
              
              
              (59
              )
              
              
              (34
              )
              
              
              -
              
              
              
              (71
              )
              
              
              (164
              )Income Before
      Income Taxes
              
              
              444
              
              
              
              247
              
              
              
              27
              
              
              
              (32
              )
              
              
              686Income
      taxes
              
              
              175
              
              
              
              99
              
              
              
              11
              
              
              
              (12
              )
              
              
              273Net
      Income
              
              $
              269
              
              
              $
              148
              
              
              $
              16
              
              
              $
              (20
              )
              
              $
              413Changes
      Between Third Quarter 2008 andThird
      Quarter 2007 Financial ResultsIncrease
      (Decrease)Revenues:ExternalElectric
              
              $
              147
              
              
              $
              43
              
              
              $
              65
              
              
              $
              -
              
              
              $
              255Other
              
              
              (10
              )
              
              
              47
              
              
              
              25
              
              
              
              (54
              )
              
              
              8Internal
              
              
              -
              
              
              
              (20
              )
              
              
              -
              
              
              
              20
              
              
              
              -Total
      Revenues
              
              
              137
              
              
              
              70
              
              
              
              90
              
              
              
              (34
              )
              
              
              263Expenses:Fuel
              
              
              (2
              )
              
              
              31
              
              
              
              -
              
              
              
              -
              
              
              
              29Purchased
      power
              
              
              134
              
              
              
              (8
              )
              
              
              (8
              )
              
              
              20
              
              
              
              138Other
      operating expenses
              
              
              (6
              )
              
              
              21
              
              
              
              30
              
              
              
              (7
              )
              
              
              38Provision for
      depreciation
              
              
              (3
              )
              
              
              16
              
              
              
              -
              
              
              
              (7
              )
              
              
              6Amortization
      of regulatory assets
              
              
              (16
              )
              
              
              -
              
              
              
              19
              
              
              
              -
              
              
              
              3Deferral of
      new regulatory assets
              
              
              6
              
              
              
              -
              
              
              
              43
              
              
              
              -
              
              
              
              49General
      taxes
              
              
              3
              
              
              
              -
              
              
              
              -
              
              
              
              1
              
              
              
              4Total
      Expenses
              
              
              116
              
              
              
              60
              
              
              
              84
              
              
              
              7
              
              
              
              267Operating
      Income
              
              
              21
              
              
              
              10
              
              
              
              6
              
              
              
              (41
              )
              
              
              (4
              )Other Income
      (Expense):Investment
      income
              
              
              (10
              )
              
              
              8
              
              
              
              1
              
              
              
              11
              
              
              
              10Interest
      expense
              
              
              18
              
              
              
              -
              
              
              
              (1
              )
              
              
              (6
              )
              
              
              11Capitalized
      interest
              
              
              (2
              )
              
              
              8
              
              
              
              -
              
              
              
              -
              
              
              
              6Total Other
      Expense
              
              
              6
              
              
              
              16
              
              
              
              -
              
              
              
              5
              
              
              
              27Income Before
      Income Taxes
              
              
              27
              
              
              
              26
              
              
              
              6
              
              
              
              (36
              )
              
              
              23Income
      taxes
              
              
              13
              
              
              
              10
              
              
              
              3
              
              
              
              (61
              )
              
              
              (35
              )Net
      Income
              
              $
              14
              
              
              $
              16
              
              
              $
              3
              
              
              $
              25
              
              
              $
              58







7





Energy Delivery Services – Third
Quarter 2008 Compared with Third Quarter 2007





Net income increased
$14 million to $283 million in the third quarter of 2008 compared to
$269 million in the third quarter of 2007, primarily due to increased
revenues partially offset by higher purchased power costs.





Revenues –





The
increase in total revenues resulted from the following sources:





Three
      MonthsEnded
      September 30,
            
            IncreaseRevenues
      by Type of Service
            
            2008
            
            2007
            
            (Decrease)(In
      millions)Distribution
      services
            
            $
            1,100
            
            $
            1,104
            
            $
            (4
            )Generation
      sales:Retail
            
            
            986
            
            
            942
            
            
            44Wholesale
            
            
            286
            
            
            207
            
            
            79Total
      generation sales
            
            
            1,272
            
            
            1,149
            
            
            123Transmission
            
            
            241
            
            
            219
            
            
            22Other
            
            
            44
            
            
            48
            
            
            (4
            )Total
      Revenues
            
            $
            2,657
            
            $
            2,520
            
            $
            137








The
decrease in distribution deliveries by customer class is summarized in the
following table:





Electric
      Distribution KWH DeliveriesResidential
            
            (1.9)
            %Commercial
            
            (1.1)
            %Industrial
            
            (4.1)
            %Total
      Distribution KWH Deliveries
            
            (2.3)
            %





The decrease in
electric distribution deliveries to residential and commercial customers was
primarily due to reduced weather-related usage during the third quarter of 2008
compared to the same period of 2007, as cooling degree days decreased 8.1%. In
the industrial sector, a decrease in deliveries to automotive and related
manufacturers (23%) and refining customers (15%) was partially offset by an
increase in usage by steel customers (4%). The reduction in distribution sales
volume was partially offset by an increase in unit prices from the previous
year.





The following table
summarizes the price and volume factors contributing to the $123 million
increase in generation revenues in the third quarter of 2008 compared to the
third quarter of 2007:





Sources
      of Change in Generation Revenues
            
            Increase
                (Decrease)(In
      millions)Retail:Effect
      of 1.9 % decrease in sales volumes
            
            $
            (18
            )Change
      in prices
            
            
            6244Wholesale:Effect
      of 2.4% decrease in sales volumes
            
            
            (5
            )Change
      in prices
            
            
            8479Net Increase
      in Generation Revenues
            
            $
            123





The decrease in
retail generation sales volumes was primarily due to an increase in customer
shopping in Penn’s, Penelec’s and JCP&L’s service territories and the
weather-related impacts described above. The increase in retail generation
prices during the third quarter of 2008 was due to higher generation rates for
JCP&L resulting from the New Jersey BGS auction process and an increase in
NUGC rates authorized by the NJBPU. The increase in wholesale prices reflected
higher spot market prices for PJM market participants.





8








Transmission
revenues increased $22 million primarily due to higher transmission rates
for Met-Ed and Penelec resulting from the annual update to their TSC riders,
which became effective June 1, 2008. Met-Ed and Penelec defer the
difference between revenues from their transmission rider and transmission costs
incurred with no material effect on current period earnings (see Outlook – State
Regulatory Matters – Pennsylvania).





Expenses –





The
increases in revenues discussed above were offset by a $116 million
increase in expenses due to the following:





·
            Purchased
      power costs were $134million higher in the
      third quarter of 2008 due to higher unit costs and a decrease in the
      amount of NUG costs deferred. The increased unit costs reflected the
      effect of higher JCP&L costs resulting from the BGS auction process.
      JCP&L is permitted to defer for future collection from customers the
      amounts by which its costs of supplying BGS to non-shopping customers and
      costs incurred under NUG agreements exceed amounts collected through BGS
      and NUGC rates and market sales of NUG energy and capacity. The following
      table summarizes the sources of changes in purchased power
      costs:





Source
      of Change in Purchased Power
            
            Increase
              (Decrease)(In
      millions)Purchases from
      non-affiliates:Change due to increased unit
      costs
            
            $
            146Change due to decreased
      volumes
            
            
            (45
            )101Purchases from
      FES:Change due to decreased unit
      costs
            
            
            (6
            )Change due to decreased
      volumes
            
            
            (10
            )(16
            )Decrease in
      NUG costs deferred
            
            
            49Net Increase
      in Purchased Power Costs
            
            $
            134








·
            Other
      operating expenses decreased $6 million due primarily to the net
      effects of the following:





-
            an increase in
      storm-related costs (including labor) of
  $9 million;





-
            an increase in
      other labor expenses of $3 million primarily due to increased hiring since
      the third quarter of 2007 as a result of the segment’s workforce
      initiatives;





-
            a $7 million
      increase in costs allocated to capital
projects;





-
            reduced
      vegetation management expenses of
      $5 million;  and





-
            a $4million decrease in
      uncollectible expense.





·
            Amortization
      of regulatory assets decreased by $16 million due primarily to the
      full recovery of certain regulatory assets since the third quarter of
      2007.





·
            The deferral
      of new regulatory assets during the third quarter of 2008 was
      $6 million lower primarily due to a reduction in the amount of
      deferred distribution costs.




·
            Depreciation
      expense decreased $3million due to a
      change in estimate for the asset retirement obligation for OE’s retired
      Toronto and Gorge plants.







·
              General taxes
      increased $3 million due to higher gross receipts and property
      taxes.








9








Other Expense –





Other expense
decreased $6million
in the third quarter of 2008 primarily due to lower interest expense (net of
capitalized interest) of $16million due to redemptions
of pollution control notes and term notes. Lower investment income of $10million, resulting from the
repayment of notes receivable from affiliates since the third quarter of 2007,
partially offset the interest expense reduction.





Competitive Energy Services – Third
Quarter 2008 Compared with Third Quarter 2007





Net income for this
segment was $164million in the third
quarter of 2008 compared to $148 million in the same period in 2007. The
$16 million increase in net income reflects an increase in gross generation
margin and investment income partially offset by higher operating
costs.





Revenues –





Total revenues
increased $70million
in the third quarter of 2008 due to higher non-affiliated generation sales and
transmission revenues, partially offset by reduced volumes on affiliated
generation sales.





The
net increase in total revenues resulted from the following sources:





Three
      Months EndedSeptember
      30,
            
            IncreaseRevenues
      By Type of Service
            
            2008
            
            2007
            
            (Decrease)(In
      millions)Non-Affiliated
      Generation Sales:Retail
            
            $
            171
            
            $
            189
            
            $
            (18
            )Wholesale
            
            
            210
            
            
            149
            
            
            61Total
      Non-Affiliated Generation Sales
            
            
            381
            
            
            338
            
            
            43Affiliated
      Generation Sales
            
            
            786
            
            
            806
            
            
            (20
            )Transmission
            
            
            47
            
            
            26
            
            
            21Other
            
            
            32
            
            
            6
            
            
            26Total
      Revenues
            
            $
            1,246
            
            $
            1,176
            
            $
            70





The lower retail
revenues resulted from decreased sales in the PJM market due primarily to lower
contract renewals for commercial and industrial customers. Higher non-affiliated
wholesale revenues resulted from the effect of increased generation available
for sale to that market as total generation output increased by 6.4% from the
third quarter of 2007. An increase in prices for non-affiliated wholesale sales,
reflecting higher capacity prices, also contributed to the revenue
increase.





The following tables
summarize the price and volume factors contributing to changes in revenues from
generation sales:





Source
      of Change in Non-Affiliated Generation Revenues
            
            Increase
      (Decrease)(In
      millions)Retail:Effect of 14.2% decrease in sales
      volumes
            
            $
            (27
            )Change in prices
            
            
            9(18
            )Wholesale:Effect of 28.8% increase in sales
      volumes
            
            
            43Change in prices
            
            
            1861Net Increase
      in Non-Affiliated Generation Revenues
            
            $
            43








10








Source
      of Change in Affiliated Generation Revenues
            
            Increase
      (Decrease)(In
      millions)Ohio
      Companies:Effect of 3.6% decrease in sales
      volumes
            
            $
            (22
            )Change in prices
            
            
            19(3
            )Pennsylvania
      Companies:Effect of 5.9% decrease in sales
      volumes
            
            
            (11
            )Change in prices
            
            
            (6
            )(17
            )Net Decrease
      in Affiliated Generation Revenues
            
            $
            (20
            )





The decreased
affiliated company generation revenues were due to reduced volumes partially
offset by higher unit prices for the Ohio Companies. The higher unit prices
reflected increases in the Ohio Companies’ retail generation rates. The
reduction in PSA sales volume to the Ohio and Pennsylvania Companies was due to
the milder weather and industrial sales changes discussed above and reduced
default service requirements in Penn’s service territory as a result of its RFP
process (see Outlook – State Regulatory Matters – Pennsylvania).





Transmission
revenues increased $21 million due primarily to an increase in transmission
prices in the MISO and PJM markets. Other revenues increased by $26 million due
to NGC’s purchase of certain lessor equity interests in the sale and leaseback
of Perry and Beaver Valley Unit 2 that continue to be leased to OE and
TE.





Expenses -





Total expenses
increased $60 million in the third quarter of 2008 due to the following
factors:





·
            Fossil fuel
      costs increased $50 million due to higher unit prices and increased
      generation volumes. The increased unit prices primarily reflect higher
      western coal transportation costs (including surcharges for increased
      diesel fuel prices) in the third quarter of 2008. The increase in fossil
      fuel costs was partially offset by a $25 million adjustment resulting
      from the annual coal inventory that reduced expense. Nuclear fuel expense
      increased $6 million due to increased
  generation;





·
            Purchased
      power costs decreased $8 million due to reduced volume requirements
      partially offset by higher market
prices;





·
            Other
      operating expenses were $21 million higher due primarily to a
      $13 million charge associated with a cancelled fossil project, an
      increase in nuclear operating costs of $5 million and a $5 million
      increase in uncollectible expense, partially offset by a $5 million
      reduction in transmission expense.





·
            Higher
      depreciation expense of $16 million was due to the assignment of the
      Bruce Mansfield Plant leasehold interests to FGCO and NGC’s purchase of
      certain lessor equity interests in the sale and leaseback of Perry and
      Beaver Valley Unit 2.





Other Expense –





Total other expense
in the third quarter of 2008 was $16million lower than the
third quarter of 2007, primarily due to a $9 million increase in net
earnings from nuclear decommissioning trust investments and higher capitalized
interest of $8 million due to a higher level of fossil capital projects in
progress.





Ohio Transitional Generation Services –
Third Quarter 2008 Compared with Third Quarter 2007





Net income for this
segment increased to $19million in the third
quarter of 2008 from $16 million in the same period of 2007. Higher
generation revenues were partially offset by higher operating expenses and lower
deferrals of new regulatory assets.





11





Revenues –





The
increase in reported segment revenues resulted from the following
sources:





Three
      Months EndedSeptember
      30,Revenues
      by Type of Service
            
            2008
            
            2007
            
            Increase(In
      millions)Generation
      sales:Retail
            
            $
            675
            
            $
            622
            
            $
            53Wholesale
            
            
            4
            
            
            3
            
            
            1Total
      generation sales
            
            
            679
            
            
            625
            
            
            54Transmission
            
            
            134
            
            
            98
            
            
            36Total
      Revenues
            
            $
            813
            
            $
            723
            
            $
            90





The following table
summarizes the price and volume factors contributing to the net increase in
sales revenues from retail customers:





Source
      of Change in Retail Generation Revenues
            
            Increase
      (Decrease)(In
      millions)Effect of 3.1% decrease in sales
      volumes
            
            $
            (19
            )Change in prices
            
            
            72Total
      Increase in Retail Generation Revenues
            
            $
            53





The decrease in
generation sales volume was primarily due to lower weather-related usage in the
third quarter of 2008 compared to the same period of 2007, partially offset by
reduced customer shopping. In the industrial sector, a decrease in generation
sales to automotive and related manufacturers (23%) and refining customers (15%)
was partially offset by an increase in usage by steel customers (2%). The
percentage of generation services provided by alternative suppliers to total
sales delivered by the Ohio Companies in their service areas decreased to 15.2%
in the third quarter of 2008 from 15.5% in the same period in 2007. Average
prices increased primarily due to an increase in the Ohio Companies’ fuel cost
recovery rider that became effective in January 2008.





Increased
transmission revenue resulted from a PUCO-approved transmission tariff increase
that became effective July 1, 2008, and higher MISO transmission
revenue.





Expenses -





Purchased power
costs were $8million
lower in the third quarter of 2008 due primarily to reduced volume requirements.
The factors contributing to the net decrease are summarized in the following
table:





Source
      of Change in Purchased Power
            
            Increase
              (Decrease)(In
      millions)Purchases from
      non-affiliates:Change due to decreased unit
      costs
            
            $
            (1
            )Change due to decreased
      volumes
            
            
            (3
            )(4
            )Purchases from
      FES:Change due to increased unit
      costs
            
            
            19Change due to decreased
      volumes
            
            
            (23
            )(4
            )Net Decrease
      in Purchased Power Costs
            
            $
            (8
            )





The decrease in
purchase volumes from FES was due to the lower retail generation sales
requirements described above. The higher unit costs reflect the increases in the
Ohio Companies’ retail generation rates, as provided for under the PSA with
FES.





Other operating
expenses increased $30 million due primarily to higher MISO
transmission-related expenses. The difference between transmission revenues
accrued and transmission expenses incurred is deferred, resulting in no material
impact to current period earnings.





12








The deferral of new
regulatory assets decreased by $43 million and the amortization of
regulatory assets increased $19 million in the third quarter of 2008 as compared
to the same period in 2007. MISO transmission deferrals and RCP fuel deferrals
each decreased as more transmission and generation costs were recovered from
customers through PUCO-approved riders.





Other – Third Quarter 2008 Compared
with Third Quarter 2007





Financial results
from other operating segments and reconciling items resulted in a
$25 million increase in FirstEnergy’s net income in the third quarter of
2008 compared to the same period in 2007. The increase resulted primarily
from income tax benefits associated with the settlement of tax positions
taken on federal returns in prior years, and from lower taxes payable upon
filing the 2007 federal income tax return in 2008 compared to the amount
initially estimated last year. The income tax benefits were partially offset by
the absence of the gain from the sale of First Communications ($13 million,
net of taxes) in 2007.





Summary of Results of Operations –
First Nine Months of 2008 Compared with the First Nine Months of
2007





Financial results
for FirstEnergy's major business segments in the first nine months of 2008 and
2007 were as follows:




OhioEnergy
              
              
              Competitive
              
              
              Transitional
              
              
              Other
      andDelivery
              
              
              Energy
              
              
              Generation
              
              
              Reconciling
              
              
              FirstEnergyFirst
      Nine Months 2008 Financial Results
              
              Services
              
              
              Services
              
              
              Services
              
              
              Adjustments
              
              
              Consolidated(In
      millions)Revenues:ExternalElectric
              
              $
              6,567
              
              
              $
              994
              
              
              $
              2,142
              
              
              $
              -
              
              
              $
              9,703Other
              
              
              484
              
              
              
              170
              
              
              
              61
              
              
              
              8
              
              
              
              723Internal
              
              
              -
              
              
              
              2,266
              
              
              
              -
              
              
              
              (2,266
              )
              
              
              -Total
      Revenues
              
              
              7,051
              
              
              
              3,430
              
              
              
              2,203
              
              
              
              (2,258
              )
              
              
              10,426Expenses:Fuel
              
              
              1
              
              
              
              999
              
              
              
              -
              
              
              
              -
              
              
              
              1,000Purchased
      power
              
              
              3,228
              
              
              
              648
              
              
              
              1,766
              
              
              
              (2,266
              )
              
              
              3,376Other
      operating expenses
              
              
              1,288
              
              
              
              906
              
              
              
              268
              
              
              
              (87
              )
              
              
              2,375Provision for
      depreciation
              
              
              309
              
              
              
              179
              
              
              
              -
              
              
              
              12
              
              
              
              500Amortization
      of regulatory assets
              
              
              747
              
              
              
              -
              
              
              
              48
              
              
              
              -
              
              
              
              795Deferral of
      new regulatory assets
              
              
              (274
              )
              
              
              -
              
              
              
              13
              
              
              
              -
              
              
              
              (261
              )General
      taxes
              
              
              491
              
              
              
              82
              
              
              
              4
              
              
              
              19
              
              
              
              596Total
      Expenses
              
              
              5,790
              
              
              
              2,814
              
              
              
              2,099
              
              
              
              (2,322
              )
              
              
              8,381Operating
      Income
              
              
              1,261
              
              
              
              616
              
              
              
              104
              
              
              
              64
              
              
              
              2,045Other Income
      (Expense):Investment
      income
              
              
              133
              
              
              
              (1
              )
              
              
              1
              
              
              
              (60
              )
              
              
              73Interest
      expense
              
              
              (305
              )
              
              
              (116
              )
              
              
              (1
              )
              
              
              (137
              )
              
              
              (559
              )Capitalized
      interest
              
              
              2
              
              
              
              30
              
              
              
              -
              
              
              
              4
              
              
              
              36Total Other
      Expense
              
              
              (170
              )
              
              
              (87
              )
              
              
              -
              
              
              
              (193
              )
              
              
              (450
              )Income Before
      Income Taxes
              
              
              1,091
              
              
              
              529
              
              
              
              104
              
              
              
              (129
              )
              
              
              1,595Income
      taxes
              
              
              436
              
              
              
              212
              
              
              
              42
              
              
              
              (105
              )
              
              
              585Net
      Income
              
              $
              655
              
              
              $
              317
              
              
              $
              62
              
              
              $
              (24
              )
              
              $
              1,010
  13
   OhioEnergy
                
                
                Competitive
                
                
                Transitional
                
                
                Other
      andDelivery
                
                
                Energy
                
                
                Generation
                
                
                Reconciling
                
                
                FirstEnergyFirst
      Nine Months 2007 Financial Results
                
                Services
                
                
                Services
                
                
                Services
                
                
                Adjustments
                
                
                Consolidated(In
      millions)Revenues:ExternalElectric
                
                $
                6,148
                
                
                $
                973
                
                
                $
                1,942
                
                
                $
                -
                
                
                $
                9,063Other
                
                
                507
                
                
                
                116
                
                
                
                26
                
                
                
                11
                
                
                
                660Internal
                
                
                -
                
                
                
                2,210
                
                
                
                -
                
                
                
                (2,210
                )
                
                
                -Total
      Revenues
                
                
                6,655
                
                
                
                3,299
                
                
                
                1,968
                
                
                
                (2,199
                )
                
                
                9,723Expenses:Fuel
                
                
                4
                
                
                
                883
                
                
                
                -
                
                
                
                -
                
                
                
                887Purchased
      power
                
                
                2,834
                
                
                
                578
                
                
                
                1,712
                
                
                
                (2,210
                )
                
                
                2,914Other
      operating expenses
                
                
                1,255
                
                
                
                839
                
                
                
                218
                
                
                
                (57
                )
                
                
                2,255Provision for
      depreciation
                
                
                301
                
                
                
                153
                
                
                
                -
                
                
                
                23
                
                
                
                477Amortization
      of regulatory assets
                
                
                765
                
                
                
                -
                
                
                
                20
                
                
                
                -
                
                
                
                785Deferral of
      new regulatory assets
                
                
                (299
                )
                
                
                -
                
                
                
                (100
                )
                
                
                -
                
                
                
                (399
                )General
      taxes
                
                
                486
                
                
                
                81
                
                
                
                3
                
                
                
                19
                
                
                
                589Total
      Expenses
                
                
                5,346
                
                
                
                2,534
                
                
                
                1,853
                
                
                
                (2,225
                )
                
                
                7,508Operating
      Income
                
                
                1,309
                
                
                
                765
                
                
                
                115
                
                
                
                26
                
                
                
                2,215Other Income
      (Expense):Investment
      income
                
                
                190
                
                
                
                13
                
                
                
                1
                
                
                
                (111
                )
                
                
                93Interest
      expense
                
                
                (347
                )
                
                
                (144
                )
                
                
                (1
                )
                
                
                (101
                )
                
                
                (593
                )Capitalized
      interest
                
                
                7
                
                
                
                13
                
                
                
                -
                
                
                
                1
                
                
                
                21Total Other
      Expense
                
                
                (150
                )
                
                
                (118
                )
                
                
                -
                
                
                
                (211
                )
                
                
                (479
                )Income Before
      Income Taxes
                
                
                1,159
                
                
                
                647
                
                
                
                115
                
                
                
                (185
                )
                
                
                1,736Income
      taxes
                
                
                464
                
                
                
                259
                
                
                
                46
                
                
                
                (74
                )
                
                
                695Net
      Income
                
                $
                695
                
                
                $
                388
                
                
                $
                69
                
                
                $
                (111
                )
                
                $
                1,041Changes
      Between First Nine Months 2008and
      First Nine Months 2007Financial
      Results Increase (Decrease)Revenues:ExternalElectric
                
                $
                419
                
                
                $
                21
                
                
                $
                200
                
                
                $
                -
                
                
                $
                640Other
                
                
                (23
                )
                
                
                54
                
                
                
                35
                
                
                
                (3
                )
                
                
                63Internal
                
                
                -
                
                
                
                56
                
                
                
                -
                
                
                
                (56
                )
                
                
                -Total
      Revenues
                
                
                396
                
                
                
                131
                
                
                
                235
                
                
                
                (59
                )
                
                
                703Expenses:Fuel
                
                
                (3
                )
                
                
                116
                
                
                
                -
                
                
                
                -
                
                
                
                113Purchased
      power
                
                
                394
                
                
                
                70
                
                
                
                54
                
                
                
                (56
                )
                
                
                462Other
      operating expenses
                
                
                33
                
                
                
                67
                
                
                
                50
                
                
                
                (30
                )
                
                
                120Provision for
      depreciation
                
                
                8
                
                
                
                26
                
                
                
                -
                
                
                
                (11
                )
                
                
                23Amortization
      of regulatory assets
                
                
                (18
                )
                
                
                -
                
                
                
                28
                
                
                
                -
                
                
                
                10Deferral of
      new regulatory assets
                
                
                25
                
                
                
                -
                
                
                
                113
                
                
                
                -
                
                
                
                138General
      taxes
                
                
                5
                
                
                
                1
                
                
                
                1
                
                
                
                -
                
                
                
                7Total
      Expenses
                
                
                444
                
                
                
                280
                
                
                
                246
                
                
                
                (97
                )
                
                
                873Operating
      Income
                
                
                (48
                )
                
                
                (149
                )
                
                
                (11
                )
                
                
                38
                
                
                
                (170
                )Other Income
      (Expense):Investment
      income
                
                
                (57
                )
                
                
                (14
                )
                
                
                -
                
                
                
                51
                
                
                
                (20
                )Interest
      expense
                
                
                42
                
                
                
                28
                
                
                
                -
                
                
                
                (36
                )
                
                
                34Capitalized
      interest
                
                
                (5
                )
                
                
                17
                
                
                
                -
                
                
                
                3
                
                
                
                15Total Other
      Expense
                
                
                (20
                )
                
                
                31
                
                
                
                -
                
                
                
                18
                
                
                
                29Income Before
      Income Taxes
                
                
                (68
                )
                
                
                (118
                )
                
                
                (11
                )
                
                
                56
                
                
                
                (141
                )Income
      taxes
                
                
                (28
                )
                
                
                (47
                )
                
                
                (4
                )
                
                
                (31
                )
                
                
                (110
                )Net
      Income
                
                $
                (40
                )
                
                $
                (71
                )
                
                $
                (7
                )
                
                $
                87
                
                
                $
                (31
                )


14







Energy
Delivery Services – First Nine Months of 2008 Compared to First Nine Months of
2007





Net income decreased
$40 million to $655 million in the first nine months of 2008 compared
to $695 million in the first nine months of 2007, primarily due to
increased operating expenses and lower investment income partially offset by
higher revenues.





Revenues –





The
increase in total revenues resulted from the following sources:





Nine
      Months EndedSeptember
      30,
            
            IncreaseRevenues
      by Type of Service
            
            2008
            
            2007
            
            (Decrease)(In
      millions)Distribution
      services
            
            $
            2,974
            
            $
            2,996
            
            $
            (22
            )Generation
      sales:Retail
            
            
            2,548
            
            
            2,417
            
            
            131Wholesale
            
            
            758
            
            
            489
            
            
            269Total
      generation sales
            
            
            3,306
            
            
            2,906
            
            
            400Transmission
            
            
            633
            
            
            595
            
            
            38Other
            
            
            138
            
            
            158
            
            
            (20
            )Total
      Revenues
            
            $
            7,051
            
            $
            6,655
            
            $
            396





The
decrease in distribution deliveries by customer class are summarized in the
following table:





Electric
      Distribution KWH DeliveriesResidential
            
            
            (1.3)
            %Commercial
            
            
            (0.5)
            %Industrial
            
            
            (1.8)
            %Total
      Distribution KWH Deliveries
            
            
            (1.2)
            %





The decrease in
electric distribution deliveries to residential and commercial customers was
primarily due to lower weather-related usage during the first nine months of
2008 compared to the same period of 2007, as cooling degree days decreased by
9.0% and heating degree days decreased by 2.6%. In the industrial sector, a
decrease in deliveries to automotive and related manufacturers (16%) and
refining customers (2%) was partially offset by an increase in usage by steel
customers (5%).





The following table
summarizes the price and volume factors contributing to the $400 million
increase in generation revenues in the first nine months of 2008 compared to the
same period of 2007:





IncreaseSources
      of Change in Generation Revenues
            
            (Decrease)(In
      millions)Retail:Effect
      of 2.2% decrease in sales volumes
            
            $
            (54
            )Change
      in prices
            
            
            185131Wholesale:Effect
      of 2.8% increase in sales volumes
            
            
            14Change
      in prices
            
            
            255269Net Increase
      in Generation Revenues
            
            $
            400





The decrease in
retail generation sales volumes reflected an increase in customer shopping in
Penn’s, Penelec’s, and JCP&L’s service territories and the weather-related
impacts described above. The increase in retail generation prices during the
first nine months of 2008 was due to higher generation rates for JCP&L
resulting from the New Jersey BGS auction process and an increase in NUGC rates
authorized by the NJBPU. Wholesale generation sales increased principally as a
result of Met-Ed and Penelec selling additional available power into the PJM
market. The increase in wholesale prices reflected higher spot market prices for
PJM market participants.





Transmission
revenues increased $38 million primarily due to higher transmission rates
for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of
transmission cost recovery and the annual update to their TSC riders, which
became effective June 1, 2008. Met-Ed and Penelec defer the difference
between revenues from their transmission rider and transmission costs incurred
with no material effect on current period earnings (see Outlook – State
Regulatory Matters – Pennsylvania).





15








Expenses –





The
net increases in revenues discussed above were more than offset by a
$444 million increase in expenses due to the following:





·
            Purchased
      power costs were $394million higher in the
      first nine months of 2008 due to higher unit costs and a decrease in the
      amount of NUG costs deferred. The increased unit costs primarily reflected
      the effect of higher JCP&L costs resulting from the BGS auction
      process. JCP&L is permitted to defer for future collection from
      customers the amounts by which its costs of supplying BGS to non-shopping
      customers and costs incurred under NUG agreements exceed amounts collected
      through BGS and NUGC rates and market sales of NUG energy and capacity.
      The following table summarizes the sources of changes in purchased power
      costs:





Source
      of Change in Purchased Power
            
            Increase
              (Decrease)(In
      millions)Purchases from
      non-affiliates:Change due to increased unit
      costs
            
            $
            369Change due to decreased
      volumes
            
            
            (83
            )286Purchases from
      FES:Change due to decreased unit
      costs
            
            
            (12
            )Change due to decreased
      volumes
            
            
            (1
            )(13
            )Decrease in
      NUG costs deferred
            
            
            121Net Increase
      in Purchased Power Costs
            
            $
            394








·
            Other
      operating expenses increased $33million due to the
      net effects of:





-
            an increase of
      $17million for
      costs (including labor) associated with three major storms experienced in
      FirstEnergy’s service territories in the first nine months of
      2008.





-
            an increase in
      other labor expenses of $19million primarily due
      to an increase in the number of employees in the first nine months of 2008
      compared to 2007 as a result of the segment’s workforce
      initiatives.





·
            Amortization
      of regulatory assets decreased $18 million due primarily to the complete
      recovery of certain regulatory assets for JCP&L since the third
      quarter of 2007.





·
            The deferral
      of new regulatory assets during the first nine months of 2008 was
      $25 million lower primarily due to the absence of the one-time
      deferral in 2007 of decommissioning costs related to the Saxton nuclear
      research facility.





·
            Higher
      depreciation expense of $8 million resulted from additional capital
      projects placed in service since the third quarter of
  2007.





·
            General taxes
      increased $5 million due to higher gross receipts and property
      taxes.





Other Expense –





Other expense
increased $20 million in the first nine months of 2008 compared to 2007
primarily due to lower investment income of $57million, resulting
primarily from the repayment of notes receivable from affiliates since the third
quarter of 2007, partially offset by lower interest expense (net of capitalized
interest) of $37 million.





Competitive Energy Services – First
Nine Months of 2008 Compared to First Nine Months of 2007





Net income for this
segment was $317 million in the first nine months of 2008 compared to
$388 million in the same period in 2007. The $71 million reduction in
net income reflects a decrease in gross generation margin and higher other
operating costs, which were partially offset by lower interest
expense.





16





Revenues –





Total revenues
increased $131million
in the first nine months of 2008 compared to the same period in 2007. This
increase primarily resulted from higher unit prices on affiliated generation
sales to the Ohio Companies and increased non-affiliated wholesale sales,
partially offset by lower retail sales.





The
increase in reported segment revenues resulted from the following
sources:





Nine
      Months EndedSeptember
      30,
            
            IncreaseRevenues
      by Type of Service
            
            2008
            
            2007
            
            (Decrease)(In
      millions)Non-Affiliated
      Generation Sales:Retail
            
            $
            485
            
            $
            547
            
            $
            (62
            )Wholesale
            
            
            509
            
            
            426
            
            
            83Total
      Non-Affiliated Generation Sales
            
            
            994
            
            
            973
            
            
            21Affiliated
      Generation Sales
            
            
            2,266
            
            
            2,210
            
            
            56Transmission
            
            
            113
            
            
            71
            
            
            42Other
            
            
            57
            
            
            45
            
            
            12Total
      Revenues
            
            $
            3,430
            
            $
            3,299
            
            $
            131





The lower retail
revenues resulted from decreased sales in the PJM market, partially offset by
increased sales in the MISO market. The decrease in PJM retail sales is
primarily the result of lower contract renewals for commercial and industrial
customers. The increase in MISO retail sales is primarily the result of
capturing more shopping customers in Penn’s service territory, partially offset
by lower customer usage. Higher non-affiliated wholesale revenues resulted from
higher capacity prices and increased sales volumes in PJM, partially offset by
decreased sales volumes in MISO.





The increased
affiliated company generation revenues were due to higher unit prices for the
Ohio Companies partially offset by lower unit prices for the Pennsylvania
Companies and decreased sales volumes to all affiliates. The higher unit prices
reflected increases in the Ohio Companies’ retail generation rates. While unit
prices for each of the Pennsylvania Companies did not change, the mix of sales
among the companies caused the overall price to decline. The reduction in PSA
sales volume to the Ohio and Pennsylvania Companies was due to the milder
weather and industrial sales changes discussed above and reduced default service
requirements in Penn’s service territory as a result of its RFP process (see
Outlook – State Regulatory Matters – Pennsylvania).





The following tables
summarize the price and volume factors contributing to changes in revenues from
generation sales:





IncreaseSource
      of Change in Non-Affiliated Generation Revenues
            
            (Decrease)(In
      millions)Retail:Effect of 13.2% decrease in sales
      volumes
            
            $
            (73
            )Change in prices
            
            
            11(62
            )Wholesale:Effect of 4.6% increase in sales
      volumes
            
            
            19Change in prices
            
            
            6483Net Increase
      in Non-Affiliated Generation Revenues
            
            $
            21IncreaseSource
      of Change in Affiliated Generation Revenues
            
            (Decrease)(In
      millions)Ohio
      Companies:Effect of 1.7% decrease in sales
      volumes
            
            $
            (28
            )Change in prices
            
            
            9769Pennsylvania
      Companies:Effect of 0.2% decrease in sales
      volumes
            
            
            (1
            )Change in prices
            
            
            (12
            )(13
            )Net Increase
      in Affiliated Generation Revenues
            
            $
            56








Transmission
revenues increased $42 million due primarily to higher transmission rates
in MISO and PJM.





17








Expenses -





Total expenses
increased $280 million in the first nine months of 2008 due to the
following factors:





·
            Fossil fuel
      costs increased $133 million due to higher unit prices
      ($135 million) partially offset by lower generation volume
      ($2 million). The increased unit prices primarily reflect higher
      western coal transportation costs, increased rates for existing eastern
      coal contracts and emission allowance costs in the first nine months of
      2008. The increase in fossil fuel costs was partially offset by a
      $25 million adjustment resulting from the annual coal inventory that
      reduced expense. Nuclear fuel expense was $8 million higher as
      nuclear generation increased in the first nine months of
    2008.





·
            Purchased
      power costs increased $70 million due primarily to higher spot market
      prices, partially offset by reduced volume
  requirements.





·
            Nuclear
      operating costs increased $21 million in the first nine months of
      2008 due to an additional refueling outage in 2008 compared with the 2007
      period.





·
            Fossil
      operating costs were $20 million higher due to a cancelled fossil
      project ($13 million), planned maintenance outages in 2008, employee
      benefits and reduced gains from emission allowance
  sales.





·
            Other
      operating expenses increased $26 million due primarily to the
      assignment of CEI’s and TE’s leasehold interests in the Bruce Mansfield
      Plant to FGCO in the fourth quarter of 2007 ($26 million) and higher
      employee benefit costs during the first nine months of 2008
      ($14 million), partially offset by lower transmission expense ($16
      million).





·
            Higher
      depreciation expenses of $26 million were due to the assignment of
      the Bruce Mansfield Plant leasehold interests to FGCO and NGC’s purchase
      of certain lessor equity interests in the sale and leaseback of Perry and
      Beaver Valley Unit 2.





·
            Higher general
      taxes of $1 million resulted from higher property
  taxes.





Other Expense –





Total other expense
in the first nine months of 2008 was $31million lower than the
first nine months of 2007, principally due to a decline in interest expense (net
of capitalized interest) of $45 million from the repayment of notes payable
to affiliates since the third quarter of 2007, partially offset by a
$14 million decrease in net earnings from nuclear decommissioning trust
investments due primarily to securities impairments resulting from market
declines during the first nine months of 2008.





Ohio Transitional Generation Services –
First Nine Months of 2008 Compared to First Nine Months of 2007





Net income for this
segment decreased to $62million in the first nine
months of 2008 from $69 million in the same period of 2007. Higher
operating expenses, primarily for purchased power, and a decrease in the
deferral of new regulatory assets were partially offset by higher generation
revenues.





Revenues –





The
increase in reported segment revenues resulted from the following
sources:





Nine
      Months EndedSeptember
      30Revenues
      by Type of Service
            
            2008
            
            2007
            
            Increase(In
      millions)Generation
      sales:Retail
            
            $
            1,868
            
            $
            1,712
            
            $
            156Wholesale
            
            
            9
            
            
            7
            
            
            2Total
      generation sales
            
            
            1,877
            
            
            1,719
            
            
            158Transmission
            
            
            319
            
            
            248
            
            
            71Other
            
            
            7
            
            
            1
            
            
            6Total
      Revenues
            
            $
            2,203
            
            $
            1,968
            
            $
            235








18





The following table
summarizes the price and volume factors contributing to the net increase in
sales revenues from retail customers:




Source
      of Change in Generation Revenues
            
            Increase(In
      millions)Retail:Effect of 1.4% decrease in sales
      volumes
            
            $
            (24
            )Change in prices
            
            
            180Total
      Increase in Retail Generation Revenues
            
            $
            156





The decrease in
generation sales volume in the first nine months of 2008 was primarily due to
milder weather and reduced customer shopping. Cooling degree days in OE’s, CEI’s
and TE’s service territories for the first nine months of 2008 decreased by
23.3%, 7.3% and 15.0%, respectively, while heating degree days were relatively
unchanged from the previous year. In the industrial sector, a decrease in
generation sales to automotive and related manufacturers (16%) and refining
customers (2%) was partially offset by an increase in usage by steel customers
(1%). The percentage of generation services provided by alternative suppliers to
total sales delivered by the Ohio Companies in their service areas decreased to
14.6% in the first nine months of 2008 from 15.1% in the same period in 2007.
Average prices increased primarily due to an increase in the Ohio Companies’
fuel cost recovery riders that became effective in January 2008.





Increased
transmission revenue resulted from PUCO-approved transmission tariff increases
that became effective July 1, 2007 and July 1, 2008. The difference between
transmission revenues accrued and transmission expenses incurred is deferred,
resulting in no material impact to current period earnings.





Expenses -





Purchased power
costs were $54 million higher due primarily to higher unit costs for power
purchased from FES. The factors contributing to the net increase are summarized
in the following table:





IncreaseSource
      of Change in Purchased Power
            
            (Decrease)(In
      millions)Purchases from
      non-affiliates:Change due to decreased unit
      costs
            
            $
            (3
            )Change due to decreased
      volumes
            
            
            (13
            )(16
            )Purchases from
      FES:Change due to increased unit
      costs
            
            
            98Change due to decreased
      volumes
            
            
            (28
            )70Net Increase
      in Purchased Power Costs
            
            $
            54





The higher unit
costs reflect the increases in the Ohio Companies’ retail generation rates, as
provided for under the PSA with FES. The decrease in purchase volumes from FES
was due to the lower retail generation sales requirements described
above.





Other operating
expenses increased $50 million due primarily to higher net costs associated
with the Ohio Companies’ generation leasehold interests and increased MISO
transmission-related expenses. The difference between transmission revenues
accrued and transmission expenses incurred is deferred, resulting in no material
impact to current period earnings.





The deferral of new
regulatory assets decreased by $113 million and the amortization of
regulatory assets increased $28 million in the first nine months of 2008 as
compared to the same period in 2007. MISO transmission deferrals and RCP fuel
deferrals decreased as more transmission and generation costs were recovered
from customers through PUCO-approved riders.





Other – First Nine Months of 2008
Compared to First Nine Months of 2007





Financial results
from other operating segments and reconciling items resulted in an
$87 million increase in FirstEnergy’s net income in the first nine months
of 2008 compared to the same period in 2007. The increase resulted primarily
from a $19 million after-tax gain from the sale of telecommunication assets, a
$10 million after-tax gain from the settlement of litigation relating to
formerly-owned international assets, a $33 million reduction of interest
expense associated with the revolving credit facility, and income tax
adjustments associated with the favorable settlement of tax positions taken on
federal returns in prior years. This increase was partially offset by the
absence of the gain from the sale of First Communications ($13 million, net
of taxes) in 2007.





19





CAPITAL
RESOURCES AND LIQUIDITY





Despite recent
unprecedented volatility in the capital markets, FirstEnergy expects its
existing sources of liquidity to remain sufficient to meet its anticipated
obligations and those of its subsidiaries. FirstEnergy’s business is capital
intensive, requiring significant resources to fund operating expenses,
construction expenditures, scheduled debt maturities and interest and dividend
payments. During the remainder of 2008 and in subsequent years, FirstEnergy
expects to satisfy these requirements with a combination of cash from operations
and funds from the capital markets. FirstEnergy also expects that borrowing
capacity under credit facilities will continue to be available to manage working
capital requirements during those periods.





FirstEnergy and
certain of its subsidiaries have access to $2.75 billion of short-term
financing under a revolving credit facility which expires in August 2012. A
total of 25 banks participate in the facility, with no one bank having more than
7.3% of the total commitments. As of September 30, 2008, FirstEnergy
had $420 million of bank credit facilities in addition to the
$2.75 billion revolving credit facility. On October 8,
2008, FirstEnergy obtained a new $300 million secured term loan facility
with Credit Suisse to reinforce its liquidity in light of the unprecedented
disruptions in the credit markets. On October 20, 2008, OE issued
$300 million of FMBs to fund its capital expenditures and for other general
corporate purposes. In addition, an aggregate of $550 million of
accounts receivable financing facilities through the Ohio and Pennsylvania
Companies may be accessed to meet working capital requirements and for other
general corporate purposes. FirstEnergy’s available liquidity as of
October 31, 2008, is described in the following table:





Company
            
            Type
            
            Maturity
            
            Commitment
            
            Available(In
      millions)FirstEnergy(1)
            
            Revolving
            
            Aug.
      2012
            
            $2,750
            
            404FirstEnergy
      and FES
            
            Revolving
            
            May
      2009
            
            300
            
            300FirstEnergy
            
            Bank
      lines
            
            Various(2)
            
            120
            
            20FGCO
            
            Term
      loan
            
            Oct. 2009(3)
            
            300
            
            300Ohio and
      Pennsylvania Companies
            
            A/R
      financing
            
            Various(4)
            
            550
            
            445Subtotal:
            
            $4,020
            
            $1,469Cash:
            
            -
            
            456Total:
            
            $4,020
            
            $1,925





(1)FirstEnergy
      Corp. and subsidiary borrowers.
              (2)$100 million
      matures November 30, 2009; $20 million uncommitted line of credit
      with no maturity date.
              (3)Drawn amounts
      are payable within 30 days and may not be reborrowed.
              (4)$370 million
      matures March 21, 2009; $180 million matures December 19,
      2008 with an extension requested
              pending
      state regulatory approval of replacement
  facility.




In early October
2008, FirstEnergy took steps to further enhance its liquidity position by
negotiating with the banks that have issued irrevocable direct pay LOCs in
support of its outstanding variable interest rate PCRBs ($2.1 billion as of
September 30, 2008) to extend the respective reimbursement obligations of
the applicable FirstEnergy subsidiary obligors in the event that such LOCs are
drawn upon. As discussed below, the LOCs supporting these PCRBs may be drawn
upon to pay the purchase price to bondholders that have exercised the right to
tender their PCRBs for mandatory purchase. As a result of these negotiations, a
total of approximately $902 million of LOCs that previously required
reimbursement within 30 days or less of a draw under the applicable LOC have now
been modified to extend the reimbursement obligations to six months or June
2009, as applicable.  The LOCs for FirstEnergy’s variable interest
rate PCRBs were issued by seven banks, as summarized in the following
table:





Aggregate
      LOCAmount(5)
            
            
            
            Reimbursements
      ofLOC
      Bank
            
            (In
      millions)
            
            LOC
      Termination Date
            
            LOC
      Draws DueBarclays
      Bank(1)
            
            $
            149
            
            June
      2009
            
            June
      2009Bank of
      America(1)
      (2)
            
            
            101
            
            June
      2009
            
            June
      2009The Bank of
      Nova Scotia(1)
            
            
            255
            
            Beginning June
      2010
            
            Shorter of 6
      months or LOC termination dateThe Royal Bank
      of Scotland(1)
            
            
            131
            
            June
      2012
            
            6
      monthsKeyBank(1)
      (3)
            
            
            266
            
            June
      2010
            
            6
      monthsWachovia
      Bank
            
            
            648
            
            March
      2009
            
            March
      2009Barclays
      Bank(4)
            
            
            528
            
            Beginning
      December 2010
            
            30
      daysPNC
      Bank
            
            
            70
            
            Beginning
      December 2010
            
            5
      daysTotal
            
            $
            2,148




(1)Due dates for
      reimbursements of LOC draws for these banks were extended in October 2008
      from 30
                days or less
      to the dates indicated.
                (2)Supported by 2
      participating banks, with each having 50% of the total
      commitment.
                (3)Supported by 4
      participating banks, with the LOC bank having 62% of the total
      commitment.
                (4)Supported by
      17 participating banks, with no one bank having more than 14% of the total
      commitment.
                (5)Includes
      approximately $22 million of applicable interest
      coverage.





20








As of
September 30, 2008, FirstEnergy’s net deficit in working capital (current
assets less current liabilities) was principally due to short-term borrowings
($2.4 billion) and the classification of certain variable interest rate
PCRBs as currently payable long-term debt. Currently payable long-term debt as
of September 30, 2008 included the following:





Currently
      Payable Long-term Debt(In
      millions)PCRBs
      supported by bank LOCs (1)
            
            $
            2,126CEI FMBs (2)
            
            
            125CEI secured
      PCRBs (2)
            
            
            82Penelec
      unsecured notes (3)
            
            
            100NGC
      collateralized lease obligation bonds (4)
            
            
            37Sinking fund
      requirements (5)
            
            
            39$
            2,509




(1)Interest rate mode permits individual debt holders to put the
      respective debt back to the issuer prior to maturity.
              (2)Redeemed in October 2008.
              (3)
      Matures in April 2009.
              (4)
      $4 million payable in the fourth quarter of 2008.
              (5)
      $9 million payable in the fourth quarter of 2008.


Changes
in Cash Position





FirstEnergy's
primary source of cash required for continuing operations as a holding company
is cash from the operations of its subsidiaries. In the first nine months of
2008, FirstEnergy received $748 million of cash dividends from its
subsidiaries and paid $503 million in cash dividends to common
shareholders. With the exception of Met-Ed, which is currently in an accumulated
deficit position, there are no material restrictions on the payment of cash
dividends by the subsidiaries of FirstEnergy.





During the nine
months ended September 30, 2008, net cash provided from operating and financing
activities was $1.4 billion and $914 million, respectively and net
cash used for investing activities was $2.3 billion. As of September 30,
2008, FirstEnergy had $181 million of cash and cash equivalents compared
with $129 million as of December 31, 2007. Cash and cash equivalents
consist of unrestricted, highly liquid instruments with an original or remaining
maturity of three months or less. As of September 30, 2008, approximately $132
million of cash and cash equivalents consisted of temporary overnight
investments. The major sources of changes in these balances are summarized
below.


Cash
Flows from Operating Activities





FirstEnergy's
consolidated net cash from operating activities is provided primarily by its
energy delivery services and competitive energy services businesses (see Results
of Operations above). Net cash provided from operating activities was
$1.4 billion and $1.2 billion in the first nine months of 2008 and
2007, respectively, as summarized in the following table:





Nine
      Months EndedSeptember
      30,Operating
      Cash Flows
            
            2008
            
            2007(In
      millions)Net
      income
            
            $
            1,010
            
            $
            1,041Non-cash
      charges
            
            
            1,008
            
            
            358Pension trust
      contribution
            
            
            -
            
            
            (300
            )Working
      capital and other
            
            
            (590
            )
            
            111$
            1,428
            
            $
            1,210





Net cash provided
from operating activities increased by $218 million in the first nine
months of 2008 compared to the first nine months of 2007 primarily due to the
absence of a $300 million pension trust contribution in 2007 and a
$650 million increase in non-cash charges, partially offset by a
$701 million decrease from working capital and other changes and a
$31 million decrease in net income (see Results of Operations
above).





21





The increase in
non-cash charges is primarily due to lower deferrals of new regulatory assets
and purchased power costs and higher deferred income taxes. The deferral of new
regulatory assets decreased primarily as a result of the Ohio Companies’
transmission and fuel recovery riders that became effective in July 2007 and
January 2008, respectively, and the absence of the deferral of decommissioning
costs related to the Saxton nuclear research facility in the first quarter of
2007. Lower deferrals of purchased power costs reflected a decrease in NUG costs
deferred. The change in deferred income taxes is primarily due to additional tax
depreciation as provided for under the Economic Stimulus Act of 2008, the
settlement of tax positions taken on federal returns in prior years, and the
absence of deferred income tax impacts related to the Bruce Mansfield Unit 1
sale and leaseback transaction in 2007. The changes in working capital and other
primarily resulted from higher fossil fuel inventories and increased tax
payments, partially offset by a change in the collection of
receivables.




Cash
Flows from Financing Activities





In the first nine
months of 2008, cash provided from financing activities was $914 million
compared to cash used of $1.4 billion in the first nine months of 2007. The
increase was due to higher short-term borrowings primarily for capital
expenditures for environmental compliance and to fund a number of strategic
acquisitions, including the Fremont Plant ($275 million), Signal Peak ($125
million), and the purchase of lessor equity interests in Beaver Valley Unit 2
and Perry ($438 million). The absence of the repurchase of common stock in the
first nine months of 2007 also contributed to the increase in the 2008 period.
The following table summarizes security issuances and redemptions or repurchases
during the nine months ended September 30, 2008, and 2007.





Nine
      Months EndedSecurities
      Issued or
            
            September
      30,Redeemed
      / Repurchased
            
            2008
            
            2007(In
      millions)New
      issuesPollution
      control notes
            
            $
            611
            
            $
            -Unsecured
      notes
            
            
            20
            
            
            1,100$
            631
            
            $
            1,100Redemptions
      / RepurchasesFirst mortgage
      bonds
            
            $
            1
            
            $
            287Pollution
      control notes
            
            
            534
            
            
            4Senior secured
      notes
            
            
            23
            
            
            203Unsecured
      notes
            
            
            175
            
            
            153Common
      stock
            
            
            -
            
            
            918$
            733
            
            $
            1,565





FirstEnergy had
approximately $2.4 billion of short-term indebtedness as of September 30,
2008 compared to approximately $903 million as of December 31,
2007.





As described above,
FirstEnergy and its subsidiaries, FES and FGCO entered into a new
$300 million secured term loan facility with Credit Suisse in October 2008.
Under the facility, FGCO is the borrower and FES and FirstEnergy are guarantors.
Generally, the facility is available to FGCO until October 7, 2009, with a
minimum borrowing amount of $100 million and a maturity of 30 days from the
date of the borrowing. Once repaid, borrowings may not be
re-borrowed.





As of September 30,
2008, the Ohio Companies and Penn had the aggregate capability to issue
approximately $3.6 billion of additional FMB on the basis of property additions
and retired bonds under the terms of their respective mortgage indentures. The
issuance of FMB by OE, CEI and TE is also subject to provisions of their senior
note indentures generally limiting the incurrence of additional secured debt,
subject to certain exceptions that would permit, among other things, the
issuance of secured debt (including FMB) supporting pollution control notes or
similar obligations, or as an extension, renewal or replacement of previously
outstanding secured debt. In addition, these provisions would permit OE, CEI and
TE to incur additional secured debt not otherwise permitted by a specified
exception of up to $448 million, $457 million and $120 million,
respectively, as of September 30, 2008. On June 19, 2008, FGCO established
an FMB indenture. Based upon its net earnings and available bondable property
additions as of September 30, 2008, FGCO had the capability to issue
$3.1 billion of additional FMB under the terms of that indenture. Met-Ed
and Penelec had the capability to issue secured debt of approximately
$363 million and $310 million, respectively, under provisions of their
senior note indentures as of September 30, 2008.





On September 22,
2008, FirstEnergy and the Utilities filed an automatically effective shelf
registration statement with the SEC for an unspecified number and amount of
securities to be offered thereon. The shelf registration provides FirstEnergy
the flexibility to issue and sell various types of securities, including common
stock, preferred stock, debt securities, warrants, share purchase contracts, and
share purchase units. The Utilities may utilize the shelf registration statement
to offer and sell unsecured, and in some cases, secured debt
securities.





22








As discussed above,
on October 20, 2008, OE issued and sold under the shelf registration statement
$300 million of FMBs, comprised of $275 million 8.25% Series of 2008 due
2038 and $25 million 8.25% Series of 2008 due 2018. The net proceeds from
this offering will be used to fund capital expenditures and for other general
corporate purposes. This issuance reduces OE’s capability to issue additional
FMB under the terms of its mortgage indenture described above.





As of September 30,
2008, FirstEnergy’s currently payable long-term debt includes approximately $2.1
billion (FES - $1.9 billion, OE - $156 million, Met-Ed - $29 million and Penelec
- $45 million) of variable interest rate PCRBs, the bondholders of which are
entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates
on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for
mandatory purchase prior to maturity with the purchase price payable from
remarketing proceeds, or if the PCRBs are not successfully remarketed, by
drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required
to reimburse the applicable LOC bank for any such drawings or, if the LOC bank
fails to honor its LOC for any reason, must itself pay the purchase
price.





Prior to September
2008, FirstEnergy had not experienced any unsuccessful remarketings of these
variable-rate PCRBs. Coincident with recent disruptions in the variable-rate
demand bond and capital markets generally, certain of the PCRBs have been
tendered by bondholders to the trustee. As of October 31, 2008,
$72.5 million of the PCRBs, all of which are backed by Wachovia Bank LOCs,
had been tendered and not yet successfully remarketed. Of these, draws on the
applicable LOCs were made for $72.4 million, all of which Wachovia honored.
The reimbursement agreements between the subsidiary obligors and Wachovia
require reimbursement of outstanding LOC draws by March 2009.





FirstEnergy and
certain of its subsidiaries are party to a $2.75 billion revolving credit
facility (included in the borrowing capability table above). FirstEnergy has the
capability to request an increase in the total commitments available under this
facility up to a maximum of $3.25 billion, subject to the discretion of
each lender to provide additional commitments. Commitments under the facility
are available until August 24, 2012, unless the lenders agree, at the
request of the borrowers, to an unlimited number of additional one-year
extensions. Generally, borrowings under the facility must be repaid within 364
days. Available amounts for each borrower are subject to a specified sub-limit,
as well as applicable regulatory and other limitations.





The following table
summarizes the borrowing sub-limits for each borrower under the facility, as
well as the limitations on short-term indebtedness applicable to each borrower
under current regulatory approvals and applicable statutory and/or charter
limitations as of September 30, 2008:





Revolving
            
            Regulatory
      andCredit
      Facility
            
            Other
      Short-TermBorrower
            
            Sub-Limit
            
            Debt
      Limitations(In
      millions)FirstEnergy
            
            $
            2,750
            
            $
            -
            (1)OE
            
            
            500
            
            
            500Penn
            
            
            50
            
            
            39
            (2)CEI
            
            
            250
            (3)
            
            500TE
            
            
            250
            (3)
            
            500JCP&L
            
            
            425
            
            
            428
            (2)Met-Ed
            
            
            250
            
            
            300
            (2)Penelec
            
            
            250
            
            
            300
            (2)FES
            
            
            1,000
            
            
            -
            (1)ATSI
            
            
            -
            (4)
            
            50




(1)No regulatory approvals, statutory or charter limitations
      applicable.
              (2)Excluding amounts which may be borrowed under the regulated
              companies’
      money pool.
              (3)Borrowing sub-limits for CEI and TE may be increased to up to
      $500 million by
              delivering
      notice to the administrative agent that such borrower has senior unsecured
              debt
      ratings of at least BBB by S&P and Baa2 by Moody’s.
              (4)The borrowing sub-limit for ATSI may be increased up to
      $100 million by delivering
              notice
      to the administrative agent that either (i) ATSI has senior unsecured debt
              ratings
      of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has
      guarantee
              ATSI’s
      obligations of such borrower under the
facility.





23








The revolving credit
facility described above, combined with $720 million of additional credit
facilities ($620 million available as of October 31, 2008) and an aggregate
$550 million of accounts receivable financing facilities for OE, CEI, TE,
Met-Ed, Penelec and Penn ($445 million available as of October 31, 2008),
are available to provide liquidity to meet working capital requirements and for
other general corporate purposes for FirstEnergy and its
subsidiaries.





Under the revolving
credit facility, borrowers may request the issuance of LOCs expiring up to one
year from the date of issuance. The stated amount of outstanding LOCs will count
against total commitments available under the facility and against the
applicable borrower’s borrowing sub-limit.





The revolving credit
facility contains financial covenants requiring each borrower to maintain a
consolidated debt to total capitalization ratio of no more than 65%, measured at
the end of each fiscal quarter. As of September 30, 2008, FirstEnergy’s and
its subsidiaries' debt to total capitalization ratios (as defined under the
revolving credit facility) were as follows:





BorrowerFirstEnergy
            
            59.6
            %OE
            
            46.0
            %Penn
            
            19.2
            %CEI
            
            55.8
            %TE
            
            44.5
            %JCP&L
            
            31.0
            %Met-Ed
            
            43.7
            %Penelec
            
            50.1
            %FES
            
            56.6
            %





The revolving credit
facility does not contain provisions that either restrict the ability to borrow
or accelerate repayment of outstanding advances as a result of any change in
credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
borrowed under the facility is related to the credit ratings of the company
borrowing the funds.





FirstEnergy's
regulated companies also have the ability to borrow from each other and the
holding company to meet their short-term working capital requirements. A similar
but separate arrangement exists among FirstEnergy's unregulated companies. FESC
administers these two money pools and tracks surplus funds of FirstEnergy and
the respective regulated and unregulated subsidiaries, as well as proceeds
available from bank borrowings. Companies receiving a loan under the money pool
agreements must repay the principal amount of the loan, together with accrued
interest, within 364 days of borrowing the funds. The rate of interest is the
same for each company receiving a loan from their respective pool and is based
on the average cost of funds available through the pool. The average interest
rate for borrowings in the first nine months of 2008 was 3.13% for the regulated
companies’ money pool and 3.09% for the unregulated companies’ money
pool.





FirstEnergy’s access
to capital markets and costs of financing are influenced by the ratings of its
securities. The following table displays FirstEnergy’s, FES’ and the Utilities’
securities ratings as of November 5, 2008. On August 1, 2008, S&P
changed its outlook for FirstEnergy and its subsidiaries from “negative” to
“stable.” On November 5, 2008, S&P raised its senior unsecured rating
on OE, Penn, CEI and TE to BBB from BBB-. Moody’s outlook for FirstEnergy and
its subsidiaries remains “stable.”





Issuer
            
            Securities
            
            S&P
            
            Moody’sFirstEnergy
            
            Senior
      unsecured
            
            BBB-
            
            Baa3FES
            
            Senior
      unsecured
            
            BBB
            
            Baa2OE
            
            Senior
      secured
            
            BBB+
            
            Baa1Senior
      unsecured
            
            BBB
            
            Baa2CEI
            
            Senior
      secured
            
            BBB+
            
            Baa2Senior
      unsecured
            
            BBB
            
            Baa3TE
            
            Senior
      unsecured
            
            BBB
            
            Baa3Penn
            
            Senior
      secured
            
            A-
            
            Baa1JCP&L
            
            Senior
      unsecured
            
            BBB
            
            Baa2Met-Ed
            
            Senior
      unsecured
            
            BBB
            
            Baa2Penelec
            
            Senior
      unsecured
            
            BBB
            
            Baa2








24





Cash Flows from Investing
Activities





Net cash flows used
in investing activities resulted principally from property additions. Additions
for the energy delivery services segment primarily include expenditures related
to transmission and distribution facilities. Capital spending by the competitive
energy services segment is principally generation-related. The following table
summarizes investing activities for the nine months ended September 30, 2008,
and 2007 by business segment:





Summary
      of Cash Flows Provided from
                
                Property(Used
      for) Investing Activities
                
                Additions
                
                Investments
                
                Other
                
                TotalSources
      (Uses)
                
                (In
      millions)Nine
      Months Ended September 30, 2008Energy
      delivery services
                
                $
                (621
                )
                $
                33
                
                $
                (3
                )
                $
                (591
                )Competitive
      energy services(1)
                
                
                (1,430
                )
                
                (13
                )
                
                (121
                )
                
                (1,564
                )Other(2)
                
                
                (106
                )
                
                57
                
                
                (54
                )
                
                (103
                )Inter-Segment
      reconciling items
                
                
                (20
                )
                
                (12
                )
                
                -
                
                
                (32
                )Total
                
                $
                (2,177
                )
                $
                65
                
                $
                (178
                )
                $
                (2,290
                )Nine
      Months Ended September 30, 2007Energy
      delivery services
                
                $
                (609
                )
                $
                6
                
                $
                (2
                )
                $
                (605
                )Competitive
      energy services
                
                
                (462
                )
                
                1,311
                
                
                2
                
                
                851Other
                
                
                (6
                )
                
                (4
                )
                
                1
                
                
                (9
                )Inter-Segment
      reconciling items
                
                
                (50
                )
                
                (15
                )
                
                -
                
                
                (65
                )Total
                
                $
                (1,127
                )
                $
                1,298
                
                $
                1
                
                $
                172(1)Other
      investing activities include approximately $82 million in restricted
      funds to redeem outstanding debt in the fourth quarter of
      2008.
                  (2)Other
      investing activities include approximately $64 million in cash
      investments for the equity interest in Signal Peak.




Net cash used for
investing activities was $2.3 billion in the first nine months of 2008 compared
to net cash provided from investing activities of $172 million in the first nine
months of 2007. The change was principally due to a $1.1 billion increase in
property additions and the absence of $1.3 billion of proceeds from the Bruce
Mansfield Unit 1 sale and leaseback transaction in the third quarter of 2007.
The increased property additions reflected the acquisitions described above and
higher planned air quality control system expenditures in the first nine months
of 2008.





During the remaining
three months of 2008, capital requirements for property additions and capital
leases are expected to be approximately $555 million, including $88 million for
nuclear fuel. As of September 30, 2008, FirstEnergy had additional requirements
of approximately $138 million for maturing long-term debt during the remainder
of 2008, of which $125 million was redeemed in October 2008. These cash
requirements are expected to be satisfied from a combination of internal cash,
short-term credit arrangements and funds raised in the capital
markets.





FirstEnergy's
capital spending for the period 2008-2012 is expected to be approximately
$7.6 billion (excluding nuclear fuel, the purchase of nuclear sale and
leaseback lessor equity interests, and the acquisition of Signal Peak), of which
approximately $2.1 billion applies to 2008. Investments for additional
nuclear fuel during the 2008-2012 period are estimated to be approximately
$1.2 billion, of which about $167 million applies to 2008. During the
same periods, FirstEnergy's nuclear fuel investments are expected to be reduced
by approximately $892 million and $111 million, respectively, as the
nuclear fuel is consumed.





While FirstEnergy
believes its existing sources of liquidity will continue to be available to meet
its anticipated obligations, management is reviewing its 2009 plans to determine
what adjustments should be made to operating and capital budgets in response to
the economic climate to reduce the need for external sources of capital.
Management plans to reassess the economic value of discretionary projects;
however, it expects to continue to meet commitments for required capital
projects and necessary operational expenditures.Although this process is
not yet complete, management expects that FirstEnergy's capital expenditures
will be reduced from the levels previously anticipated.





GUARANTEES
AND OTHER ASSURANCES





As part of normal
business activities, FirstEnergy enters into various agreements on behalf of its
subsidiaries to provide financial or performance assurances to third parties.
These agreements include contract guarantees, surety bonds and LOCs. Some of the
guaranteed contracts contain collateral provisions that are contingent upon
either FirstEnergy’s or its subsidiaries’ credit ratings.





As of
September 30, 2008, FirstEnergy’s maximum exposure to potential future
payments under outstanding guarantees and other assurances approximated
$4.2 billion, as summarized below:





25








MaximumGuarantees
      and Other Assurances
            
            Exposure(In
      millions)FirstEnergy
      Guarantees of SubsidiariesEnergy and
      Energy-Related Contracts (1)
            
            $
            408LOC (long-term
      debt) – interest coverage (2)
            
            
            6Other (3)
            
            
            503917Subsidiaries’
      GuaranteesEnergy and
      Energy-Related Contracts
            
            
            86LOC (long-term
      debt) – interest coverage (2)
            
            
            11FES’ guarantee
      of FGCO’s sale and leaseback obligations
            
            
            2,5912,688Surety
      Bonds
            
            
            94LOC (long-term
      debt) – interest coverage (2)
            
            
            5LOC (non-debt)
      (4)(5)
            
            
            463562Total
      Guarantees and Other Assurances
            
            $
            4,167





(1)
            Issued for
      open-ended terms, with a 10-day termination right by
      FirstEnergy.


(2)
            Reflects the
      interest coverage portion of LOCs issued in support of floating-rate
              PCRBs with
      various maturities. The principal amount of floating-rate PCRBs of
              $2.1 billion
      is reflected as debt on FirstEnergy’s consolidated balance
      sheets.


(3)
            Includes
      guarantees of $300 million for OVEC obligations and $80 million
      for
              nuclear
      decommissioning funding assurances.


(4)
            Includes
      $38 million issued for various terms pursuant to LOC capacity
      available
              under
      FirstEnergy’s revolving credit
facility.


(5)
            Includes
      approximately $291 million pledged in connection with the sale and
              leaseback of
      Beaver Valley Unit 2 by OE and $134 million pledged in connection
              with the sale
      and leaseback of Perry Unit 1 by
OE.





FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved in
energy commodity activities principally to facilitate or hedge normal physical
transactions involving electricity, gas, emission allowances and coal.
FirstEnergy also provides guarantees to various providers of credit support for
the financing or refinancing by subsidiaries of costs related to the acquisition
of property, plant and equipment. These agreements legally obligate FirstEnergy
to fulfill the obligations of those subsidiaries directly involved in energy and
energy-related transactions or financings where the law might otherwise limit
the counterparties' claims. If demands of a counterparty were to exceed the
ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee
enables the counterparty's legal claim to be satisfied by other FirstEnergy
assets. The likelihood is remote that such parental guarantees will increase
amounts otherwise paid by FirstEnergy to meet its obligations incurred in
connection with ongoing energy and energy-related activities.





While these types of
guarantees are normally parental commitments for the future payment of
subsidiary obligations, subsequent to the occurrence of a credit rating
downgrade to below investment grade or “material adverse event,” the immediate
posting of cash collateral, provision of an LOC or accelerated payments may be
required of the subsidiary. As of September 30, 2008, FirstEnergy's maximum
exposure under these collateral provisions was $573 million as shown
below:





Collateral
      Provisions
            
            FES
            
            Utilities
            
            Total(in
      millions)Credit rating
      downgrade to
              below
      investment grade
            
            $
            216
            
            $
            293
            
            $
            509Material
      adverse event
            
            
            56
            
            
            8
            
            
            64Total
            
            $
            272
            
            $
            301
            
            $
            573





Additionally, stress
case conditions of a credit rating downgrade or “material adverse event” and
hypothetical adverse price movements in the underlying commodity markets would
increase the total potential amount to $648 million, consisting of $58 million
due to “material adverse event” contractual clauses and $590 million due to a
below investment grade credit rating.


FES, through
potential participation in utility sponsored competitive power procurement
processes (including those of affiliates) or through forward hedging
transactions and as a consequence of future power price movements, could be
required to post significantly higher collateral to support its power
transactions.


26








Most of
FirstEnergy’s surety bonds are backed by various indemnities common within the
insurance industry. Surety bonds and related guarantees provide additional
assurance to outside parties that contractual and statutory obligations will be
met in a number of areas including construction contracts, environmental
commitments and various retail transactions.





OFF-BALANCE
SHEET ARRANGEMENTS





FES and the Ohio
Companies have obligations that are not included on FirstEnergy’s Consolidated
Balance Sheets related to sale and leaseback arrangements involving the Bruce
Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are
satisfied through operating lease payments. The total present value of these
sale and leaseback operating lease commitments, net of trust investments,
decreased to $1.8 billion as of September 30, 2008, from $2.3 billion as of
December 31, 2007, due primarily to NGC’s purchase of certain lessor equity
interests in Perry Unit 1 and Beaver Valley Unit 2 (see Note
9).





FirstEnergy has
equity ownership interests in certain businesses that are accounted for using
the equity method of accounting for investments. There are no undisclosed
material contingencies related to these investments. Certain guarantees that
FirstEnergy does not expect to have a material current or future effect on its
financial condition, liquidity or results of operations are disclosed under
“Guarantees and Other Assurances” above.





MARKET
RISK INFORMATION





FirstEnergy uses
various market risk sensitive instruments, including derivative contracts,
primarily to manage the risk of price and interest rate fluctuations.
FirstEnergy's Risk Policy Committee, comprised of members of senior management,
provides general oversight for risk management activities throughout the
company.





Commodity Price Risk





FirstEnergy is
exposed to financial and market risks resulting from the fluctuation of interest
rates and commodity prices -- electricity, energy transmission, natural gas,
coal, nuclear fuel and emission allowances. To manage the volatility relating to
these exposures, FirstEnergy uses a variety of non-derivative and derivative
instruments, including forward contracts, options, futures contracts and swaps.
The derivatives are used principally for hedging purposes. Derivatives that fall
within the scope of SFAS 133 must be recorded at their fair value and
marked to market. The majority of FirstEnergy’s derivative hedging contracts
qualify for the normal purchase and normal sale exception under SFAS 133
and are therefore excluded from the tables below. Contracts that are not exempt
from such treatment include certain power purchase agreements with NUG entities
that were structured pursuant to the Public Utility Regulatory Policies Act of
1978. These non-trading contracts are adjusted to fair value at the end of each
quarter, with a corresponding regulatory asset recognized for above-market
costs. The changes in the fair value of commodity derivative contracts related
to energy production during the three months and nine months ended September 30,
2008 are summarized in the following table:





Three
      Months
            
            Nine
      MonthsIncrease
      (Decrease) in the Fair Value
            
            Ended
      September 30, 2008
            
            Ended
      September 30, 2008of Derivative
Contracts
            
            Non-Hedge
            
            Hedge
            
            Total
            
            Non-Hedge
            
            Hedge
            
            Total(In
      millions)Change
      in the Fair Value ofCommodity
      Derivative Contracts:Outstanding
      net liability at beginning of period
            
            $
            (616
            )
            $
            (37
            )
            $
            (653
            )
            $
            (713
            )
            $
            (26
            )
            $
            (739
            )Additions/change
      in value of existing contracts
            
            
            23
            
            
            33
            
            
            56
            
            
            (10
            )
            
            9
            
            
            (1
            )Settled
      contracts
            
            
            18
            
            
            (6
            )
            
            12
            
            
            148
            
            
            7
            
            
            155Outstanding
      net liability at end of period (1)
            
            
            (575
            )
            
            (10
            )
            
            (585
            )
            
            (575
            )
            
            (10
            )
            
            (585
            )Non-commodity
      Net Assets at End of Period:Interest rate
      swaps (2)
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Net
      Liabilities - Derivative Contracts
              at
      End of Period
            
            $
            (575
            )
            $
            (10
            )
            $
            (585
            )
            $
            (575
            )
            $
            (10
            )
            $
            (585
            )Impact
      of Changes in Commodity Derivative Contracts(3)Income
      Statement effects (pre-tax)
            
            $
            (1
            )
            $
            -
            
            $
            (1
            )
            $
            -
            
            $
            -
            
            $
            -Balance Sheet
      effects:Other
      comprehensive income (pre-tax)
            
            $
            -
            
            $
            27
            
            $
            27
            
            $
            -
            
            $
            16
            
            $
            16Regulatory
      assets (net)
            
            $
            (42
            )
            $
            -
            
            $
            (42
            )
            $
            (138
            )
            $
            -
            
            $
            (138
            )





(1)
            Includes
      $575 million in non-hedge commodity derivative contracts (primarily
      with NUGs) that are offset by a regulatory
  asset.


(2)
            Interest rate
      swaps are treated as cash flow or fair value hedges (see Interest Rate
      Swap Agreements below).


(3)
            Represents the
      change in value of existing contracts, settled contracts and changes in
      techniques/assumptions.





27








Derivatives
      are included on the Consolidated Balance Sheet as of September 30,
      2008 as follows:





Balance
      Sheet Classification
            
            Non-Hedge
            
            Hedge
            
            Total(In
      millions)Current-Other
      assets
            
            $
            -
            
            $
            14
            
            $
            14Other
      liabilities
            
            
            -
            
            
            (26
            )
            
            (26
            )Non-Current-Other deferred
      charges
            
            
            28
            
            
            3
            
            
            31Other
      non-current liabilities
            
            
            (603
            )
            
            (1
            )
            
            (604
            )Net
      liabilities
            
            $
            (575
            )
            $
            (10
            )
            $
            (585
            )








The valuation of
derivative contracts is based on observable market information to the extent
that such information is available. In cases where such information is not
available, FirstEnergy relies on model-based information. The model provides
estimates of future regional prices for electricity and an estimate of related
price volatility. FirstEnergy uses these results to develop estimates of fair
value for financial reporting purposes and for internal management decision
making (see Note 5). Sources of information for the valuation of commodity
derivative contracts as of September 30, 2008 are summarized by year in the
following table:





Source
      of Information-
      Fair Value by Contract Year
            
            2008(1)
            
            2009
            
            2010
            
            2011
            
            2012
            
            Thereafter
            
            Total(In
      millions)Prices
      actively quoted(2)
            
            $
            (2)
            
            $
            (5)
            
            $
            (1)
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            (8)Other external
      sources(3)
            
            
            (58)
            
            
            (182)
            
            
            (151)
            
            
            (106)
            
            
            -
            
            
            -
            
            
            (497)Prices based
      on models
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (32)
            
            
            (48)
            
            
            (80)Total(4)
            
            $
            (60)
            
            $
            (187)
            
            $
            (152)
            
            $
            (106)
            
            $
            (32)
            
            $
            (48)
            
            $
            (585)





(1)     For
the last quarter of 2008.


(2)     Represents
exchange traded NYMEX futures and options.


(3)     Primarily
represents contracts based on broker and Intercontinental Exchange
quotes.


(4) Includes
$575 million in non-hedge commodity derivative contracts (primarily with
NUGs) that are offset by a regulatory asset.





FirstEnergy performs
sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift (an increase or decrease
depending on the derivative position) in quoted market prices in the near term
on its derivative instruments would not have had a material effect on its
consolidated financial position (assets, liabilities and equity) or cash flows
as of September 30, 2008. Based on derivative contracts held as of
September 30, 2008, an adverse 10% change in commodity prices would
decrease net income by approximately $1 million during the next 12
months.





Interest Rate Swap Agreements - Fair
Value Hedges





FirstEnergy
historically utilized fixed-for-floating interest rate swap agreements as part
of its effort to manage interest rate risk associated with its debt portfolio.
In order to reduce counterparty exposure and lessen variable debt exposure under
the current market conditions, FirstEnergy unwound its remaining interest rate
swaps. During the first nine months of 2008, FirstEnergy received
$3 million to terminate interest rate swaps with an aggregate notional
value of $250 million. As of September 30, 2008, FirstEnergy had no
outstanding interest rate swaps hedging the current debt portfolio.





Forward Starting Swap Agreements -
Cash Flow Hedges





FirstEnergy utilizes
forward starting swap agreements (forward swaps) in order to hedge a portion of
the consolidated interest rate risk associated with anticipated future issuances
of fixed-rate, long-term debt securities for one or more of its consolidated
subsidiaries in 2008 and 2009, and anticipated variable-rate, short-term debt.
These derivatives are treated as cash flow hedges, protecting against the risk
of changes in future interest payments resulting from changes in benchmark U.S.
Treasury and LIBOR rates between the date of hedge inception and the date of the
debt issuance. FirstEnergy considers counterparty credit and nonperformance risk
in its hedge assessments and continues to expect the forward-starting swaps to
be effective in protecting against the risk of changes in future interest
payments. During the first nine months of 2008, FirstEnergy entered into forward
swaps with an aggregate notional value of $950 million and terminated
forward swaps with an aggregate notional value of $750million. FirstEnergy
paid $16 million in cash related to the terminations, $5 million of
which was deemed ineffective and recognized in current period earnings. The
remaining effective portion will be recognized over the terms of the associated
future debt. As of September 30, 2008, FirstEnergy had outstanding forward
swaps with an aggregate notional amount of $600 million and an aggregate
fair value of $(0.2) million.





28








September
      30, 2008
            
            December
      31, 2007Notional
            
            Maturity
            
            Fair
            
            Notional
            
            Maturity
            
            FairForward
      Starting Swaps
            
            Amount
            
            Date
            
            Value
            
            Amount
            
            Date
            
            Value(In
      millions)Cash flow
      hedges
            
            $
            100
            
            
            2009
            
            $
            -
            
            $
            -
            
            
            2009
            
            $
            -100
            
            
            2010
            
            
            -
            
            
            -
            
            
            2010
            
            
            --
            
            
            2015
            
            
            -
            
            
            25
            
            
            2015
            
            
            (1
            )350
            
            
            2018
            
            
            -
            
            
            325
            
            
            2018
            
            
            (1
            )50
            
            
            2020
            
            
            -
            
            
            50
            
            
            2020
            
            
            (1
            )$
            600
            
            
            
            
            $
            -
            
            $
            400
            
            
            
            
            $
            (3
            )





Equity Price Risk





FirstEnergy provides
noncontributory defined benefit pension plans that cover substantially all of
its subsidiaries’ employees. The plans provide defined benefits based on years
of service and compensation levels. The benefit plan assets and obligations of
FirstEnergy are remeasured annually using a December 31 measurement date.
Reductions in plan assets from investment losses will result in a decrease to
the plans’ funded status and a decrease in common stockholders’ equity upon
actuarial revaluation of the plan on January 1, 2009.





As of
December 31, 2007, FirstEnergy’s pension plan was overfunded, and,
therefore, FirstEnergy will not be required to make any contributions in 2009
for the 2008 plan year. The overall actual investment return as of
October 31, 2008 was a loss of 25.4% compared to an assumed 9% positive
return. Based on an 8% discount rate assumption, if the ultimate return for 2008
was to remain at a loss of 25.4%, 2009 pre-tax net periodic pension expense
would be approximately $145 million, an increase of approximately $180
million compared to the year 2008. If the ultimate return for 2008 were to
remain at a loss of 25.4%, FirstEnergy would not be required to make
contributions in 2010. However, if the assets were to decline an additional 1%
from October 31, 2008 through the end of 2008, contributions of
approximately $65 million would be required in 2010.





This information
does not consider any actions management may take to mitigate the impact of the
asset return shortfalls, including changes in the amount and timing of future
contributions. The actuarial assumptions used in the determination of pension
and postretirement benefit costs are interrelated and changes in other
assumptions could have the impact of offsetting all or a portion of the
potential increase in benefit costs set forth above.





Nuclear
decommissioning trust funds have been established to satisfy NGC’s and the
Utilities’ nuclear decommissioning obligations. As of September 30, 2008,
approximately 47% of the funds were invested in equity securities and 53% were
invested in fixed income securities, with limitations related to concentration
and investment grade ratings. The equity securities are carried at their market
value of approximately $879 million as of September 30, 2008. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in an
$88 million reduction in fair value as of September 30, 2008. The
decommissioning trusts of JCP&L and the Pennsylvania Companies are subject
to regulatory accounting, with unrealized gains and losses recorded as
regulatory assets or liabilities, since the difference between investments held
in trust and the decommissioning liabilities will be recovered from or refunded
to customers. NGC, OE and TE recognize in earnings the unrealized losses on
available-for-sale securities held in their nuclear decommissioning
trusts. Nuclear decommissioning trust securities impairments totaled $63
million in the first nine months of 2008. FirstEnergy does not expect to make
additional cash contributions to the nuclear decommissioning trusts in 2009,
other than the required annual TMI-2 trust contribution that is collected
through customer rates. However, should the trust funds continue to experience
declines in market value, FirstEnergy may be required to take measures, such as
providing financial guarantees through letters of credit or parental guarantees
or making additional contributions to the trusts to ensure that the trusts are
adequately funded and meet minimum NRC funding requirements.





CREDIT
RISK





Credit risk is the
risk of an obligor's failure to meet the terms of any investment contract, loan
agreement or otherwise perform as agreed. Credit risk arises from all activities
in which success depends on issuer, borrower or counterparty performance,
whether reflected on or off the balance sheet. FirstEnergy engages in
transactions for the purchase and sale of commodities including gas,
electricity, coal and emission allowances. These transactions are often with
major energy companies within the industry.





FirstEnergy
maintains credit policies with respect to its counterparties to manage overall
credit risk. This includes performing independent risk evaluations, actively
monitoring portfolio trends and using collateral and contract provisions to
mitigate exposure. As part of its credit program, FirstEnergy aggressively
manages the quality of its portfolio of energy contracts, evidenced by a current
weighted average risk rating for energy contract counterparties of BBB+
(S&P). As of September 30, 2008, the largest credit concentration was
with JPMorgan Chase, which is currently rated investment grade, representing
10.7% of FirstEnergy’s total approved credit risk. Within FirstEnergy’s
unregulated energy subsidiaries, 99% of existing credit, net of collateral and
reserve, were with investment-grade counterparties as of September 30,
2008.





29








OUTLOOK





State Regulatory Matters





In Ohio, New Jersey
and Pennsylvania, laws applicable to electric industry restructuring contain
similar provisions that are reflected in the Utilities' respective state
regulatory plans. These provisions include:





·
            restructuring
      the electric generation business and allowing the Utilities' customers to
      select a competitive electric generation supplier other than the
      Utilities;·
            establishing
      or defining the PLR obligations to customers in the Utilities' service
      areas;·
            providing the
      Utilities with the opportunity to recover certain costs not otherwise
      recoverable in a competitive generation market;·
            itemizing
      (unbundling) the price of electricity into its component elements –
      including generation, transmission, distribution and stranded costs
      recovery charges;·
            continuing
      regulation of the Utilities' transmission and distribution systems;
      and·
            requiring
      corporate separation of regulated and unregulated business
      activities.





The Utilities and
ATSI recognize, as regulatory assets, costs which the FERC, the PUCO, the PPUC
and the NJBPU have authorized for recovery from customers in future periods or
for which authorization is probable. Without the probability of such
authorization, costs currently recorded as regulatory assets would have been
charged to income as incurred. Regulatory assets that do not earn a current
return totaled approximately $128 million as of September 30, 2008
(JCP&L - $64 million and Met-Ed - $64 million). Regulatory assets
not earning a current return (primarily for certain regulatory transition costs
and employee postretirement benefits) are expected to be recovered by 2014 for
JCP&L and by 2020 for Met-Ed. The following table discloses regulatory
assets by company:





September
      30,
            
            December
      31,
            
            IncreaseRegulatory
      Assets*
            
            2008
            
            2007
            
            (Decrease)(In
      millions)OE
            
            $
            621
            
            $
            737
            
            $
            (116
            )CEI
            
            
            796
            
            
            871
            
            
            (75
            )TE
            
            
            145
            
            
            204
            
            
            (59
            )JCP&L
            
            
            1,295
            
            
            1,596
            
            
            (301
            )Met-Ed
            
            
            541
            
            
            495
            
            
            46ATSI
            
            
            35
            
            
            42
            
            
            (7
            )Total
            
            $
            3,433
            
            $
            3,945
            
            $
            (512
            )





*
            Penelec had
      net regulatory liabilities of approximately $105 million and
      $74 million as
              of
      September 30, 2008 and December 31, 2007, respectively. These
      net regulatory
              liabilities
      are included in Other Non-current Liabilities on the Consolidated Balance
      Sheets.





Regulatory assets by
source are as follows:





September
      30,
            
            December
      31,
            
            IncreaseRegulatory
      Assets By Source
            
            2008
            
            2007
            
            (Decrease)(In
      millions)Regulatory
      transition costs
            
            $
            1,770
            
            $
            2,363
            
            $
            (593
            )Customer
      shopping incentives
            
            
            447
            
            
            516
            
            
            (69
            )Customer
      receivables for future income taxes
            
            
            247
            
            
            295
            
            
            (48
            )Loss on
      reacquired debt
            
            
            52
            
            
            57
            
            
            (5
            )Employee
      postretirement benefits
            
            
            33
            
            
            39
            
            
            (6
            )Nuclear
      decommissioning, decontaminationand spent fuel
      disposal costs
            
            
            (81
            )
            
            (115
            )
            
            34Asset removal
      costs
            
            
            (207
            )
            
            (183
            )
            
            (24
            )MISO/PJM
      transmission costs
            
            
            397
            
            
            340
            
            
            57Fuel costs -
      RCP
            
            
            213
            
            
            220
            
            
            (7
            )Distribution
      costs - RCP
            
            
            450
            
            
            321
            
            
            129Other
            
            
            112
            
            
            92
            
            
            20Total
            
            $
            3,433
            
            $
            3,945
            
            $
            (512
            )








30





Reliability Initiatives





In late 2003 and
early 2004, a series of letters, reports and recommendations were issued from
various entities, including governmental, industry and ad hoc reliability
entities (the PUCO, the FERC, the NERC and the U.S. – Canada Power System Outage
Task Force) regarding enhancements to regional reliability. The proposed
enhancements were divided into two groups:  enhancements that were to
be completed in 2004; and enhancements that were to be completed after
2004.  In 2004, FirstEnergy completed all of the enhancements that
were recommended for completion in 2004. FirstEnergy is also proceeding with the
implementation of the recommendations that were to be completed subsequent to
2004 and will continue to periodically assess the FERC-ordered Reliability Study
recommendations for forecasted 2009 system conditions, recognizing revised load
forecasts and other changing system conditions which may impact the
recommendations. Thus far, implementation of the recommendations has not
required, nor is expected to require, substantial investment in new or material
upgrades to existing equipment. The FERC or other applicable government agencies
and reliability coordinators may, however, take a different view as to
recommended enhancements or may recommend additional enhancements in the future
that could require additional material expenditures.





As a result of
outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU
performed a review of JCP&L’s service reliability. On June 9, 2004, the
NJBPU approved a stipulation that addresses a third-party consultant’s
recommendations on appropriate courses of action necessary to ensure system-wide
reliability. The stipulation incorporates the consultant’s focused audit of, and
recommendations regarding, JCP&L’s Planning and Operations and Maintenance
programs and practices. On June 1, 2005, the consultant completed his work and
issued his final report to the NJBPU. On July 14, 2006, JCP&L filed a
comprehensive response to the consultant’s report with the NJBPU. JCP&L will
complete the remaining substantive work described in the stipulation in
2008.  JCP&L continues to file compliance reports with the NJBPU
reflecting JCP&L’s activities associated with implementing the
stipulation.





In 2005, Congress
amended the Federal Power Act to provide for federally-enforceable mandatory
reliability standards. The mandatory reliability standards apply to the bulk
power system and impose certain operating, record-keeping and reporting
requirements on the Utilities and ATSI. The NERC is charged with establishing
and enforcing these reliability standards, although it has delegated day-to-day
implementation and enforcement of its responsibilities to eight regional
entities, including ReliabilityFirst
Corporation.  All of FirstEnergy’s facilities are located within the
ReliabilityFirst
region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes,
and otherwise monitors and manages its companies in response to the ongoing
development, implementation and enforcement of the reliability
standards.





FirstEnergy believes
that it is in compliance with all currently-effective and enforceable
reliability standards.  Nevertheless, it is clear that the NERC,
ReliabilityFirst and
the FERC will continue to refine existing reliability standards as well as to
develop and adopt new reliability standards. The financial impact of complying
with new or amended standards cannot be determined at this time. However, the
2005 amendments to the Federal Power Act provide that all prudent costs incurred
to comply with the new reliability standards be recovered in rates. Still, any
future inability on FirstEnergy’s part to comply with the reliability standards
for its bulk power system could result in the imposition of financial penalties
and thus have a material adverse effect on its financial condition, results of
operations and cash flows.





In April 2007,
ReliabilityFirst
performed a routine compliance audit of FirstEnergy’s bulk-power system within
the Midwest ISO region and found it to be in full compliance with all audited
reliability standards.  Similarly, ReliabilityFirst scheduled a compliance
audit of FirstEnergy’s bulk-power system within the PJM region in October 2008.
FirstEnergy currently does not expect any material adverse financial impact as a
result of these audits.





Ohio





On January 4,
2006, the PUCO issued an order authorizing the Ohio Companies to recover certain
increased fuel costs through a fuel rider and to defer certain other increased
fuel costs to be incurred from January 1, 2006 through December 31,
2008, including interest on the deferred balances. The order also provided for
recovery of the deferred costs over a twenty-five-year period through
distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that
the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio
Companies “to collect deferred increased fuel costs through future distribution
rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred
distribution-related expenses” and remanded the matter to the PUCO for further
consideration. On September 10, 2007 the Ohio Companies filed an
application with the PUCO that requested the implementation of two
generation-related fuel cost riders to collect the increased fuel costs that
were previously authorized to be deferred. On January 9, 2008 the PUCO
approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel
costs to be incurred in 2008 commencing January 1, 2008 through
December 31, 2008, which is expected to be approximately $189 million.
In addition, the PUCO ordered the Ohio Companies to file a separate application
for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel
costs. On February 8, 2008, the Ohio Companies filed an application
proposing to recover $226 million of deferred fuel costs and carrying
charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the
deferred fuel costs is addressed in the Ohio Companies’ comprehensive ESP
filing, as described below. If the recovery of the deferred fuel costs is not
resolved in the ESP, or in the event the MRO is implemented, recovery of the
deferred fuel costs will be resolved in the proceeding that was instituted with
the PUCO on February 8, 2008, as referenced above.








31








On June 7, 2007, the
Ohio Companies filed an application for an increase in electric distribution
rates with the PUCO and, on August 6, 2007, updated their filing to support
a distribution rate increase of $332 million. On December 4, 2007, the
PUCO Staff issued its Staff Reports containing the results of its investigation
into the distribution rate request. In its reports, the PUCO Staff recommended a
distribution rate increase in the range of $161 million to $180 million,
with $108 million to $127 million for distribution revenue increases and
$53 million for recovery of costs deferred under prior cases. Evidentiary
hearings began on January 29, 2008 and continued through February 25, 2008.
During the evidentiary hearings and filing of briefs, the PUCO Staff decreased
their recommended revenue increase to a range of $117 million to
$135 million. Additionally, in testimony submitted on February 11,
2008, the PUCO Staff adopted a position regarding interest deferred for
RCP-related deferrals, line extension deferrals and transition tax deferrals
that, if upheld by the PUCO, would result in the write-off of approximately
$58 million of interest costs deferred through September 30, 2008
($0.12 per share of common stock). The Ohio Companies’ electric distribution
rate request is addressed in their comprehensive ESP filing, as described
below.





On May 1, 2008,
Governor Strickland signed SB221, which became effective on July 31, 2008.
The bill requires all utilities to file an ESP with the PUCO. A utility also may
file an MRO in which it would have to prove the following objective market
criteria:





·
            the utility or
      its transmission service affiliate belongs to a FERC approved RTO, or
      there is comparable and nondiscriminatory access to the electric
      transmission grid;





·
            the RTO has a
      market-monitor function and the ability to mitigate market power or the
      utility’s market conduct, or a similar market monitoring function exists
      with the ability to identify and monitor market conditions and conduct;
      and





·
            a published
      source of information is available publicly or through subscription that
      identifies pricing information for traded electricity products, both on-
      and off-peak, scheduled for delivery two years into the
      future.





On July 31, 2008,
the Ohio Companies filed with the PUCO a comprehensive ESP and MRO. The MRO
outlines a CBP that would be implemented if the ESP is not approved by the PUCO.
Under SB221, a PUCO ruling on the ESP filing is required within 150 days and an
MRO decision is required within 90 days. The ESP proposes to phase in new
generation rates for customers beginning in 2009 for up to a three-year period
and would resolve the Ohio Companies’ collection of fuel costs deferred in 2006
and 2007, and the distribution rate request described above. Major provisions of
the ESP include:





·
            a phase-in of
      new generation rates for up to a three-year period, whereby customers
      would receive a 10% phase-in credit; related costs (expected to
      approximate $429 million in 2009, $488 million in 2010 and $553 million in
      2011) would be deferred for future collection over a period not to exceed
      10 years;





·
            a reconcilable
      rider to recover fuel transportation cost surcharges in excess of $30
      million in 2009, $20 million in 2010 and $10 million in
    2011;





·
            generation
      rate adjustments to recover any increase in fuel costs in 2011 over fuel
      costs incurred in 2010 for FES’ generation assets used to support the
      ESP;





·
            generation
      rate adjustments to recover the costs of complying with new requirements
      for certain renewable energy resources, new taxes and new environmental
      laws or new interpretations of existing laws that take effect after
      January 1, 2008 and exceed $50 million during the plan
    period;





·
            an RCP fuel
      rider to recover the 2006 and 2007 deferred fuel costs and carrying
      charges (described above) over a period not to exceed 25
      years;





·
            the resolution
      of outstanding issues pending in the Ohio Companies’ distribution rate
      case (described above), including annual electric distribution rate
      increases of $75 million for OE, $34.5 million for CEI and $40.5 million
      for TE. The new distribution rates would be effective January 1, 2009, for
      OE and TE and May 1, 2009 for CEI, with a commitment to maintain
      distribution rates through 2013. CEI also would be authorized to defer $25
      million in distribution-related costs incurred from January 1, 2009,
      through April 30, 2009;





·
            an adjustable
      delivery service improvement rider, effective January 1, 2009, through
      December 31, 2013, to ensure the Ohio Companies maintain and improve
      customer standards for service and
reliability;





·
            the waiver of
      RTC charges for CEI’s customers as of January 1, 2009, which would
      result in CEI’s write-off of approximately $485 million of estimated
      unrecoverable transition costs ($1.01 per share of common
      stock);





32








·
            the continued
      recovery of transmission costs, including MISO, ancillary services and
      congestion charges, through an annually adjusted transmission rider; a
      separate rider will be established to recover costs incurred annually
      between May 1st
      and September 30th
      for capacity purchases required to meet FERC, NERC, MISO and other
      applicable standards for planning reserve margin requirements in excess of
      amounts provided by FES as described in the ESP (the separate application
      for the recovery of these costs was filed on October 17,
      2008);





·
            a deferred
      transmission cost recovery rider effective January 1, 2009, through
      December 31, 2010 to recover transmission costs deferred by the Ohio
      Companies in 2005 and accumulated carrying charges through December 31,
      2008; a deferred distribution cost recovery rider effective
      January 1, 2011, to recover distribution costs deferred under the
      RCP, CEI’s additional $25 million of cost deferrals in 2009, line
      extension deferrals and transition tax
  deferrals;





·
            the deferral
      of annual storm damage expenses in excess of $13.9 million, certain line
      extension costs, as well as depreciation, property tax obligations and
      post in-service carrying charges on energy delivery capital investments
      for reliability and system efficiency placed in service after December 31,
      2008. Effective January 1, 2014, a rider will be established to collect
      the deferred balance and associated carrying charges over a 10-year
      period; and





·
            a commitment
      by the Ohio Companies to invest in aggregate at least $1 billion in
      capital improvements in their energy delivery systems through 2013 and
      fund $25 million for energy efficiency programs and $25 million
      for economic development and job retention programs through
      2013.





Evidentiary hearings
in the ESP case concluded on October 31, 2008 and no further hearings are
scheduled. The parties are required to submit initial briefs by November 21,
2008, with all reply briefs due by December 12, 2008.





The Ohio Companies’
MRO filing outlines a CBP for providing retail generation supply if the ESP is
not approved by the PUCO or is changed and not accepted by the Ohio Companies.
The CBP would use a “slice-of-system” approach where suppliers bid on tranches
(approximately 100 MW) of the Ohio Companies’ total customer load. If the Ohio
Companies proceed with the MRO option, successful bidders (including affiliates)
would be required to post independent credit requirements and could be subject
to significant collateral calls depending upon power price movement. On
September 16, 2008, the PUCO staff filed testimony and evidentiary hearings
were held. The PUCO failed to act on October 29, 2008 as required under the
statute.  The Ohio Companies are unable to predict the outcome of this
proceeding.





The Ohio Companies
included an interim pricing proposal as part of their ESP filing, if additional
time is necessary for final PUCO approval of either the ESP or MRO. FES will be
required to obtain FERC authorization to sell electric capacity or energy to the
Ohio Companies under the ESP or MRO, unless a waiver is obtained (see FERC
Matters).





Pennsylvania





Met-Ed and Penelec
purchase a portion of their PLR and default service requirements from FES
through a fixed-price partial requirements wholesale power sales agreement. The
agreement allows Met-Ed and Penelec to sell the output of NUG energy to the
market and requires FES to provide energy at fixed prices to replace any NUG
energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and
default service obligations. The fixed price under the agreement is expected to
remain below wholesale market prices during the term of the agreement. If Met-Ed
and Penelec were to replace the entire FES supply at current market power prices
without corresponding regulatory authorization to increase their generation
prices to customers, each company would likely incur a significant increase in
operating expenses and experience a material deterioration in credit quality
metrics. Under such a scenario, each company's credit profile would no longer be
expected to support an investment grade rating for their fixed income
securities. Based on the PPUC’s January 11, 2007 order described below, if
FES ultimately determines to terminate, reduce, or significantly modify the
agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps
in 2010, timely regulatory relief is not likely to be granted by the PPUC. See
FERC Matters below for a description of the Third Restated Partial Requirements
Agreement, executed by the parties on October 31, 2008, that limits
the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the
event of a third party supplier default, the increased costs to Met-Ed and
Penelec could be material.


Met-Ed and Penelec
made a comprehensive transition rate filing with the PPUC on April 10, 2006
to address a number of transmission, distribution and supply issues. If Met-Ed's
and Penelec's preferred approach involving accounting deferrals had been
approved, annual revenues would have increased by $216 million and
$157 million, respectively. That filing included, among other things, a
request to charge customers for an increasing amount of market-priced power
procured through a CBP as the amount of supply provided under the then existing
FES agreement was to be phased out. Met-Ed and Penelec also requested approval
of a January 12, 2005 petition for the deferral of transmission-related
costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested
recovery of annual transmission and related costs incurred on or after
January 1, 2007, plus the amortized portion of 2006 costs over a ten-year
period, along with applicable carrying charges, through an adjustable rider.
Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG
stranded costs were also included in the filing. On May 4, 2006, the PPUC
consolidated the remand of the FirstEnergy and GPU merger proceeding, related to
the quantification and allocation of merger savings, with the comprehensive
transition rate filing case.





33








The PPUC entered its
opinion and order in the comprehensive rate filing proceeding on
January 11, 2007. The order approved the recovery of transmission costs,
including the transmission-related deferral for January 1, 2006 through
January 10, 2007, and determined that no merger savings from prior years
should be considered in determining customers’ rates. The request for increases
in generation supply rates was denied as were the requested changes to NUG
expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased
Met-Ed’s and Penelec’s distribution rates by $80 million and
$19 million, respectively. These decreases were offset by the increases
allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request
for recovery of Saxton decommissioning costs was granted and, in January 2007,
Met-Ed and Penelec recognized income of $15 million and $12 million,
respectively, to establish regulatory assets for those previously expensed
decommissioning costs. Overall rates increased by 5.0% for Met-Ed
($59 million) and 4.5% for Penelec ($50 million).





On March 30, 2007,
MEIUG and PICA filed a Petition for Review with the Commonwealth Court of
Pennsylvania asking the Court to review the PPUC’s determination on transmission
(including congestion) and the transmission deferral. Met-Ed and Penelec filed a
Petition for Review on April 13, 2007 on the issues of consolidated tax savings
and the requested generation rate increase. The OCA filed its Petition for
Review on April 13, 2007, on the issues of transmission (including
congestion) and recovery of universal service costs from only the residential
rate class. From June through October 2007, initial responsive and reply briefs
were filed by various parties. The Commonwealth
Court issued its decision on November 7, 2008, which affirmed the PPUC's
January 11, 2007 order in all respects, including the deferral and recovery
of transmission and congestion related costs.





On May 22, 2008, the
PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the
period June 1, 2008, through May 31, 2009. Various intervenors filed
complaints against Met-Ed’s and Penelec’s TSC filings.  In addition,
the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC,
while at the same time allowing the company to implement the rider June 1,
2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to
consolidate the complaints against Met-Ed with its investigation and a
litigation schedule was adopted with hearings for both companies scheduled to
begin in January 2009. The TSCs include a component for under-recovery of actual
transmission costs incurred during the prior period (Met-Ed - $144 million
and Penelec - $4 million) and future transmission cost projections for June 2008
through May 2009 (Met-Ed - $258 million and Penelec - $92 million).
Met-Ed received approval from the PPUC of a transition approach that would
recover past under-recovered costs plus carrying charges through the new TSC
over thirty-one months and defer a portion of the projected costs
($92 million) plus carrying charges for recovery through future TSCs by
December 31, 2010.





On February 1, 2007,
the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of
proposed legislation that, according to the Governor, is designed to reduce
energy costs, promote energy independence and stimulate the economy. Elements of
the EIS include the installation of smart meters, funding for solar panels on
residences and small businesses, conservation and demand reduction programs to
meet energy growth, a requirement that electric distribution companies acquire
power that results in the “lowest reasonable rate on a long-term basis,” the
utilization of micro-grids and a three year phase-in of rate increases. On
July 17, 2007 the Governor signed into law two pieces of energy
legislation. The first amended the Alternative Energy Portfolio Standards Act of
2004 to, among other things, increase the percentage of solar energy that must
be supplied at the conclusion of an electric distribution company’s transition
period. The second law allows electric distribution companies, at their sole
discretion, to enter into long term contracts with large customers and to build
or acquire interests in electric generation facilities specifically to supply
long-term contracts with such customers. A special legislative session on energy
was convened in mid-September 2007 to consider other aspects of the EIS. The
Pennsylvania House and Senate on March 11, 2008 and December 12, 2007,
respectively, passed different versions of bills to fund the Governor’s EIS
proposal. As part of the 2008 state budget negotiations, the Alternative Energy
Investment Act was enacted creating a $650 million alternative energy fund to
increase the development and use of alternative and renewable energy, improve
energy efficiency and reduce energy consumption.  On October 8, 2008,
House Bill 2200 as amended, was voted out of the full Senate and adopted by the
House. On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200
into law which becomes effective on November 14, 2008 as Act 129 of
2008.  The bill addresses issues such as: energy efficiency and peak
load reduction; generation procurement; time-of-use rates; smart meters and
alternative energy.  Act 129 requires utilities to file with the PPUC
an energy efficiency and peak load reduction plan by July 1, 2009 and a smart
meter procurement and installation plan by August 14, 2009.





Major provisions of
the legislation include:




·
              power acquired
      by utilities to serve customers after rate caps expire will be procured
      through a competitive procurement process that must include a mix of
      long-term and short-term contracts and spot market
    purchases;
 
 ·
              the
      competitive procurement process must be approved by the PPUC and may
      include auctions, request for proposals, and/or bilateral
      agreements;
 
 ·
              utilities must
      provide for the installation of smart meter technology within 15
      years;
 
 ·
              a minimum
      reduction in peak demand of 4.5% by May 31,
  2013;







34







·
              minimum
      reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31,
      2013, respectively; and
 
 ·
              an expanded
      definition of alternative energy to include additional types of
      hydroelectric and biomass
facilities.




The current
legislative session ends on November 30, 2008, and any pending legislation
addressing rate mitigation and the expiration of rate caps not enacted by that
time must be re-introduced in order to be considered in the next legislative
session which begins in January 2009.  While the form and impact of
such legislation is uncertain, several legislators and the Governor have
indicated their intent to address these issues next year.





On September 25,
2008, Met-Ed and Penelec filed for Commission approval of a Voluntary Prepayment
Plan that would provide an opportunity for residential and small commercial
customers to pre-pay an amount, which would earn interest at 7.5%, on their
monthly electric bills in 2009 and 2010, to be used to reduce electric rates in
2011 and 2012. Met-Ed and Penelec also intend to file a generation procurement
plan for 2011 and beyond with the PPUC later this year or early next year.
Met-Ed and Penelec requested that the PPUC approve the Plan by mid-December 2008
and are currently awaiting a decision.





New Jersey





JCP&L is
permitted to defer for future collection from customers the amounts by which its
costs of supplying BGS to non-shopping customers and costs incurred under NUG
agreements exceed amounts collected through BGS and NUGC rates and market sales
of NUG energy and capacity. As of September 30, 2008, the accumulated
deferred cost balance totaled approximately $210 million.





In accordance with
an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7,
2004 supporting continuation of the current level and duration of the funding of
TMI-2 decommissioning costs by New Jersey customers without a reduction,
termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study. This study resulted in an updated
total decommissioning cost estimate of $729 million (in 2003 dollars)
compared to the estimated $528 million (in 2003 dollars) from the prior
1995 decommissioning study. The DRA filed comments on February 28, 2005
requesting that decommissioning funding be suspended. On March 18, 2005,
JCP&L filed a response to those comments. JCP&L responded to additional
NJBPU staff discovery requests in May and November 2007 and also submitted
comments in the proceeding in November 2007. A schedule for further NJBPU
proceedings has not yet been set.





On August 1, 2005,
the NJBPU established a proceeding to determine whether additional ratepayer
protections are required at the state level in light of the repeal of the PUHCA
pursuant to the EPACT. The NJBPU approved regulations effective October 2,
2006 that prevent a holding company that owns a gas or electric public utility
from investing more than 25% of the combined assets of its utility and
utility-related subsidiaries into businesses unrelated to the utility industry.
These regulations are not expected to materially impact FirstEnergy or
JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional
draft proposal on March 31, 2006 addressing various issues including access
to books and records, ring-fencing, cross subsidization, corporate governance
and related matters. With the approval of the NJBPU Staff, the affected
utilities jointly submitted an alternative proposal on June 1, 2006. The
NJBPU Staff circulated revised drafts of the proposal to interested stakeholders
in November 2006 and again in February 2007. On February 1, 2008, the NJBPU
accepted proposed rules for publication in the New Jersey Register on
March 17, 2008. A public hearing on these proposed rules was held on
April 23, 2008 and comments from interested parties were submitted by May
19, 2008.





New Jersey statutes
require that the state periodically undertake a planning process, known as the
EMP, to address energy related issues including energy security, economic
growth, and environmental impact. The EMP is to be developed with involvement of
the Governor’s Office and the Governor’s Office of Economic Growth, and is to be
prepared by a Master Plan Committee, which is chaired by the NJBPU President and
includes representatives of several State departments. In October 2006, the
current EMP process was initiated through the creation of a number of working
groups to obtain input from a broad range of interested stakeholders including
utilities, environmental groups, customer groups, and major customers. In
addition, public stakeholder meetings were held in 2006, 2007 and the first half
of 2008.





On April 17, 2008, a
draft EMP was released for public comment. The final EMP was issued on October
22, 2008 and establishes five major goals:





·
            maximize
      energy efficiency to achieve a 20% reduction in energy consumption by
      2020;





·
            reduce peak
      demand for electricity by 5,700 MW by
2020;





·
            meet 30% of
      the state’s electricity needs with renewable energy by
    2020;





·
            examine smart
      grid technology and develop additional cogeneration and other generation
      resources consistent with the state’s greenhouse gas targets;
      and





·
            invest in
      innovative clean energy technologies and businesses to stimulate the
      industry’s growth in New Jersey.





35








The final EMP will
be followed by appropriate legislation and regulation as necessary. At this
time, FirstEnergy cannot predict the outcome of this process nor determine the
impact, if any, such legislation or regulation may have on its operations or
those of JCP&L.





FERC
Matters





Transmission Service between MISO and
PJM





On November 18,
2004, the FERC issued an order eliminating the through and out rate for
transmission service between the MISO and PJM regions. The FERC’s intent was to
eliminate multiple transmission charges for a single transaction between the
MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission
owners within MISO and PJM to submit compliance filings containing a rate
mechanism to recover lost transmission revenues created by elimination of this
charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a
16-month transition period. The FERC issued orders in 2005 setting the SECA for
hearing. The presiding judge issued an initial decision on August 10, 2006,
rejecting the compliance filings made by MISO, PJM, and the transmission owners,
and directing new compliance filings. This decision is subject to review and
approval by the FERC. Briefs addressing the initial decision were filed on
September 11, 2006 and October 20, 2006. A final order could be issued by
the FERC by year-end 2008.  In the meantime, FirstEnergy affiliates
have been negotiating and entering into settlement agreements with other parties
in the docket to mitigate the risk of lower transmission revenue collection
associated with an adverse order.  On September 26, 2008, the
MISO and PJM transmission owners filed a motion requesting that the FERC approve
the pending settlements and act on the initial decision.





PJM Transmission Rate
Design





On January 31, 2005,
certain PJM transmission owners made filings with the FERC pursuant to a
settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
Penelec were parties to that proceeding and joined in two of the filings. In the
first filing, the settling transmission owners submitted a filing justifying
continuation of their existing rate design within the PJM RTO. Hearings were
held and numerous parties appeared and litigated various issues concerning PJM
rate design; notably AEP, which proposed to create a "postage stamp", or average
rate for all high voltage transmission facilities across PJM and a zonal
transmission rate for facilities below 345 kV. This proposal would have the
effect of shifting recovery of the costs of high voltage transmission lines to
other transmission zones, including those where JCP&L, Met-Ed, and Penelec
serve load. On April 19, 2007, the FERC issued an order finding that the
PJM transmission owners’ existing “license plate” or zonal rate design was just
and reasonable and ordered that the current license plate rates for existing
transmission facilities be retained. On the issue of rates for new transmission
facilities, the FERC directed that costs for new transmission facilities that
are rated at 500 kV or higher are to be collected from all transmission zones
throughout the PJM footprint by means of a postage-stamp rate. Costs for new
transmission facilities that are rated at less than 500 kV, however, are to be
allocated on a “beneficiary pays” basis. The FERC found that PJM’s current
beneficiary-pays cost allocation methodology is not sufficiently detailed and,
in a related order that also was issued on April 19, 2007, directed that
hearings be held for the purpose of establishing a just and reasonable cost
allocation methodology for inclusion in PJM’s tariff.





On May 18, 2007,
certain parties filed for rehearing of the FERC’s April 19, 2007 order. On
January 31, 2008, the requests for rehearing were denied. The FERC’s orders
on PJM rate design will prevent the allocation of a portion of the revenue
requirement of existing transmission facilities of other utilities to JCP&L,
Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new
500 kV and above transmission facilities on a PJM-wide basis will reduce the
costs of future transmission to be recovered from the JCP&L, Met-Ed and
Penelec zones. A partial settlement agreement addressing the “beneficiary pays”
methodology for below 500 kV facilities, but excluding the issue of allocating
new facilities costs to merchant transmission entities, was filed on September
14, 2007. The agreement was supported by the FERC’s Trial Staff, and was
certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued
an order conditionally approving the settlement subject to the submission of a
compliance filing.  The compliance filing was submitted on
August 29, 2008, and the FERC issued an order accepting the compliance
filing on October 15, 2008.  The remaining merchant transmission cost
allocation issues were the subject of a hearing at the FERC in May
2008.  An initial decision was issued by the Presiding Judge on
September 18, 2008.  PJM and FERC trial staff each filed a Brief on
Exceptions to the initial decision on October 20, 2008.  Briefs
Opposing Exceptions are due on November 10, 2008. On February 11,
2008, AEP appealed the FERC’s April 19, 2007 and January 31, 2008 orders to
the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce
Commission, the PUCO and Dayton Power & Light have also appealed these
orders to the Seventh Circuit Court of Appeals. The appeals of these parties and
others have been consolidated for argument in the Seventh Circuit.





36





Post
Transition Period Rate Design





The FERC had
directed MISO, PJM, and the respective transmission owners to make filings on or
before August 1, 2007 to reevaluate transmission rate design within MISO, and
between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the
vast majority of transmission owners, including FirstEnergy affiliates, which
proposed to retain the existing transmission rate design. These filings were
approved by the FERC on January 31, 2008. As a result of the FERC’s approval,
the rates charged to FirstEnergy’s load-serving affiliates for transmission
service over existing transmission facilities in MISO and PJM are unchanged. In
a related filing, MISO and MISO transmission owners requested that the current
MISO pricing for new transmission facilities that spreads 20% of the cost of new
345 kV and higher transmission facilities across the entire MISO footprint
(known as the RECB methodology) be retained.





On September 17, 2007, AEP filed a
complaint under Sections 206 and 306 of the Federal Power Act seeking to have
the entire transmission rate design and cost allocation methods used by MISO and
PJM declared unjust, unreasonable, and unduly discriminatory, and to have the
FERC fix a uniform regional transmission rate design and cost allocation method
for the entire MISO and PJM “Super Region” that recovers the average cost of new
and existing transmission facilities operated at voltages of 345 kV and above
from all transmission customers. Lower voltage facilities would continue to be
recovered in the local utility transmission rate zone through a license plate
rate. AEP requested a refund effective October 1, 2007, or alternatively,
February 1, 2008. On January 31, 2008, the FERC issued an order denying the
complaint. The effect of this order is to prevent the shift of significant costs
to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP is pending
before the FERC.





MISO Ancillary Services Market and
Balancing Area Consolidation





MISO made a filing
on September 14, 2007 to establish an ASM for regulation, spinning and
supplemental reserves, to consolidate the existing 24 balancing areas within the
MISO footprint, and to establish MISO as the NERC registered balancing authority
for the region. These markets would permit generators to sell, and load-serving
entities to purchase, their operating reserve requirements in a competitive
market. FirstEnergy supports the proposal to establish markets for Ancillary
Services and consolidate existing balancing areas. On February 25, 2008, the
FERC issued an order approving the ASM subject to certain compliance filings.
Numerous parties filed requests for rehearing on March 26, 2008. On
June 23, 2008, the FERC issued an order granting in part and denying in
part rehearing.





On February 29,
2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor
ASM and Consolidated Balancing Authority Initiative Verification plan and status
and Real-Time Operations ASM Reversion plan. FERC action on this compliance
filing remains pending. On March 26, 2008, MISO submitted a tariff filing in
compliance with the FERC’s 30-day directives in the February 25 order. Numerous
parties submitted comments and protests on April 16, 2008. The FERC issued an
order accepting the revisions pending further compliance on June 23, 2008. On
April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s
60-day directives in the February 25 order. FERC action on this compliance
filing remains pending. On May 23, 2008, MISO submitted its amended Balancing
Authority Agreement. On July 21, 2008, the FERC issued an order conditionally
accepting the amended Balancing Authority Agreement and requiring a further
compliance filing.  On August 19, 2008, MISO submitted its compliance
filing to the FERC.  On July 25, 2008, MISO submitted another
Readiness Certification.  The FERC has not yet acted on this
submission.  MISO announced on August 26, 2008 that the startup
of its market is postponed indefinitely.  MISO commits to make a
filing giving at least sixty days notice of the new effective date. The latest
announced effective date for market startup is January 6, 2009.





Interconnection
Agreement with AMP-Ohio





On May 29, 2008, TE
filed with the FERC a proposed Notice of Cancellation effective midnight
December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio
protested this filing. TE also filed a Petition for Declaratory Order seeking a
FERC ruling, in the alternative if cancellation is not accepted, of TE's right
to file for an increase in rates effective January 1, 2009, for power
provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a
pleading agreeing that TE may seek an increase in rates, but arguing that any
increase is limited to the cost of generation owned by TE affiliates. On
August 18, 2008, the FERC issued an order that suspended the cancellation
of the Agreement for five months, to become effective on June 1, 2009, and
established expedited hearing procedures on issues raised in the filing and TE’s
Petition for Declaratory Order. On October 14, 2008, the parties filed a
settlement agreement and mutual notice of cancellation of the Interconnection
Agreement effective midnight December 31, 2008.  Upon acceptance by
the FERC, this filing will terminate the litigation and the Interconnection
Agreement, among other effects.





37








Duquesne’s
Request to Withdraw from PJM





On November 8, 2007,
Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and
to join MISO. In its filing, Duquesne asked the FERC to be relieved of certain
capacity payment obligations to PJM for capacity auctions conducted prior to its
departure from PJM, but covering service for planning periods through
May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is
to avoid paying future obligations created by PJM’s forward capacity market. On
January 17, 2008, the FERC conditionally approved Duquesne’s request to
exit PJM. Among other conditions, the FERC obligated Duquesne zone load-serving
entities to pay their PJM capacity obligations through May 31,
2011.





FirstEnergy desires
to continue to use its Duquesne zone generation resources to serve load in PJM.
On April 18, 2008, the FERC issued its Order on Motion for Emergency
Clarification on whether Duquesne-zone generators could participate in PJM’s May
2008 auction for the 2011-2012 planning year. In the order, the FERC ruled
that although the status of the Duquesne-zone generators will change to
“External Resource” upon Duquesne’s exit from PJM, these generators could
contract with PJM for the transmission reservations necessary to participate in
the May 2008 auction. FirstEnergy has complied with the FERC’s order by
obtaining executed transmission service agreements for firm point-to-point
transmission service for the 2011-2012 delivery year and, as such, FirstEnergy
satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM
auction.





The FERC also
directed MISO and PJM to resolve the substantive and procedural issues
associated with Duquesne’s transition into MISO. As directed, PJM filed thirteen
load-serving entity Capacity Payment Agreements and a Capacity Portability
Agreement with the FERC. The Capacity Payment Agreements addressed Duquesne Zone
load-serving entity obligations through May 31, 2011 with regards to RPM
Capacity while the Capacity Portability Agreement addressed operational issues
associated with the portability of such capacity. On September 30, 2008, the
FERC approved both agreements, subject to conditions, taking notice of many
operational and procedural issues brought forth by FirstEnergy and other market
participants.





Several issues
surrounding Duquesne’s transition into MISO continue to be contested at the
FERC. Specifically, Duquesne’s obligation to pay for transmission expansion
costs allocated to the Duquesne zone when they were a member of PJM, and other
issues in which market participants wish to be held harmless by Duquesne’s
transition. FirstEnergy filed for rehearing on these issues on October 3, 2008.
Duquesne’s transition into MISO is also contingent upon the start of MISO’s
ancillary services market and consolidation of its balancing authorities,
currently scheduled for January 6, 2009.





Complaint
against PJM RPM Auction





On May 30,
2008, a group of PJM load-serving entities, state commissions, consumer
advocates, and trade associations (referred to collectively as the RPM Buyers)
filed a complaint at the FERC against PJM alleging that three of the
four transitional RPM auctions yielded prices that are unjust and
unreasonable under the Federal Power Act. Most of the parties comprising
the RPM Buyers group were parties to the settlement approved by the FERC that
established the RPM. In the complaint, the RPM Buyers request that the
total projected payments to RPM sellers for the three auctions at issue be
materially reduced. On July 11, 2008, PJM filed its answer to the
complaint, in which it denied the allegation that the rates are unjust and
unreasonable. Also on that date, FirstEnergy filed a motion to
intervene.





On September 19,
2008, the FERC denied the RPM Buyers complaint. However, the FERC did grant the
RPM Buyers request for a technical conference to review aspects of the RPM. The
FERC also ordered PJM to file on or before December 15, 2008, a report on
its progress on contemplating adjustments to the RPM as suggested by the Brattle
Group in its report reviewing the RPM. The technical conference will take place
in February, 2009. On October 20, 2008, the RPM Buyers filed a request for
rehearing of the FERC’s September 19, 2008 order.





38





MISO
Resource Adequacy Proposal





MISO made a filing
on December 28, 2007 that would create an enforceable planning reserve
requirement in the MISO tariff for load-serving entities such as the Ohio
Companies, Penn Power, and FES. This requirement is proposed to become effective
for the planning year beginning June 1, 2009. The filing would permit MISO to
establish the reserve margin requirement for load-serving entities based upon a
one day loss of load in ten years standard, unless the state utility regulatory
agency establishes a different planning reserve for load-serving entities in its
state. FirstEnergy believes the proposal promotes a mechanism that will result
in commitments from both load-serving entities and resources, including both
generation and demand side resources that are necessary for reliable resource
adequacy and planning in the MISO footprint. Comments on the filing were filed
on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy
proposal on March 26, 2008, requiring MISO to submit to further compliance
filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27,
2008, MISO submitted a compliance filing to address issues associated with
planning reserve margins. On June 17, 2008, various parties submitted comments
and protests to MISO’s compliance filing. FirstEnergy submitted comments
identifying specific issues that must be clarified and addressed. On
June 25, 2008, MISO submitted a second compliance filing establishing the
enforcement mechanism for the reserve margin requirement which establishes
deficiency payments for load-serving entities that do not meet the resource
adequacy requirements. Numerous parties, including FirstEnergy, protested this
filing.   On October 20, 2008, the FERC issued three orders
essentially permitting the MISO Resource Adequacy program to proceed with some
modifications.  First, the FERC accepted MISO's financial settlement
approach for enforcement of Resource Adequacy subject to a compliance filing
modifying the cost of new entry penalty. Second, the FERC conditionally accepted
MISO's compliance filing on the qualifications for purchase power agreements to
be capacity resources, load forecasting, loss of load expectation, and planning
reserve zones. Additional compliance filings were directed on accreditation of
load modifying resources and price responsive demand. Finally, the FERC largely
denied rehearing of its March 26 order with the exception of issues related to
behind the meter resources and certain ministerial matters. Issuance of these
orders is not expected to delay the June 1, 2009 start date for MISO
Resource Adequacy.





Organized
Wholesale Power Markets





The FERC issued a
final rule on October 17, 2008, amending its regulations to “improve the
operation of organized wholesale electric markets in the areas of: (1) demand
response and market pricing during periods of operating reserve shortage; (2)
long-term power contracting; (3) market-monitoring policies; and (4) the
responsiveness of RTOs and ISOs to their customers and other
stakeholders.”  The RTOs and ISOs were directed to submit amendments
to their respective tariffs to address these market operation
improvements.  The final rule directs RTOs to adopt market rules
permitting prices to increase during periods of supply shortages and to permit
enhanced participation by demand response resources.  It also codifies
and defines for the first time the roles and duties of independent market
monitors within RTOs.  Finally, it adopts requirements for enhanced
access by stakeholders to RTO boards of directors.  RTOs are directed
to make compliance filings six months from the effective date of the final
rule.  The final rule is not expected to have any material effect on
FirstEnergy's operations within MISO and PJM.





FES
Sales to Affiliates





On October 24, 2008,
FES, on its own behalf and on behalf of its generation-controlling subsidiaries,
filed an application with the FERC seeking a waiver of the affiliate sales
restrictions between FES and the Ohio Companies. The purpose of the waiver is to
ensure thatFESwill be able to continue supplying
a material portion of the electric load requirements of the Ohio Companies in
January 2009 pursuant to either an ESP or MRO as filed with the PUCO. FES
previously obtained a similar waiver for electricity sales to its affiliates in
New Jersey, New York, and Pennsylvania. A ruling by the FERC is expected the
week of December 15, 2008.





On October 31, 2008,
FES executed a Third Restated Partial Requirements Agreement with
Met-Ed, Penelec, and The Waverly Power and Light Company (Waverly)
effective November 1, 2008.  The Third Restated Partial Requirements
Agreement limits the amount of capacity and energy required to be supplied by
FES in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply
requirements. Met-Ed, Penelec, and Waverly have committed resources in
place for the balance of their expected power supply during 2009 and
2010.  Under the Third Restated Partial Requirements Agreement,
Met-Ed, Penelec, and Waverly are responsible for obtaining additional power
supply requirements created by the default or failure of supply of their
committed resources. Prices for the power provided by FES were not changed in
the Third Restated Partial Requirements Agreement.





Environmental
Matters





Various federal,
state and local authorities regulate FirstEnergy with regard to air and water
quality and other environmental matters. The effects of compliance on
FirstEnergy with regard to environmental matters could have a material adverse
effect on FirstEnergy's earnings and competitive position to the extent that it
competes with companies that are not subject to such regulations and, therefore,
do not bear the risk of costs associated with compliance, or failure to comply,
with such regulations. FirstEnergy estimates capital expenditures for
environmental compliance of approximately $1.4 billion for the period
2008-2012.





39








FirstEnergy accrues
environmental liabilities only when it concludes that it is probable that it has
an obligation for such costs and can reasonably estimate the amount of such
costs. Unasserted claims are reflected in FirstEnergy’s determination of
environmental liabilities and are accrued in the period that they become both
probable and reasonably estimable.





Clean Air Act Compliance





FirstEnergy is
required to meet federally-approved SO2 emissions
regulations. Violations of such regulations can result in the shutdown of the
generating unit involved and/or civil or criminal penalties of up to $32,500 for
each day the unit is in violation. The EPA has an interim enforcement policy for
SO2
regulations in Ohio that allows for compliance based on a 30-day averaging
period. FirstEnergy believes it is currently in compliance with this policy, but
cannot predict what action the EPA may take in the future with respect to the
interim enforcement policy.





The EPA Region 5
issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June
15, 2006, alleging violations to various sections of the CAA. FirstEnergy has
disputed those alleged violations based on its CAA permit, the Ohio SIP and
other information provided to the EPA at an August 2006 meeting with the EPA.
The EPA has several enforcement options (administrative compliance order,
administrative penalty order, and/or judicial, civil or criminal action) and has
indicated that such option may depend on the time needed to achieve and
demonstrate compliance with the rules alleged to have been violated. On
June 5, 2007, the EPA requested another meeting to discuss “an appropriate
compliance program” and a disagreement regarding emission limits applicable to
the common stack for Bay Shore Units 2, 3 and 4.





FirstEnergy complies
with SO2 reduction
requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NOX reductions
required by the 1990 Amendments are being achieved through combustion controls
and the generation of more electricity at lower-emitting plants. In September
1998, the EPA finalized regulations requiring additional NOX reductions
at FirstEnergy's facilities. The EPA's NOX Transport
Rule imposes uniform reductions of NOX emissions
(an approximate 85% reduction in utility plant NOX emissions
from projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NOX emissions
are contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NOX budgets
established under SIPs through combustion controls and post-combustion controls,
including Selective Catalytic Reduction and SNCR systems, and/or using emission
allowances.





In 1999 and 2000,
the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn
based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR
Litigation) and filed similar complaints involving 44 other U.S. power plants.
This case, along with seven other similar cases, is referred to as the NSR
cases.  OE’s and Penn’s settlement with the EPA, the DOJ and three
states (Connecticut, New Jersey and New York) that resolved all issues related
to the Sammis NSR litigation was approved by the Court on July 11, 2005. This
settlement agreement, in the form of a consent decree, requires reductions of
NOX
and SO2 emissions
at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the
installation of pollution control devices and provides for stipulated penalties
for failure to install and operate such pollution controls in accordance with
that agreement. Capital expenditures necessary to complete requirements of the
Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion
for 2008-2012 ($650 million of which is expected to be spent during 2008,
with the largest portion of the remaining $650 million expected to be spent
in 2009). This amount is included in the estimated capital expenditures for
environmental compliance referenced above. On September 8, 2008, the
Environmental Enforcement Section of the DOJ sent a letter to OE regarding its
view that the company was not in compliance with the Sammis NSR Litigation
consent decree because the installation of an SNCR at Eastlake Unit 5 was not
completed by December 31, 2006. However, the DOJ acknowledged that stipulated
penalties could not apply under the terms of the Sammis NSR Litigation consent
decree because Eastlake Unit 5 was idled on December 31, 2006 pending
installation of the SNCR and advised that it had exercised its discretion not to
seek any other penalties for this alleged non-compliance. OE disputed the DOJ's
interpretation of the consent decree in a letter dated September 22, 2008.
Although the Eastlake Unit 5 issue is no longer active, OE filed a dispute
resolution petition on October 23, 2008, with the United States District
Court for the Southern District of Ohio, due to potential impacts on its
compliance decisions with respect to Burger Units 4 and 5. Under the Sammis NSR
Litigation consent decree, an election to repower by December 31, 2012,
install flue gas desulfurization (FGD) by December 31, 2010, or permanently shut
down those units by December 31, 2010, is due no later than
December 31, 2008. Although FirstEnergy will meet the December 31,
2008 deadline for making an election, one potential compliance option, should
FGD be elected, would be to idle Burger Units 4 and 5 on December 31, 2010
pending completion of the FGD installation. Thus, OE is seeking a determination
by the Court whether this approach is indeed in compliance with the terms of the
Sammis NSR Litigation consent decree. The Court has scheduled a hearing on OE’s
dispute resolution petition for November 17, 2008. The outcome of this
dispute resolution process could have an impact on the option FirstEnergy
ultimately elects with respect to Burger Units 4 and 5.





40








On April 2,
2007, the United States Supreme Court ruled that changes in annual emissions (in
tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must
be used to determine whether an emissions increase triggers NSR. Subsequently,
on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize
changes in the hourly emission rate (in kilograms/hour) to determine whether an
emissions increase triggers NSR. The EPA has not yet issued a final regulation.
FGCO’s future cost of compliance with those regulations may be substantial and
will depend on how they are ultimately implemented.





On May 22, 2007,
FirstEnergy and FGCO received a notice letter, required 60 days prior to the
filing of a citizen suit under the federal CAA, alleging violations of air
pollution laws at the Bruce Mansfield Plant, including opacity limitations.
Prior to the receipt of this notice, the Plant was subject to a Consent Order
and Agreement with the Pennsylvania Department of Environmental Protection
concerning opacity emissions under which efforts to achieve compliance with the
applicable laws will continue. On October 18, 2007, PennFuture filed a
complaint, joined by three of its members, in the United States District Court
for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy
filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008,
the Court denied the motion to dismiss, but also ruled that monetary damages
could not be recovered under the public nuisance claim. In July 2008, three
additional complaints were filed against FGCO in the United States District
Court for the Western District of Pennsylvania seeking damages based on Bruce
Mansfield Plant air emissions. In addition to seeking damages, two of the
complaints seek to enjoin the Bruce Mansfield Plant from operating except in a
“safe, responsible, prudent and proper manner”, one being a complaint filed on
behalf of twenty-one individuals and the other being a class action complaint,
seeking certification as a class action with the eight named plaintiffs as the
class representatives. On October 14, 2008, the Court granted FGCO’s motion
to consolidate discovery for all four complaints pending against the Bruce
Mansfield Plant. FGCO believes the claims are without merit and intends to
defend itself against the allegations made in these complaints.





On December 18,
2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations
at the Portland Generation Station against Reliant (the current owner and
operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in
1999), GPU, Inc. and Met-Ed.  Specifically, New Jersey alleges that
"modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without
preconstruction NSR or permitting under the CAA's prevention of significant
deterioration program, and seeks injunctive relief, penalties, attorney fees and
mitigation of the harm caused by excess emissions. On March 14, 2008,
Met-Ed filed a motion to dismiss the citizen suit claims against it and a
stipulation in which the parties agreed that GPU, Inc. should be dismissed from
this case. On March 26, 2008, GPU, Inc. was dismissed by the United States
District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe
Energy is disputed.  By letter dated October 1, 2008, New Jersey
informed the Court of its intent to file an amended complaint. Met-Ed is unable
to predict the outcome of this matter.





On June 11, 2008,
the EPA issued a Notice and Finding of Violation to MEW alleging that
"modifications" at the Homer City Power Station occurred since 1988 to the
present without preconstruction NSR or permitting under the CAA's prevention of
significant deterioration program. MEW is seeking indemnification from Penelec,
the co-owner (along with New York State Electric and Gas Company) and operator
of the Homer City Power Station prior to its sale in 1999.  The scope
of Penelec’s indemnity obligation to and from MEW is
disputed.  Penelec is unable to predict the outcome of this
matter.





On May 16, 2008,
FGCO received a request from the EPA for information pursuant to Section 114(a)
of the CAA for certain operating and maintenance information regarding the
Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA
to determine whether these generating sources are complying with the NSR
provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an
ACO modifying that request and setting forth a schedule for FGCO’s response.
FGCO complied with the modified schedule and otherwise intends to fully comply
with the ACO, but, at this time, is unable to predict the outcome of this
matter.





On August 18, 2008,
FirstEnergy received a request from the EPA for information pursuant to Section
114(a) of the CAA for certain operating and maintenance information regarding
the Avon Lake and Niles generating plants, as well as a copy of a nearly
identical request directed to the current owner, Reliant Energy, to allow the
EPA to determine whether these generating sources are complying with the NSR
provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s
information request, but, at this time, is unable to predict the outcome of this
matter.





41





National Ambient Air Quality
Standards





In March 2005,
the EPA finalized the CAIR covering a total of 28 states (including Michigan,
New Jersey, Ohio and Pennsylvania) and the District of Columbia based on
proposed findings that air emissions from 28 eastern states and the District of
Columbia significantly contribute to non-attainment of the NAAQS for fine
particles and/or the "8-hour" ozone NAAQS in other states. CAIR would have
required reductions of NOX and
SO2
emissions in two phases (Phase I in 2009 for NOX, 2010 for
SO2
and Phase II in 2015 for both NOX and
SO2),
ultimately capping SO2 emissions
in affected states to just 2.5 million tons annually and NOX emissions
to just 1.3 million tons annually. CAIR was challenged in the United States
Court of Appeals for the District of Columbia and on July 11, 2008, the Court
vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from
the ground up.” The Court ruling also vacated the CAIR regional cap and trade
requirements for SO2 and
NOX,
which is currently not expected to, but may, materially impair the value of
emissions allowances obtained for future compliance. On September 24, 2008, the
EPA, utility, mining and certain environmental advocacy organizations petitioned
the Court for a rehearing to reconsider its ruling vacating CAIR.  On
October 21, 2008, the Court ordered the parties who appealed CAIR to file
responses to the rehearing petitions by November 5, 2008 and directed them to
address (1) whether any party is seeking vacatur of CAIR and (2) whether the
Court should stay its vacatur of CAIR until EPA promulgates a revised rule. The
future cost of compliance with these regulations may be substantial and will
depend on the Court’s ruling on rehearing, as well as the action taken by the
EPA or Congress in response to the Court’s ruling.





Mercury Emissions





In December 2000,
the EPA announced it would proceed with the development of regulations regarding
hazardous air pollutants from electric power plants, identifying mercury as the
hazardous air pollutant of greatest concern. In March 2005, the EPA finalized
the CAMR, which provides a cap-and-trade program to reduce mercury emissions
from coal-fired power plants in two phases; initially, capping national mercury
emissions at 38 tons by 2010 (as a "co-benefit" from implementation of
SO2
and NOX emission
caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states
and environmental groups appealed the CAMR to the United States Court of Appeals
for the District of Columbia. On February 8, 2008, the Court vacated the
CAMR, ruling that the EPA failed to take the necessary steps to “de-list”
coal-fired power plants from its hazardous air pollutant program and, therefore,
could not promulgate a cap-and-trade program. The EPA petitioned for rehearing
by the entire Court, which denied the petition on May 20, 2008.  On
October 17, 2008, the EPA (and an industry group) petitioned the United
States Supreme Court for review of the Court’s ruling vacating CAMR. The Supreme
Court could grant the EPA’s petition and alter some or all of the lower Court’s
decision, or the EPA could take regulatory action to promulgate new mercury
emission standards for coal-fired power plants. FGCO’s future cost of compliance
with mercury regulations may be substantial and will depend on the action taken
by the EPA and on how they are ultimately implemented.





Pennsylvania has
submitted a new mercury rule for EPA approval that does not provide a
cap-and-trade approach as in the CAMR, but rather follows a command-and-control
approach imposing emission limits on individual sources. It is anticipated that
compliance with these regulations, if approved by the EPA and implemented, would
not require the addition of mercury controls at the Bruce Mansfield Plant,
FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at
all.





Climate Change





In December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol, to address global warming by reducing the amount of man-made
GHG emitted by developed countries by 2012. The United States signed the Kyoto
Protocol in 1998 but it was never submitted for ratification by the United
States Senate. However, the Bush administration has committed the United States
to a voluntary climate change strategy to reduce domestic GHG intensity – the
ratio of emissions to economic output – by 18% through 2012. Also, in an
April 16, 2008 speech, President Bush set a policy goal of stopping the
growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In
addition, the EPACT established a Committee on Climate Change Technology to
coordinate federal climate change activities and promote the development and
deployment of GHG reducing technologies.





There are a number
of initiatives to reduce GHG emissions under consideration at the federal, state
and international level.  At the international level, efforts to reach
a new global agreement to reduce GHG emissions post-2012 have begun with the
Bali Roadmap, which outlines a two-year process designed to lead to an agreement
in 2009. At the federal level, members of Congress have introduced several bills
seeking to reduce emissions of GHG in the United States, and the Senate
Environment and Public Works Committee has passed one such bill. State
activities, primarily the northeastern states participating in the Regional
Greenhouse Gas Initiative and western states led by California, have coordinated
efforts to develop regional strategies to control emissions of certain
GHGs.





On April 2, 2007,
the United States Supreme Court found that the EPA has the authority to regulate
CO2
emissions from automobiles as “air pollutants” under the CAA. Although this
decision did not address CO2 emissions
from electric generating plants, the EPA has similar authority under the CAA to
regulate “air pollutants” from those and other facilities. On July 11,
2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting
input from the public on the effects of climate change and the potential
ramifications of regulation of CO2 under the
CAA.





42








FirstEnergy cannot
currently estimate the financial impact of climate change policies, although
potential legislative or regulatory programs restricting CO2 emissions
could require significant capital and other expenditures. The CO2 emissions
per KWH of electricity generated by FirstEnergy is lower than many regional
competitors due to its diversified generation sources, which include low or
non-CO2 emitting
gas-fired and nuclear generators.





Clean Water Act





Various water
quality regulations, the majority of which are the result of the federal Clean
Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio,
New Jersey and Pennsylvania have water quality standards applicable to
FirstEnergy's operations. As provided in the Clean Water Act, authority to grant
federal National Pollutant Discharge Elimination System water discharge permits
can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such
authority.





On September 7,
2004, the EPA established new performance standards under Section 316(b) of the
Clean Water Act for reducing impacts on fish and shellfish from cooling water
intake structures at certain existing large electric generating plants. The
regulations call for reductions in impingement mortality (when aquatic organisms
are pinned against screens or other parts of a cooling water intake system) and
entrainment (which occurs when aquatic life is drawn into a facility's cooling
water system). On January 26, 2007, the United States Court of Appeals for the
Second Circuit remanded portions of the rulemaking dealing with impingement
mortality and entrainment back to the EPA for further rulemaking and eliminated
the restoration option from the EPA’s regulations. On July 9, 2007, the EPA
suspended this rule, noting that until further rulemaking occurs, permitting
authorities should continue the existing practice of applying their best
professional judgment to minimize impacts on fish and shellfish from cooling
water intake structures. On April 14, 2008, the Supreme Court of the United
States granted a petition for a writ of certiorari to review one significant
aspect of the Second Circuit Court’s opinion which is whether
Section 316(b) of the Clean Water Act authorizes the EPA to compare costs
with benefits in determining the best technology available for minimizing
adverse environmental impact at cooling water intake structures.  Oral
argument before the Supreme Court is scheduled for December 2, 2008. FirstEnergy
is studying various control options and their costs and effectiveness. Depending
on the results of such studies, the outcome of the Supreme Court’s review of the
Second Circuit’s decision, the EPA’s further rulemaking and any action taken by
the states exercising best professional judgment, the future costs of compliance
with these standards may require material capital expenditures.





Regulation of Hazardous
Waste





As a result of the
Resource Conservation and Recovery Act of 1976, as amended, and the Toxic
Substances Control Act of 1976, federal and state hazardous waste regulations
have been promulgated. Certain fossil-fuel combustion waste products, such as
coal ash, were exempted from hazardous waste disposal requirements pending the
EPA's evaluation of the need for future regulation. The EPA subsequently
determined that regulation of coal ash as a hazardous waste is unnecessary. In
April 2000, the EPA announced that it will develop national standards regulating
disposal of coal ash under its authority to regulate non-hazardous
waste.





Under NRC
regulations, FirstEnergy must ensure that adequate funds will be available to
decommission its nuclear facilities.  As of September 30, 2008,
FirstEnergy had approximately $1.9 billion invested in external trusts to be
used for the decommissioning and environmental remediation of Davis-Besse,
Beaver Valley, Perry and TMI-2. As part of the application to the NRC to
transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005,
FirstEnergy agreed to contribute another $80 million to these trusts by 2010.
Consistent with NRC guidance, utilizing a “real” rate of return on these funds
of approximately 2% over inflation, these trusts are expected to exceed the
minimum decommissioning funding requirements set by the NRC. Conservatively,
these estimates do not include any rate of return that the trusts may earn over
the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1
as it relates to the timing of the decommissioning of TMI-2) seeks for these
facilities.





The Utilities have
been named as PRPs at waste disposal sites, which may require cleanup under the
Comprehensive Environmental Response, Compensation, and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site may be liable on a
joint and several basis. Therefore, environmental liabilities that are
considered probable have been recognized on the Consolidated Balance Sheet as of
September 30, 2008, based on estimates of the total costs of cleanup, the
Utilities' proportionate responsibility for such costs and the financial ability
of other unaffiliated entities to pay. Total liabilities of approximately
$94 million (JCP&L - $68 million, TE - $1 million, CEI -
$1 million and FirstEnergy Corp. - $24 million) have been accrued
through September 30, 2008. Included in the total for JCP&L are accrued
liabilities of approximately $57 million for environmental remediation of
former manufactured gas plants in New Jersey, which are being recovered by
JCP&L through a non-bypassable SBC.





43








Other Legal Proceedings





Power Outages and Related
Litigation





In July 1999, the
Mid-Atlantic States experienced a severe heat wave, which resulted in power
outages throughout the service territories of many electric utilities, including
JCP&L's territory. In an investigation into the causes of the outages and
the reliability of the transmission and distribution systems of all four of New
Jersey’s electric utilities, the NJBPU concluded that there was not a prima
facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or
improper service to its customers. Two class action lawsuits (subsequently
consolidated into a single proceeding) were filed in New Jersey Superior Court
in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory.





In August 2002, the
trial Court granted partial summary judgment to JCP&L and dismissed the
plaintiffs' claims for consumer fraud, common law fraud, negligent
misrepresentation, and strict product liability. In November 2003, the trial
Court granted JCP&L's motion to decertify the class and denied plaintiffs'
motion to permit into evidence their class-wide damage model indicating damages
in excess of $50 million. These class decertification and damage rulings were
appealed to the Appellate Division. The Appellate Division issued a decision in
July 2004, affirming the decertification of the originally certified class, but
remanding for certification of a class limited to those customers directly
impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a
common incident involving the failure of the bushings of two large transformers
in the Red Bank substation resulting in planned and unplanned outages in the
area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify
the class based on a very limited number of class members who incurred damages
and also filed a motion for summary judgment on the remaining plaintiffs’ claims
for negligence, breach of contract and punitive damages. In July 2006, the New
Jersey Superior Court dismissed the punitive damage claim and again decertified
the class based on the fact that a vast majority of the class members did not
suffer damages and those that did would be more appropriately addressed in
individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate
Division which, in March 2007, reversed the decertification of the Red Bank
class and remanded this matter back to the Trial Court to allow plaintiffs
sufficient time to establish a damage model or individual proof of damages.
JCP&L filed a petition for allowance of an appeal of the Appellate Division
ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings
are continuing in the Superior Court and a case management conference with the
presiding Judge was held on June 13, 2008.  At that conference,
the plaintiffs stated their intent to drop their efforts to create a class-wide
damage model and, instead of dismissing the class action, expressed their desire
for a bifurcated trial on liability and damages. The judge directed the
plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed
under this scenario.  Thereafter, the judge expects to hold another
pretrial conference to address plaintiffs' proposed procedure.JCP&L has received
the plaintiffs’ proposed plan of action, and intends to file its objection to
the proposed plan, and also file a renewed motion to decertify the class.
JCP&L is defending this action but is unable to predict the outcome. No
liability has been accrued as of September 30, 2008.




Nuclear
Plant Matters





On May 14, 2007, the
Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply
to an April 2, 2007 NRC request for information about two reports prepared
by expert witnesses for an insurance arbitration (the insurance claim was
subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse.
The NRC indicated that this information was needed for the NRC “to determine
whether an Order or other action should be taken pursuant to 10 CFR 2.202, to
provide reasonable assurance that FENOC will continue to operate its licensed
facilities in accordance with the terms of its licenses and the Commission’s
regulations.” FENOC was directed to submit the information to the NRC within 30
days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that
it accepts full responsibility for the mistakes and omissions leading up to the
damage to the reactor vessel head and that it remains committed to operating
Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC
submitted a supplemental response clarifying certain aspects of the DFI response
to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a
confirmatory order imposing these commitments. FENOC must inform the NRC’s
Office of Enforcement after it completes the key commitments embodied in the
NRC’s order. FENOC has conducted the employee training required by the
confirmatory order and a consultant has performed follow-up reviews to ensure
the effectiveness of that training.  The NRC continues to monitor
FENOC’s compliance with all the commitments made in the confirmatory
order.





In August 2007,
FENOC submitted an application to the NRC to renew the operating licenses for
the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The
NRC is required by statute to provide an opportunity for members of the public
to request a hearing on the application. No members of the public, however,
requested a hearing on the Beaver Valley license renewal application. On
September 24, 2008, the NRC issued a draft supplemental Environmental
Impact Statement for Beaver Valley. FENOC will continue to work with the
NRC Staff as it completes its environmental and technical reviews of the license
renewal application, and expects to obtain renewed licenses for the Beaver
Valley Power Station in 2009. If renewed licenses are issued by the NRC, the
Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for
Units 1 and 2, respectively.





44








Other Legal Matters





There are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to FirstEnergy's normal business operations pending against FirstEnergy
and its subsidiaries. The other potentially material items not otherwise
discussed above are described below.





On August 22, 2005,
a class action complaint was filed against OE in Jefferson County, Ohio Common
Pleas Court, seeking compensatory and punitive damages to be determined at trial
based on claims of negligence and eight other tort counts alleging damages from
W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking
injunctive relief to eliminate harmful emissions and repair property damage and
the institution of a medical monitoring program for class members. On
April 5, 2007, the Court rejected the plaintiffs’ request to certify this
case as a class action and, accordingly, did not appoint the plaintiffs as class
representatives or their counsel as class counsel. On July 30, 2007,
plaintiffs’ counsel voluntarily withdrew their request for reconsideration of
the April 5, 2007 Court order denying class certification and the Court
heard oral argument on the plaintiffs’ motion to amend their complaint, which OE
opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to
amend their complaint. The plaintiffs have appealed the Court’s denial of the
motion for certification as a class action and motion to amend their complaint
and oral argument was held on November 5, 2008.





JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
panel decided not to hear testimony on damages and closed the proceedings. On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district Court granted a union motion to dismiss, as premature,
a JCP&L appeal of the award filed on October 18, 2005. A final order
identifying the individual damage amounts was issued on October 31, 2007.
The award appeal process was initiated. The union filed a motion with the
federal Court to confirm the award and JCP&L filed its answer and
counterclaim to vacate the award on December 31, 2007. JCP&L and the
union filed briefs in June and July of 2008 and oral arguments were held in the
fall. The Court has yet to render its decision. JCP&L recognized a liability
for the potential $16 million award in 2005.





The union employees
at the Bruce Mansfield Plant have been working without a labor contract since
February 15, 2008. The parties are continuing to bargain with the assistance of
a federal mediator. FirstEnergy has a strike mitigation plan ready in the event
of a strike.





FirstEnergy accrues
legal liabilities only when it concludes that it is probable that it has an
obligation for such costs and can reasonably estimate the amount of such costs.
If it were ultimately determined that FirstEnergy or its subsidiaries have legal
liability or are otherwise made subject to liability based on the above matters,
it could have a material adverse effect on FirstEnergy's or its subsidiaries'
financial condition, results of operations and cash flows.





NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS





SFAS 141(R) – “Business
Combinations”





In December 2007,
the FASB issued SFAS 141(R), which: (i) requires the acquiring entity in a
business combination to recognize all assets acquired and liabilities assumed in
the transaction; (ii) establishes the acquisition-date fair value as the
measurement objective for all assets acquired and liabilities assumed; and (iii)
requires the acquirer to disclose to investors and other users all of the
information they need to evaluate and understand the nature and financial effect
of the business combination. The Standard includes both core principles and
pertinent application guidance, eliminating the need for numerous EITF issues
and other interpretative guidance. SFAS 141(R) will affect business combinations
entered into by FirstEnergy that close after January 1, 2009. In addition,
the Standard also affects the accounting for changes in deferred tax valuation
allowances and income tax uncertainties made after January 1, 2009, that
were established as part of a business combination prior to the implementation
of this Standard. Under SFAS 141(R), adjustments to the acquired entity’s
deferred tax assets and uncertain tax position balances occurring outside the
measurement period will be recorded as a component of income tax expense, rather
than goodwill.The
impact of FirstEnergy’s application of this Standard in periods after
implementation will be dependent upon acquisitions at that time.





45








SFAS
160 - “Non-controlling Interests in Consolidated Financial Statements – an
Amendment of ARB No. 51”





In December 2007,
the FASB issued SFAS 160 that establishes accounting and reporting standards for
the noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an
ownership interest in the consolidated entity that should be reported as equity
in the consolidated financial statements. This Statement is effective for fiscal
years, and interim periods within those fiscal years, beginning on or after
December 15, 2008. Early adoption is prohibited. The Statement is not
expected to have a material impact on FirstEnergy’s financial
statements.





SFAS
      161 - “Disclosures about Derivative Instruments and Hedging Activities –
      an Amendment of FASB Statement No.
133”





In March 2008, the
FASB issued SFAS 161 that enhances the current disclosure framework for
derivative instruments and hedging activities. The Statement requires that
objectives for using derivative instruments be disclosed in terms of underlying
risk and accounting designation. The FASB believes that additional required
disclosure of the fair values of derivative instruments and their gains and
losses in a tabular format will provide a more complete picture of the location
in an entity’s financial statements of both the derivative positions existing at
period end and the effect of using derivatives during the reporting period.
Disclosing information about credit-risk-related contingent features is designed
to provide information on the potential effect on an entity’s liquidity from
using derivatives. This Statement also requires cross-referencing within the
footnotes to help users of financial statements locate important information
about derivative instruments. The Statement is effective for reporting periods
beginning after November 15, 2008. FirstEnergy expects this Standard to
increase its disclosure requirements for derivative instruments and hedging
activities.








46











Report
of Independent Registered Public Accounting Firm


























To the Stockholders
and Board of


Directors of
FirstEnergy Corp.:





We have reviewed the
accompanying consolidated balance sheet of FirstEnergy Corp. and its
subsidiaries as of September 30, 2008 and the related consolidated
statements of income and comprehensive income for each of the three-month and
nine-month periods ended September 30, 2008 and 2007 and the consolidated
statement of cash flows for the nine-month periods ended September 30, 2008 and
2007. These interim financial statements are the responsibility of the Company’s
management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2007, and the related consolidated statements of income, capitalization,
common stockholders’ equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 28, 2008, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying consolidated balance
sheet information as of December 31, 2007, is fairly stated in all material
respects in relation to the consolidated balance sheet from which it has been
derived.




PricewaterhouseCoopers
      LLP
              Cleveland,
      Ohio
              November 6,
      2008








47




FIRSTENERGY
      CORP.CONSOLIDATED
      STATEMENTS OF INCOME(Unaudited)Three
      Months
              
              
              Nine
      MonthsEnded
      September 30
              
              
              Ended
      September 302008
              
              
              2007
              
              
              2008
              
              
              2007(In
      millions, except per share amounts)REVENUES:Electric
      utilities
              
              $
              3,469
              
              
              $
              3,242
              
              
              $
              9,247
              
              
              $
              8,619Unregulated
      businesses
              
              
              435
              
              
              
              399
              
              
              
              1,179
              
              
              
              1,104Total revenues
      *
              
              
              3,904
              
              
              
              3,641
              
              
              
              10,426
              
              
              
              9,723EXPENSES:Fuel
              
              
              356
              
              
              
              327
              
              
              
              1,000
              
              
              
              887Purchased
      power
              
              
              1,306
              
              
              
              1,168
              
              
              
              3,376
              
              
              
              2,914Other
      operating expenses
              
              
              794
              
              
              
              756
              
              
              
              2,375
              
              
              
              2,255Provision for
      depreciation
              
              
              168
              
              
              
              162
              
              
              
              500
              
              
              
              477Amortization
      of regulatory assets
              
              
              291
              
              
              
              288
              
              
              
              795
              
              
              
              785Deferral of
      new regulatory assets
              
              
              (58
              )
              
              
              (107
              )
              
              
              (261
              )
              
              
              (399
              )General
      taxes
              
              
              201
              
              
              
              197
              
              
              
              596
              
              
              
              589Total
      expenses
              
              
              3,058
              
              
              
              2,791
              
              
              
              8,381
              
              
              
              7,508OPERATING
      INCOME
              
              
              846
              
              
              
              850
              
              
              
              2,045
              
              
              
              2,215OTHER
      INCOME (EXPENSE):Investment
      income
              
              
              40
              
              
              
              30
              
              
              
              73
              
              
              
              93Interest
      expense
              
              
              (192
              )
              
              
              (203
              )
              
              
              (559
              )
              
              
              (593
              )Capitalized
      interest
              
              
              15
              
              
              
              9
              
              
              
              36
              
              
              
              21Total other
      expense
              
              
              (137
              )
              
              
              (164
              )
              
              
              (450
              )
              
              
              (479
              )INCOME
      BEFORE INCOME TAXES
              
              
              709
              
              
              
              686
              
              
              
              1,595
              
              
              
              1,736INCOME
      TAXES
              
              
              238
              
              
              
              273
              
              
              
              585
              
              
              
              695NET
      INCOME
              
              $
              471
              
              
              $
              413
              
              
              $
              1,010
              
              
              $
              1,041BASIC
      EARNINGS PER SHARE OF COMMON STOCK
              
              $
              1.55
              
              
              $
              1.36
              
              
              $
              3.32
              
              
              $
              3.39WEIGHTED
      AVERAGE NUMBER OFBASIC
      SHARES OUTSTANDING
              
              
              304
              
              
              
              304
              
              
              
              304
              
              
              
              307DILUTED
      EARNINGS PER SHARE OF COMMON STOCK
              
              $
              1.54
              
              
              $
              1.34
              
              
              $
              3.29
              
              
              $
              3.35WEIGHTED
      AVERAGE NUMBER OFDILUTED
      SHARES OUTSTANDING
              
              
              307
              
              
              
              307
              
              
              
              307
              
              
              
              311DIVIDENDS
      DECLARED PER SHARE OF COMMON STOCK
              
              $
              1.10
              
              
              $
              1.00
              
              
              $
              1.65
              
              
              $
              1.50* Includes
      excise tax collections of $115 million and $113 million in the three
      months ended September 30, 2008 and 2007,respectively,
      and $329 million and $322 million in the nine months ended September 2008
      and 2007, respectively.The
      accompanying Notes to Consolidated Financial Statements as they relate to
      FirstEnergy Corp. are an integral part ofthese
      statements.
  48
  
 FIRSTENERGY
      CORP.CONSOLIDATED
      STATEMENTS OF COMPREHENSIVE INCOME(Unaudited)Three
      Months
              
              
              Nine
      MonthsEnded
      September 30
              
              
              Ended
      September 302008
              
              
              2007
              
              
              2008
              
              
              2007(In
      millions)NET
      INCOME
              
              $
              471
              
              
              $
              413
              
              
              $
              1,010
              
              
              $
              1,041OTHER
      COMPREHENSIVE INCOME (LOSS):Pension and
      other postretirement benefits
              
              
              (20
              )
              
              
              (12
              )
              
              
              (60
              )
              
              
              (34
              )Unrealized
      gain (loss) on derivative hedges
              
              
              26
              
              
              
              (10
              )
              
              
              21
              
              
              
              10Change in
      unrealized gain on available for sale securities
              
              
              (100
              )
              
              
              26
              
              
              
              (181
              )
              
              
              89Other
      comprehensive income (loss)
              
              
              (94
              )
              
              
              4
              
              
              
              (220
              )
              
              
              65Income tax
      expense (benefit) related to othercomprehensive
      income
              
              
              (34
              )
              
              
              -
              
              
              
              (81
              )
              
              
              19Other
      comprehensive income (loss), net of tax
              
              
              (60
              )
              
              
              4
              
              
              
              (139
              )
              
              
              46COMPREHENSIVE
      INCOME
              
              $
              411
              
              
              $
              417
              
              
              $
              871
              
              
              $
              1,087The
      accompanying Notes to Consolidated Financial Statements as they relate to
      FirstEnergy Corp. are an integral part ofthese
      statements.
  
 49
  
 FIRSTENERGY
      CORP.CONSOLIDATED
      BALANCE SHEETS(Unaudited)September
      30,
              
              
              December
      31,2008
              
              
              2007(In
      millions)ASSETSCURRENT
      ASSETS:Cash and cash
      equivalents
              
              $
              181
              
              
              $
              129Receivables-Customers
      (less accumulated provisions of $31 million and$36 million,
      respectively, for uncollectible accounts)
              
              
              1,383
              
              
              
              1,256Other (less
      accumulated provisions of $9 million and$22 million,
      respectively, for uncollectible accounts)
              
              
              148
              
              
              
              165Materials and
      supplies, at average cost
              
              
              587
              
              
              
              521Prepayments
      and other
              
              
              505
              
              
              
              1592,804
              
              
              
              2,230PROPERTY,
      PLANT AND EQUIPMENT:In
      service
              
              
              26,141
              
              
              
              24,619Less -
      Accumulated provision for depreciation
              
              
              10,714
              
              
              
              10,34815,427
              
              
              
              14,271Construction
      work in progress
              
              
              1,730
              
              
              
              1,11217,157
              
              
              
              15,383INVESTMENTS:Nuclear plant
      decommissioning trusts
              
              
              1,873
              
              
              
              2,127Investments in
      lease obligation bonds
              
              
              674
              
              
              
              717Other
              
              
              720
              
              
              
              7543,267
              
              
              
              3,598DEFERRED
      CHARGES AND OTHER ASSETS:Goodwill
              
              
              5,583
              
              
              
              5,607Regulatory
      assets
              
              
              3,433
              
              
              
              3,945Pension
      assets
              
              
              768
              
              
              
              700Other
              
              
              550
              
              
              
              60510,334
              
              
              
              10,857$
              33,562
              
              
              $
              32,068LIABILITIES
      AND CAPITALIZATIONCURRENT
      LIABILITIES:Currently
      payable long-term debt
              
              $
              2,509
              
              
              $
              2,014Short-term
      borrowings
              
              
              2,392
              
              
              
              903Accounts
      payable
              
              
              744
              
              
              
              777Accrued
      taxes
              
              
              253
              
              
              
              408Other
              
              
              1,149
              
              
              
              1,0467,047
              
              
              
              5,148CAPITALIZATION:Common
      stockholders’ equity-Common stock,
      $0.10 par value, authorized 375,000,000 shares-304,835,407
      outstanding
              
              
              31
              
              
              
              31Other paid-in
      capital
              
              
              5,465
              
              
              
              5,509Accumulated
      other comprehensive loss
              
              
              (189
              )
              
              
              (50
              )Retained
      earnings
              
              
              3,994
              
              
              
              3,487Total common
      stockholders' equity
              
              
              9,301
              
              
              
              8,977Long-term debt
      and other long-term obligations
              
              
              8,674
              
              
              
              8,86917,975
              
              
              
              17,846NONCURRENT
      LIABILITIES:Accumulated
      deferred income taxes
              
              
              2,793
              
              
              
              2,671Asset
      retirement obligations
              
              
              1,314
              
              
              
              1,267Deferred gain
      on sale and leaseback transaction
              
              
              1,035
              
              
              
              1,060Power purchase
      contract loss liability
              
              
              603
              
              
              
              750Retirement
      benefits
              
              
              914
              
              
              
              894Lease market
      valuation liability
              
              
              319
              
              
              
              663Other
              
              
              1,562
              
              
              
              1,7698,540
              
              
              
              9,074COMMITMENTS,
      GUARANTEES AND CONTINGENCIES (Note 11)$
              33,562
              
              
              $
              32,068The
      accompanying Notes to Consolidated Financial Statements as they relate to
      FirstEnergy Corp. are an integral part of thesebalance
      sheets.
 
 50
 
 FIRSTENERGY
      CORP.CONSOLIDATED
      STATEMENTS OF CASH FLOWS(Unaudited)Nine
      MonthsEnded
      September 302008
                
                2007(In
      millions)CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      income
                
                $
                1,010
                
                $
                1,041Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
                
                
                500
                
                
                477Amortization
      of regulatory assets
                
                
                795
                
                
                785Deferral of
      new regulatory assets
                
                
                (261
                )
                
                (399
                )Nuclear fuel
      and lease amortization
                
                
                82
                
                
                75Deferred
      purchased power and other costs
                
                
                (163
                )
                
                (265
                )Deferred
      income taxes and investment tax credits, net
                
                
                278
                
                
                (158
                )Investment
      impairment
                
                
                63
                
                
                16Deferred rents
      and lease market valuation liability
                
                
                (62
                )
                
                (41
                )Accrued
      compensation and retirement benefits
                
                
                (127
                )
                
                (50
                )Stock-based
      compensation
                
                
                (74
                )
                
                (32
                )Commodity
      derivative transactions, net
                
                
                4
                
                
                5Gain on asset
      sales
                
                
                (43
                )
                
                (35
                )Cash
      collateral
                
                
                21
                
                
                (50
                )Pension trust
      contribution
                
                
                -
                
                
                (300
                )Decrease
      (increase) in operating assets-Receivables
                
                
                (117
                )
                
                (329
                )Materials and
      supplies
                
                
                (34
                )
                
                62Prepayments
      and other current assets
                
                
                (264
                )
                
                (39
                )Increase
      (decrease) in operating liabilities-Accounts
      payable
                
                
                (34
                )
                
                (15
                )Accrued
      taxes
                
                
                (166
                )
                
                355Accrued
      interest
                
                
                107
                
                
                104Electric
      service prepayment programs
                
                
                (58
                )
                
                (52
                )Other
                
                
                (29
                )
                
                55Net cash
      provided from operating activities
                
                
                1,428
                
                
                1,210CASH
      FLOWS FROM FINANCING ACTIVITIES:New
      Financing-Long-term
      debt
                
                
                631
                
                
                1,100Short-term
      borrowings, net
                
                
                1,489
                
                
                -Redemptions
      and Repayments-Common
      stock
                
                
                -
                
                
                (918
                )Long-term
      debt
                
                
                (733
                )
                
                (647
                )Short-term
      borrowings, net
                
                
                -
                
                
                (535
                )Net controlled
      disbursement activity
                
                
                6
                
                
                6Stock-based
      compensation tax benefit
                
                
                24
                
                
                16Common stock
      dividend payments
                
                
                (503
                )
                
                (464
                )Net cash
      provided from (used for) financing activities
                
                
                914
                
                
                (1,442
                )CASH
      FLOWS FROM INVESTING ACTIVITIES:Property
      additions
                
                
                (2,177
                )
                
                (1,127
                )Proceeds from
      asset sales
                
                
                64
                
                
                37Proceeds from
      sale and leaseback transaction
                
                
                -
                
                
                1,329Sales of
      investment securities held in trusts
                
                
                1,144
                
                
                1,010Purchases of
      investment securities held in trusts
                
                
                (1,215
                )
                
                (1,126
                )Cash
      investments
                
                
                72
                
                
                48Restricted
      funds for debt redemption
                
                
                (82
                )
                
                -Other
                
                
                (96
                )
                
                1Net cash
      provided from (used for) investing activities
                
                
                (2,290
                )
                
                172Net change in
      cash and cash equivalents
                
                
                52
                
                
                (60
                )Cash and cash
      equivalents at beginning of period
                
                
                129
                
                
                90Cash and cash
      equivalents at end of period
                
                $
                181
                
                $
                30The
      accompanying Notes to Consolidated Financial Statements as they relate to
      FirstEnergy Corp. are anintegral part
      of these statements.
  51




FIRSTENERGY
SOLUTIONS CORP.





MANAGEMENT’S
NARRATIVE


ANALYSIS
OF RESULTS OF OPERATIONS








FES is a wholly
owned subsidiary of FirstEnergy. FES provides energy-related products and
services primarily in Ohio, Pennsylvania, Michigan and Maryland, and through its
subsidiaries, FGCO and NGC, owns or leases and operates FirstEnergy’s fossil and
hydroelectric generation facilities and owns FirstEnergy’s nuclear generation
facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy,
operates and maintains the nuclear generating facilities.





FES’ revenues are
primarily from the sale of electricity (provided from FES’ generating facilities
and through purchased power arrangements) to affiliated utility companies to
meet all or a portion of their PLR and default service requirements. These
affiliated power sales include a full-requirements PSA with OE, CEI and TE to
supply each of their default service obligations through 2008, at prices that
take into consideration their respective PUCO-authorized billing rates. FES also
has a partial requirements wholesale power sales agreement with its affiliates,
Met-Ed and Penelec, to supply a portion of each of their respective default
service obligations at fixed prices through 2010. The fixed prices under the
partial requirements agreement are expected to remain below wholesale market
prices during the term of the agreement. FES also supplies a portion of Penn’s
default service requirements at market-based rates as a result of Penn’s 2008
competitive solicitations. FES’ existing contractual obligations to Penn expire
on May 31, 2009, but could continue if FES successfully bids in future
competitive solicitations. FES’ revenues also include competitive retail and
wholesale sales to non-affiliated customers in Ohio, Pennsylvania, Maryland and
Michigan.





Results of
Operations





In the first nine
months of 2008, net income decreased to $344million from $409million in the same
period in 2007. The decrease in net income was primarily due to higher fuel and
other operating expenses, partially offset by lower purchased power costs and
higher revenues.





Revenues





Revenues increased
by $154million in the
first nine months of 2008 compared to the same period of 2007 due to increases
in revenues from non-affiliated and affiliated wholesale sales, partially offset
by lower retail generation sales. Non-affiliated wholesale revenues increased as
a result of higher capacity prices and sales volumes in the PJM market,
partially offset by decreased sales volumes in the MISO market. Retail
generation sales revenues decreased as a result of decreased sales in the PJM
market partially offset by increased sales in the MISO market. Lower sales in
the PJM market were primarily due to lower contract renewals for commercial and
industrial customers. Increased sales in the MISO market were primarily due to
FES capturing more shopping customers in Penn’s service territory, partially
offset by lower customer usage.





The increase in
affiliated company wholesale sales was due to higher unit prices for the Ohio
Companies partially offset by lower unit prices for the Pennsylvania Companies
and decreased sales volumes to all affiliates. Higher unit prices on sales to
the Ohio Companies resulted from the PSA provision, whereby PSA rates reflect
the increase in the Ohio Companies’ retail generation rates. While unit prices
for each of the Pennsylvania Companies did not change, the mix of sales among
the companies caused the composite price to decline. The lower PSA sales volumes
to the Ohio and Pennsylvania Companies were due to milder weather and decreased
default service requirements in Penn’s service territory as a result of its RFP
process.





Changes in revenues
in the first nine months of 2008 from the same period of 2007 are summarized
below:





Nine  Months
      EndedSeptember
      30,
            
            IncreaseRevenues
      by Type of Service
            
            2008
            
            2007
            
            (Decrease)(In
      millions)Non-Affiliated
      Generation Sales:Retail
            
            $
            485
            
            $
            547
            
            $
            (62
            )Wholesale
            
            
            509
            
            
            426
            
            
            83Total
      Non-Affiliated Generation Sales
            
            
            994
            
            
            973
            
            
            21Affiliated
      Generation Sales
            
            
            2,266
            
            
            2,210
            
            
            56Transmission
            
            
            113
            
            
            71
            
            
            42Other
            
            
            39
            
            
            4
            
            
            35Total
      Revenues
            
            $
            3,412
            
            $
            3,258
            
            $
            154






52








The following tables
summarize the price and volume factors contributing to changes in revenues from
non-affiliated and affiliated generation sales in the first nine months of 2008
compared to the same period last year:





IncreaseSource
      of Change in Non-Affiliated Generation Revenues
            
            (Decrease)(In
      millions)Retail:Effect of 13.2% decrease in sales
      volumes
            
            $
            (73
            )Change in prices
            
            
            11(62
            )Wholesale:Effect of 4.6% increase in sales
      volumes
            
            
            19Change in prices
            
            
            6483Net Increase
      in Non-Affiliated Generation Revenues
            
            $
            21





IncreaseSource
      of Change in Affiliated Generation Revenues
            
            (Decrease)(In
      millions)Ohio
      Companies:Effect of 1.7% decrease in sales
      volumes
            
            $
            (28
            )Change in prices
            
            
            9769Pennsylvania
      Companies:Effect of 0.2% decrease in sales
      volumes
            
            
            (1
            )Change in prices
            
            
            (12
            )(13
            )Net Increase
      in Affiliated Generation Revenues
            
            $
            56





Transmission revenue
increased $42 million due primarily to higher rates for transmission
service in MISO and PJM. Other revenue increased by $34 million principally
due to revenue from affiliated companies for the lessor equity interests in
Beaver Valley Unit 2 and Perry that were acquired by NGC during the second
quarter of 2008.





Expenses





Total expenses
increased by $272 million in the first nine months of 2008 compared with
the same period of 2007. The following tables summarize the factors contributing
to the changes in fuel and purchased power costs in the first nine months of
2008 from the same period last year:





Source
      of Change in Fuel Costs
            
            Increase(In
      millions)Fossil
      Fuel:Change due to volume
      consumed
            
            $
            98Change due to increased unit
      costs
            
            
            73171Nuclear
      Fuel:Change due to volume
      consumed
            
            
            4Change due to increased unit
      costs
            
            
            37Net Increase
      in Fuel Costs
            
            $
            178








Fossil fuel costs
increased $171 million in the first nine months of 2008 as a result of the
assignment of CEI’s and TE’s leasehold interest in the Bruce Mansfield Plant to
FGCO in October 2007 and higher unit prices due to increased coal transportation
costs, increased prices for existing eastern coal contracts and emission
allowance costs. The increased fossil fuel costs were partially offset by a $25
million adjustment resulting from the annual coal inventory that reduced expense
in the 2008 period. Nuclear fuel expense increased $7 million reflecting
higher generation in 2008.





53








Source
      of Change in Purchased Power Costs
            
            Increase
                (Decrease)(In
      millions)Purchased
      Power From Non-affiliates:Change due to volume
      purchased
            
            $
            (121
            )Change due to increased unit
      costs
            
            
            19271Purchased
      Power From AffiliatesChange due to volume
      purchased
            
            
            (126
            )Change due to decreased unit
      costs
            
            
            (8
            )(134
            )Net Decrease
      in Purchased Power Costs
            
            $
            (63
            )








Purchased power
costs decreased as a result of reduced purchases from affiliates, partially
offset by increased non-affiliated purchased power costs. Purchases from
affiliated companies decreased as a result of the assignment of CEI’s and TE’s
leasehold interests in the Mansfield Plant to FGCO; prior to the assignment,
FGCO purchased the associated output from CEI and TE. Purchased power costs from
non-affiliates increased primarily as a result of higher spot market prices in
MISO and PJM partially offset by reduced volumes reflecting lower retail sales
requirements and more available generation.





Other operating
expenses increased by $132million in the first
nine months of 2008 from the same period of 2007 primarily due to lease expenses
relating to the assignment of CEI’s and TE’s leasehold interests in the
Mansfield Plant to FGCO ($36 million) and the sale and leaseback of
Mansfield Unit 1 ($72 million) completed in the second half of 2007. Higher
nuclear operating costs were due to an additional refueling outage during the
first nine months of 2008 compared with 2007. Higher fossil operating costs were
primarily due to a cancelled fossil project ($13 million), additional planned
maintenance outages in 2008, employee benefits and reduced gains from excess
emission allowance sales.





Depreciation expense
increased by $26 million in the first nine months of 2008 primarily due to
the assignment of the Mansfield Plant to FGCO described above and NGC’s
acquisition of certain lessor equity interest in the sale and leaseback of Perry
and Beaver Valley Unit 2.





Other Expense





Other expense
decreased by $8million in the first
nine months of 2008 from the same period of 2007 primarily as a result
of  decreased interest expense (net of capitalized interest),
partially offset by lower miscellaneous income. Affiliated interest expense
decreased $36 million primarily as a result of reduced loans from the
unregulated money pool. Lower miscellaneous income resulted from a
$13 million decrease in net earnings from nuclear decommissioning trust
investments due primarily to securities impairments and reduced investment
income from loans to the unregulated money pool ($15 million).





Legal
Proceedings





See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to FES.





New Accounting Standards and
Interpretations





See
the “New Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to FES.














54











Report
of Independent Registered Public Accounting Firm


























To the Stockholder
and Board of


Directors of
FirstEnergy Solutions Corp.:





We have reviewed the
accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its
subsidiaries as of September 30, 2008 and the related consolidated
statements of income and comprehensive income for each of the three-month and
nine-month periods ended September 30, 2008 and 2007 and the consolidated
statement of cash flows for the nine-month periods ended September 30, 2008 and
2007. These interim financial statements are the responsibility of the Company’s
management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2007, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 28, 2008, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying consolidated balance
sheet information as of December 31, 2007, is fairly stated in all material
respects in relation to the consolidated balance sheet from which it has been
derived.




PricewaterhouseCoopers
      LLP
              Cleveland,
      Ohio
              November 6,
      2008











55





FIRSTENERGY
      SOLUTIONS CORP.CONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE INCOME(Unaudited)Three
      Months
              
              
              Nine
      MonthsEnded
      September 30
              
              
              Ended
      September 302008
              
              
              2007
              
              
              2008
              
              
              2007(In
      thousands)REVENUES:Electric sales
      to affiliates
              
              $
              785,681
              
              
              $
              805,372
              
              
              $
              2,266,271
              
              
              $
              2,209,743Electric sales
      to non-affiliates
              
              
              381,483
              
              
              
              337,561
              
              
              
              994,100
              
              
              
              972,591Other
              
              
              74,440
              
              
              
              27,975
              
              
              
              151,627
              
              
              
              75,598Total
      revenues
              
              
              1,241,604
              
              
              
              1,170,908
              
              
              
              3,411,998
              
              
              
              3,257,932EXPENSES:Fuel
              
              
              349,946
              
              
              
              301,786
              
              
              
              982,185
              
              
              
              804,201Purchased
      power from non-affiliates
              
              
              221,493
              
              
              
              228,755
              
              
              
              648,556
              
              
              
              577,831Purchased
      power from affiliates
              
              
              15,821
              
              
              
              62,508
              
              
              
              75,834
              
              
              
              209,576Other
      operating expenses
              
              
              279,184
              
              
              
              235,033
              
              
              
              863,468
              
              
              
              731,774Provision for
      depreciation
              
              
              64,633
              
              
              
              48,500
              
              
              
              170,535
              
              
              
              145,030General
      taxes
              
              
              21,736
              
              
              
              22,242
              
              
              
              64,728
              
              
              
              64,870Total
      expenses
              
              
              952,813
              
              
              
              898,824
              
              
              
              2,805,306
              
              
              
              2,533,282OPERATING
      INCOME
              
              
              288,791
              
              
              
              272,084
              
              
              
              606,692
              
              
              
              724,650OTHER
      INCOME (EXPENSE):Miscellaneous
      income
              
              
              18,427
              
              
              
              12,655
              
              
              
              13,449
              
              
              
              47,756Interest
      expense - affiliates
              
              
              (8,015
              )
              
              
              (9,641
              )
              
              
              (25,953
              )
              
              
              (61,904
              )Interest
      expense - other
              
              
              (32,769
              )
              
              
              (31,794
              )
              
              
              (81,809
              )
              
              
              (70,845
              )Capitalized
      interest
              
              
              12,395
              
              
              
              5,131
              
              
              
              29,599
              
              
              
              12,763Total other
      expense
              
              
              (9,962
              )
              
              
              (23,649
              )
              
              
              (64,714
              )
              
              
              (72,230
              )INCOME
      BEFORE INCOME TAXES
              
              
              278,829
              
              
              
              248,435
              
              
              
              541,978
              
              
              
              652,420INCOME
      TAXES
              
              
              93,174
              
              
              
              93,671
              
              
              
              198,245
              
              
              
              243,736NET
      INCOME
              
              
              185,655
              
              
              
              154,764
              
              
              
              343,733
              
              
              
              408,684OTHER
      COMPREHENSIVE INCOME (LOSS):Pension and
      other postretirement benefits
              
              
              (1,821
              )
              
              
              (1,360
              )
              
              
              (5,462
              )
              
              
              (4,080
              )Unrealized
      gain on derivative hedges
              
              
              27,277
              
              
              
              4,863
              
              
              
              15,075
              
              
              
              9,451Change in
      unrealized gain on available-for-sale securities
              
              
              (90,198
              )
              
              
              21,263
              
              
              
              (159,759
              )
              
              
              80,053Other
      comprehensive income (loss)
              
              
              (64,742
              )
              
              
              24,766
              
              
              
              (150,146
              )
              
              
              85,424Income tax
      expense (benefit) related to othercomprehensive
      income
              
              
              (24,781
              )
              
              
              8,915
              
              
              
              (55,497
              )
              
              
              30,474Other
      comprehensive income (loss), net of tax
              
              
              (39,961
              )
              
              
              15,851
              
              
              
              (94,649
              )
              
              
              54,950TOTAL
      COMPREHENSIVE INCOME
              
              $
              145,694
              
              
              $
              170,615
              
              
              $
              249,084
              
              
              $
              463,634The
      accompanying Notes to Consolidated Financial Statements as they related to
      FirstEnergy Solutions Corp. are an integral part ofthese balance
      sheets.
  56
   FIRSTENERGY
      SOLUTIONS CORP.CONSOLIDATED
      BALANCE SHEETS(Unaudited)September
      30,
              
              
              December
      31,2008
              
              
              2007(In
      thousands)ASSETSCURRENT
      ASSETS:Cash and cash
      equivalents
              
              $
              2
              
              
              $
              2Receivables-Customers
      (less accumulated provisions of $5,840,000 and $8,072,000,respectively,
      for uncollectible accounts)
              
              
              137,126
              
              
              
              133,846Associated
      companies
              
              
              263,779
              
              
              
              376,499Other (less
      accumulated provisions of $6,798,000 and $9,000respectively,
      for uncollectible accounts)
              
              
              22,924
              
              
              
              3,823Notes
      receivable from associated companies
              
              
              156,926
              
              
              
              92,784Materials and
      supplies, at average cost
              
              
              497,276
              
              
              
              427,015Prepayments
      and other
              
              
              179,530
              
              
              
              92,3401,257,563
              
              
              
              1,126,309PROPERTY,
      PLANT AND EQUIPMENT:In
      service
              
              
              9,834,662
              
              
              
              8,294,768Less -
      Accumulated provision for depreciation
              
              
              4,211,717
              
              
              
              3,892,0135,622,945
              
              
              
              4,402,755Construction
      work in progress
              
              
              1,385,652
              
              
              
              761,7017,008,597
              
              
              
              5,164,456OTHER
      PROPERTY AND INVESTMENTS:Nuclear plant
      decommissioning trusts
              
              
              1,145,384
              
              
              
              1,332,913Long-term
      notes receivable from associated companies
              
              
              62,900
              
              
              
              62,900Other
              
              
              40,573
              
              
              
              40,0041,248,857
              
              
              
              1,435,817DEFERRED
      CHARGES AND OTHER ASSETS:Accumulated
      deferred income tax benefits
              
              
              230,341
              
              
              
              276,923Lease
      assignment receivable from associated companies
              
              
              71,356
              
              
              
              215,258Goodwill
              
              
              24,248
              
              
              
              24,248Property
      taxes
              
              
              47,774
              
              
              
              47,774Pension
      assets
              
              
              14,764
              
              
              
              16,723Unamortized
      sale and leaseback costs
              
              
              57,365
              
              
              
              70,803Other
              
              
              49,702
              
              
              
              43,953495,550
              
              
              
              695,682$
              10,010,567
              
              
              $
              8,422,264LIABILITIES
      AND CAPITALIZATIONCURRENT
      LIABILITIES:Currently
      payable long-term debt
              
              $
              1,938,215
              
              
              $
              1,441,196Short-term
      borrowings-Associated
      companies
              
              
              311,750
              
              
              
              264,064Other
              
              
              1,000,000
              
              
              
              300,000Accounts
      payable-Associated
      companies
              
              
              361,447
              
              
              
              445,264Other
              
              
              163,173
              
              
              
              177,121Accrued
      taxes
              
              
              80,719
              
              
              
              171,451Other
              
              
              217,914
              
              
              
              237,8064,073,218
              
              
              
              3,036,902CAPITALIZATION:Common
      stockholder's equity-Common stock,
      without par value, authorized 750 shares-7 shares
      outstanding
              
              
              1,461,541
              
              
              
              1,164,922Accumulated
      other comprehensive income
              
              
              46,005
              
              
              
              140,654Retained
      earnings
              
              
              1,409,388
              
              
              
              1,108,655Total common
      stockholder's equity
              
              
              2,916,934
              
              
              
              2,414,231Long-term debt
      and other long-term obligations
              
              
              558,923
              
              
              
              533,7123,475,857
              
              
              
              2,947,943NONCURRENT
      LIABILITIES:Deferred gain
      on sale and leaseback transaction
              
              
              1,035,013
              
              
              
              1,060,119Accumulated
      deferred investment tax credits
              
              
              63,968
              
              
              
              61,116Asset
      retirement obligations
              
              
              849,475
              
              
              
              810,114Retirement
      benefits
              
              
              67,567
              
              
              
              63,136Property
      taxes
              
              
              48,095
              
              
              
              48,095Lease market
      valuation liability
              
              
              319,129
              
              
              
              353,210Other
              
              
              78,245
              
              
              
              41,6292,461,492
              
              
              
              2,437,419COMMITMENTS
      AND CONTINGENCIES (Note 11)$
              10,010,567
              
              
              $
              8,422,264The
      accompanying Notes to Consolidated Financial Statements as they related to
      FirstEnergy Solutions Corp. are an integralpart of these
      balance sheets.
  57
   FIRSTENERGY
      SOLUTIONS CORP.CONSOLIDATED
      STATEMENTS OF CASH FLOWS(Unaudited)Nine
      MonthsEnded
      September 302008
              
              
              2007(In
      thousands)CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      income
              
              $
              343,733
              
              
              $
              408,684Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
              
              
              170,535
              
              
              
              145,030Nuclear fuel
      and lease amortization
              
              
              81,950
              
              
              
              75,102Deferred rents
      and lease market valuation liability
              
              
              (36,702
              )
              
              
              -Deferred
      income taxes and investment tax credits, net
              
              
              91,082
              
              
              
              (381,042
              )Investment
      impairment
              
              
              58,173
              
              
              
              14,296Accrued
      compensation and retirement benefits
              
              
              (2,110
              )
              
              
              3,414Commodity
      derivative transactions, net
              
              
              3,634
              
              
              
              4,913Gain on asset
      sales
              
              
              (11,319
              )
              
              
              (12,105
              )Cash
      collateral, net
              
              
              (8,827
              )
              
              
              (19,798
              )Pension trust
      contribution
              
              
              -
              
              
              
              (64,020
              )Decrease
      (increase) in operating assets:Receivables
              
              
              106,574
              
              
              
              (30,172
              )Materials and
      supplies
              
              
              (35,498
              )
              
              
              48,123Prepayments
      and other current assets
              
              
              (10,762
              )
              
              
              (5,118
              )Increase
      (decrease) in operating liabilities:Accounts
      payable
              
              
              (61,035
              )
              
              
              (108,949
              )Accrued
      taxes
              
              
              (90,767
              )
              
              
              434,568Accrued
      interest
              
              
              15,420
              
              
              
              14,355Other
              
              
              (59,948
              )
              
              
              (5,254
              )Net cash
      provided from operating activities
              
              
              554,133
              
              
              
              522,027CASH
      FLOWS FROM FINANCING ACTIVITIES:New
      Financing-Long-term
      debt
              
              
              537,375
              
              
              
              -Equity
      contribution from parent
              
              
              280,000
              
              
              
              700,000Short-term
      borrowings, net
              
              
              747,686
              
              
              
              -Redemptions
      and Repayments-Common
      stock
              
              
              -
              
              
              
              (600,000
              )Long-term
      debt
              
              
              (460,902
              )
              
              
              (1,110,174
              )Short-term
      borrowings, net
              
              
              -
              
              
              
              (785,127
              )Common stock
      dividend payments
              
              
              (43,000
              )
              
              
              (67,000
              )Net cash
      provided from (used for) financing activities
              
              
              1,061,159
              
              
              
              (1,862,301
              )CASH
      FLOWS FROM INVESTING ACTIVITIES:Property
      additions
              
              
              (1,417,205
              )
              
              
              (482,907
              )Proceeds from
      asset sales
              
              
              15,218
              
              
              
              12,990Proceeds from
      sale and leaseback transaction
              
              
              -
              
              
              
              1,328,919Sales of
      investment securities held in trusts
              
              
              596,291
              
              
              
              521,535Purchases of
      investment securities held in trusts
              
              
              (624,899
              )
              
              
              (552,779
              )Loan
      repayments from (loans to) associated companies, net
              
              
              (64,142
              )
              
              
              510,307Restricted
      funds for debt redemption
              
              
              (81,640
              )
              
              
              -Other
              
              
              (38,915
              )
              
              
              2,209Net cash
      provided from (used for) investing activities
              
              
              (1,615,292
              )
              
              
              1,340,274Net change in
      cash and cash equivalents
              
              
              -
              
              
              
              -Cash and cash
      equivalents at beginning of period
              
              
              2
              
              
              
              2Cash and cash
      equivalents at end of period
              
              $
              2
              
              
              $
              2The
      accompanying Notes to Consolidated Financial Statements as they related to
      FirstEnergy Solutions Corp. arean integral
      part of these balance sheets.





58










OHIO
EDISON COMPANY





MANAGEMENT’S
NARRATIVE


ANALYSIS
OF RESULTS OF OPERATIONS








OE is a wholly owned
electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary,
Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated
electric distribution services. They provide generation services to those
customers electing to retain OE and Penn as their power supplier. OE’s power
supply requirements are provided by FES – an affiliated company. Penn
purchases power from FES and third-party suppliers through a competitive RFP
process.





Results of
Operations





In the first
nine months of 2008, net income increased to $165
million from $148 million in the same period of 2007.  The
increase primarily resulted from higher electric sales revenues and
lower purchased power costs, partially offset by a
decrease in the deferral of new regulatory assets
and lower investment income.





Revenues





Revenues
increased by $73 million, or 3.9%, in the first nine months
of 2008 compared with the same period in 2007, primarily due to increases in
retail generation revenues ($51 million) and distribution throughput
revenues ($16 million).





Retail generation
revenues increased primarily due to higher average prices across all customer
classes, partially offset by decreased KWH sales in all sectors. The higher
average prices included the 2008 fuel cost recovery rider that became effective
January 16, 2008 (see Regulatory Matters). Milder weather in the first nine
months of 2008 primarily caused the lower KWH sales (cooling degree days
decreased in OE’s and Penn’s service territories by 23.3% and 21.5%,
respectively, from the same period in 2007). Commercial and industrial
retail KWH sales were also impacted by increased customer shopping in Penn’s
service territory in the first nine months of 2008.





Changes in retail
generation sales and revenues in the first nine months of 2008 from the same
period in 2007 are summarized in the following tables:





Retail
      Generation KWH Sales
            
            DecreaseResidential
            
            
            (2.3)
            %Commercial
            
            
            (2.1)
            %Industrial
            
            
            (4.4)
            %Decrease
      in Generation Sales
            
            
            (2.9)
            %





Retail
      Generation Revenues
            
            Increase(In
      millions)Residential
            
            $
            23Commercial
            
            
            11Industrial
            
            
            17Increase
      in Generation Revenues
            
            $
            51








Revenues from
distribution throughput increased by $16 million in the first nine
months of 2008 compared to the same period in 2007 due to higher average unit
prices for all customer classes, partially offset by lower KWH deliveries in all
sectors. The higher average prices resulted from Ohio transmission rider
increases that became effective July 1, 2007 and July 1, 2008. The
lower KWH deliveries to residential and commercial customers reflected the
milder weather conditions described above.





Changes in
distribution KWH deliveries and revenues in the first nine months of 2008 from
the same period in 2007 are summarized in the following tables.





59








Distribution
      KWH Deliveries
            
            
            DecreaseResidential
            
            
            (1.8)
            %Commercial
            
            
            (0.8)
            %Industrial
            
            
            (2.2)
            %Decrease
      in Distribution Deliveries
            
            
            (1.7)
            %





Distribution
      Revenues
            
            Increase(In
      millions)Residential
            
            $
            3Commercial
            
            
            7Industrial
            
            
            6Increase
      in Distribution Revenues
            
            $
            16





Expenses





Total expenses
increased by $38 million in the first nine months of 2008 from the
same period of 2007. The following table presents changes from the prior year by
expense category.





Expenses
      – Changes
            
            Increase
      (Decrease)(In
      millions)Purchased
      power costs
            
            $
            (40
            )Other
      operating costs
            
            
            (1
            )Provision for
      depreciation
            
            
            1Amortization
      of regulatory assets
            
            
            9Deferral of
      new regulatory assets
            
            
            66General
      taxes
            
            
            3Net
      Increase in Expenses
            
            $
            38





Lower purchased
power costs in the first nine months of 2008 primarily reflected the lower
retail generation KWH sales, reducing the purchase volumes required. Higher
amortization of regulatory assets in the first nine months of 2008 was primarily
due to increased amortization of MISO transmission cost deferrals. The decrease
in the deferral of new regulatory assets for the first nine months of 2008 was
primarily due to lower MISO cost deferrals ($26 million) and lower RCP fuel
deferrals ($36 million), as more transmission and generation costs were
recovered from customers through PUCO-approved riders. The increase in general
taxes for the first nine months of 2008 was primarily due to higher property
taxes.





Other Income





Other income decreased $20
million in the first nine months of 2008 as compared with the
same period of 2007 primarily due to reductions in interest income on notes
receivable from associated companies resulting from principal payments since the
third quarter of 2007.





Legal
Proceedings





See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of other legal proceedings applicable to OE.





New Accounting Standards and
Interpretations





See the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to OE.








60











Report
of Independent Registered Public Accounting Firm


























To the Stockholder
and Board of


Directors of Ohio
Edison Company:





We have reviewed the
accompanying consolidated balance sheet of Ohio Edison Company and its
subsidiaries as of September 30, 2008 and the related consolidated
statements of income and comprehensive income for each of the three-month and
nine-month periods ended September 30, 2008 and 2007 and the consolidated
statement of cash flows for the nine-month periods ended September 30, 2008 and
2007. These interim financial statements are the responsibility of the Company’s
management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2007, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 28, 2008, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying consolidated balance
sheet information as of December 31, 2007, is fairly stated in all material
respects in relation to the consolidated balance sheet from which it has been
derived.




PricewaterhouseCoopers
      LLP
              Cleveland,
      Ohio
              November 6,
      2008








61







OHIO
      EDISON COMPANYCONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE INCOME(Unaudited)Three
      Months
              
              
              Nine
      MonthsEnded September 30
              
              
              Ended September 302008
              
              
              2007
              
              
              2008
              
              
              2007(In
      thousands)REVENUES:Electric
      sales
              
              $
              671,761
              
              
              $
              638,336
              
              
              $
              1,877,300
              
              
              $
              1,802,110Excise tax
      collections
              
              
              30,500
              
              
              
              30,472
              
              
              
              87,165
              
              
              
              89,077Total
      revenues
              
              
              702,261
              
              
              
              668,808
              
              
              
              1,964,465
              
              
              
              1,891,187EXPENSES:Purchased
      power
              
              
              349,374
              
              
              
              364,709
              
              
              
              997,609
              
              
              
              1,037,200Other
      operating costs
              
              
              146,048
              
              
              
              144,869
              
              
              
              423,993
              
              
              
              424,970Provision for
      depreciation
              
              
              14,997
              
              
              
              19,482
              
              
              
              57,904
              
              
              
              57,440Amortization
      of regulatory assets
              
              
              57,660
              
              
              
              53,026
              
              
              
              154,054
              
              
              
              144,569Deferral of
      new regulatory assets
              
              
              (15,078
              )
              
              
              (41,417
              )
              
              
              (66,390
              )
              
              
              (132,410
              )General
      taxes
              
              
              49,255
              
              
              
              46,158
              
              
              
              144,097
              
              
              
              141,296Total
      expenses
              
              
              602,256
              
              
              
              586,827
              
              
              
              1,711,267
              
              
              
              1,673,065OPERATING
      INCOME
              
              
              100,005
              
              
              
              81,981
              
              
              
              253,198
              
              
              
              218,122OTHER
      INCOME (EXPENSE):Investment
      income
              
              
              19,323
              
              
              
              19,827
              
              
              
              45,866
              
              
              
              67,803Miscellaneous
      income (expense)
              
              
              (1,089
              )
              
              
              670
              
              
              
              (5,180
              )
              
              
              3,362Interest
      expense
              
              
              (17,309
              )
              
              
              (20,311
              )
              
              
              (51,851
              )
              
              
              (62,749
              )Capitalized
      interest
              
              
              55
              
              
              
              136
              
              
              
              324
              
              
              
              398Total other
      income (expense)
              
              
              980
              
              
              
              322
              
              
              
              (10,841
              )
              
              
              8,814INCOME
      BEFORE INCOME TAXES
              
              
              100,985
              
              
              
              82,303
              
              
              
              242,357
              
              
              
              226,936INCOME
      TAXES
              
              
              28,501
              
              
              
              34,089
              
              
              
              77,122
              
              
              
              79,074NET
      INCOME
              
              
              72,484
              
              
              
              48,214
              
              
              
              165,235
              
              
              
              147,862OTHER
      COMPREHENSIVE INCOME (LOSS):Pension and
      other postretirment benefits
              
              
              (3,994
              )
              
              
              (3,423
              )
              
              
              (11,982
              )
              
              
              (10,270
              )Change in
      unrealized gain on available-for-sale securities
              
              
              (9,936
              )
              
              
              2,442
              
              
              
              (20,310
              )
              
              
              7,415Other
      comprehensive loss
              
              
              (13,930
              )
              
              
              (981
              )
              
              
              (32,292
              )
              
              
              (2,855
              )Income tax
      benefit related to other comprehensive loss
              
              
              (5,105
              )
              
              
              (573
              )
              
              
              (11,931
              )
              
              
              (1,688
              )Other
      comprehensive loss, net of tax
              
              
              (8,825
              )
              
              
              (408
              )
              
              
              (20,361
              )
              
              
              (1,167
              )TOTAL
      COMPREHENSIVE INCOME
              
              $
              63,659
              
              
              $
              47,806
              
              
              $
              144,874
              
              
              $
              146,695The
      accompanying Notes to Consolidated Financial Statements as they relate to
      Ohio Edison Company are an integral part ofthese
      statements.
  62
   OHIO
      EDISON COMPANYCONSOLIDATED
      BALANCE SHEETS(Unaudited)September 30,
              
              
              December 31,2008
              
              
              2007(In
      thousands)ASSETSCURRENT
      ASSETS:Cash and cash
      equivalents
              
              $
              715
              
              
              $
              732Receivables-Customers
      (less accumulated provisions of $6,888,000 and 8,032,000,respectively,
      for uncollectible accounts)
              
              
              268,252
              
              
              
              248,990Associated
      companies
              
              
              205,776
              
              
              
              185,437Other (less
      accumulated provisions of $13,000 and $5,639,000respectively,
      for uncollectible accounts)
              
              
              16,731
              
              
              
              12,395Notes
      receivable from associated companies
              
              
              362,695
              
              
              
              595,859Prepayments
      and other
              
              
              11,285
              
              
              
              10,341865,454
              
              
              
              1,053,754UTILITY
      PLANT:In
      service
              
              
              2,854,174
              
              
              
              2,769,880Less -
      Accumulated provision for depreciation
              
              
              1,101,572
              
              
              
              1,090,8621,752,602
              
              
              
              1,679,018Construction
      work in progress
              
              
              41,880
              
              
              
              50,0611,794,482
              
              
              
              1,729,079OTHER
      PROPERTY AND INVESTMENTS:Long-term
      notes receivable from associated companies
              
              
              257,457
              
              
              
              258,870Investment in
      lease obligation bonds
              
              
              248,751
              
              
              
              253,894Nuclear plant
      decommissioning trusts
              
              
              115,523
              
              
              
              127,252Other
              
              
              31,441
              
              
              
              36,037653,172
              
              
              
              676,053DEFERRED
      CHARGES AND OTHER ASSETS:Regulatory
      assets
              
              
              621,192
              
              
              
              737,326Pension
      assets
              
              
              250,762
              
              
              
              228,518Property
      taxes
              
              
              65,520
              
              
              
              65,520Unamortized
      sale and leaseback costs
              
              
              41,381
              
              
              
              45,133Other
              
              
              33,820
              
              
              
              48,0751,012,675
              
              
              
              1,124,572$
              4,325,783
              
              
              $
              4,583,458LIABILITIES
      AND CAPITALIZATIONCURRENT
      LIABILITIES:Currently
      payable long-term debt
              
              $
              159,662
              
              
              $
              333,224Short-term
      borrowings-Associated
      companies
              
              
              -
              
              
              
              50,692Other
              
              
              242,449
              
              
              
              2,609Accounts
      payable-Associated
      companies
              
              
              95,604
              
              
              
              174,088Other
              
              
              20,902
              
              
              
              19,881Accrued
      taxes
              
              
              58,800
              
              
              
              89,571Accrued
      interest
              
              
              14,216
              
              
              
              22,378Other
              
              
              123,177
              
              
              
              65,163714,810
              
              
              
              757,606CAPITALIZATION:Common
      stockholder's equity-Common stock,
      without par value, authorized 175,000,000 shares -60 shares
      outstanding
              
              
              1,224,039
              
              
              
              1,220,512Accumulated
      other comprehensive income
              
              
              28,025
              
              
              
              48,386Retained
      earnings
              
              
              207,512
              
              
              
              307,277Total common
      stockholder's equity
              
              
              1,459,576
              
              
              
              1,576,175Long-term debt
      and other long-term obligations
              
              
              841,871
              
              
              
              840,5912,301,447
              
              
              
              2,416,766NONCURRENT
      LIABILITIES:Accumulated
      deferred income taxes
              
              
              776,042
              
              
              
              781,012Accumulated
      deferred investment tax credits
              
              
              14,040
              
              
              
              16,964Asset
      retirement obligations
              
              
              79,372
              
              
              
              93,571Retirement
      benefits
              
              
              173,297
              
              
              
              178,343Deferred
      revenues - electric service programs
              
              
              14,954
              
              
              
              46,849Other
              
              
              251,821
              
              
              
              292,3471,309,526
              
              
              
              1,409,086COMMITMENTS
      AND CONTINGENCIES (Note 11)$
              4,325,783
              
              
              $
              4,583,458The
      accompanying Notes to Consolidated Financial Statements as they relate to
      Ohio Edison Company are an integralpart of these
      balance sheets.
  63
   OHIO
      EDISON COMPANYCONSOLIDATED
      STATEMENTS OF CASH FLOWS(Unaudited)Nine
      MonthsEnded
      September 302008
              
              
              2007(In
      thousands)CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      income
              
              $
              165,235
              
              
              $
              147,862Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
              
              
              57,904
              
              
              
              57,440Amortization
      of regulatory assets
              
              
              154,054
              
              
              
              144,569Deferral of
      new regulatory assets
              
              
              (66,390
              )
              
              
              (132,410
              )Amortization
      of lease costs
              
              
              28,535
              
              
              
              28,567Deferred
      income taxes and investment tax credits, net
              
              
              17,267
              
              
              
              (29,155
              )Accrued
      compensation and retirement benefits
              
              
              (41,190
              )
              
              
              (34,572
              )Pension trust
      contribution
              
              
              -
              
              
              
              (20,261
              )Decrease
      (increase) in operating assets-Receivables
              
              
              (26,009
              )
              
              
              (70,098
              )Prepayments
      and other current assets
              
              
              2,065
              
              
              
              (3,542
              )Increase
      (decrease) in operating liabilities-Accounts
      payable
              
              
              (77,463
              )
              
              
              89,550Accrued
      taxes
              
              
              (27,776
              )
              
              
              (25,734
              )Accrued
      interest
              
              
              (8,162
              )
              
              
              (7,277
              )Electric
      service prepayment programs
              
              
              (31,895
              )
              
              
              (27,455
              )Other
              
              
              (1,283
              )
              
              
              9,868Net cash
      provided from operating activities
              
              
              144,892
              
              
              
              127,352CASH
      FLOWS FROM FINANCING ACTIVITIES:New
      Financing-Short-term
      borrowings, net
              
              
              189,148
              
              
              
              -Redemptions
      and Repayments-Common
      stock
              
              
              -
              
              
              
              (500,000
              )Long-term
      debt
              
              
              (175,588
              )
              
              
              (1,190
              )Short-term
      borrowings, net
              
              
              -
              
              
              
              (64,475
              )Dividend
      Payments-Common
      stock
              
              
              (265,000
              )
              
              
              (150,000
              )Net cash used
      for financing activities
              
              
              (251,440
              )
              
              
              (715,665
              )CASH
      FLOWS FROM INVESTING ACTIVITIES:Property
      additions
              
              
              (135,450
              )
              
              
              (109,461
              )Sales of
      investment securities held in trusts
              
              
              115,988
              
              
              
              31,624Purchases of
      investment securities held in trusts
              
              
              (121,871
              )
              
              
              (36,194
              )Loan
      repayments from associated companies, net
              
              
              234,577
              
              
              
              685,364Cash
      investments
              
              
              5,143
              
              
              
              17,316Other
              
              
              8,144
              
              
              
              (321
              )Net cash
      provided from investing activities
              
              
              106,531
              
              
              
              588,328Net increase
      (decrease) in cash and cash equivalents
              
              
              (17
              )
              
              
              15Cash and cash
      equivalents at beginning of period
              
              
              732
              
              
              
              712Cash and cash
      equivalents at end of period
              
              $
              715
              
              
              $
              727The
      accompanying Notes to Consolidated Financial Statements as they relate to
      Ohio Edison Company are anintegral part
      of these statements.





64










THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY





MANAGEMENT’S
NARRATIVE


ANALYSIS
OF RESULTS OF OPERATIONS








CEI is a wholly
owned, electric utility subsidiary of FirstEnergy. CEI conducts business in
northeastern Ohio, providing regulated electric distribution services. CEI also
provides generation services to those customers electing to retain CEI as their
power supplier. CEI’s power supply requirements are primarily provided by FES –
an affiliated company.





Results
of Operations





Net income in the
first nine months of 2008 increased to $218 million from $211 million
in the same period of 2007. The increase resulted primarily from the elimination
of fuel costs and lower other operating costs (due to the assignment of
leasehold interests in generating assets to FGCO), partially offset by lower
revenues and regulatory asset deferrals and higher purchased power costs and
regulatory asset amortization.





Revenues





Revenues decreased
by $24 million, or 1.7%, in the first nine months of 2008 compared to the
same period of 2007, primarily due to a decrease in wholesale generation
revenues ($89million), partially
offset by increases in retail generation revenues ($50 million),
distribution revenues ($8 million), and transmission revenues ($11
million).





Wholesale generation
revenues decreased due to the assignment of CEI’s leasehold interests in the
Bruce Mansfield Plant to FGCO in October 2007. Prior to the assignment, CEI
sold power from its interests in the plant to FGCO.





Retail generation
revenues increased in the first nine months of 2008 due to higher average unit
prices across all customer classes, partially offset by a slight decrease in
sales volume in all sectors compared to the same period of 2007. The higher
average unit prices were driven by the 2008 fuel cost recovery rider that became
effective January 16, 2008 (see Regulatory Matters). Milder weather in the
first nine months of 2008, compared to the same period of 2007, primarily caused
the decrease in sales volume (heating and cooling degree days decreased 1% and
7%, respectively).





Changes in retail
generation sales and revenues in the first nine months of 2008 compared to the
same period in 2007 are summarized in the following tables:





Retail
      Generation KWH Sales
            
            DecreaseResidential
            
            
            (1.2
            )%Commercial
            
            
            (1.1
            )%Industrial
            
            
            (1.1
            )%Decrease
      in Retail Generation Sales
            
            
            (1.1
            )%





Retail
      Generation Revenues
            
            Increase(In
      millions)Residential
            
            $
            17Commercial
            
            
            12Industrial
            
            
            21Increase
      in Generation Revenues
            
            $
            50





Revenues from
distribution throughput increased by $8 million in the first nine months of
2008 compared to the same period of 2007 primarily due to higher average unit
prices for all customer classes, partially offset by a slight decrease in KWH
deliveries in all sectors. The higher average unit prices resulted from
transmission rider increases that became effective July 1, 2007 and
July 1, 2008. The lower KWH deliveries in the first nine months of 2008
reflected the weather impacts described above.





Changes in
distribution KWH deliveries and revenues in the first nine months of 2008
compared to the same period of 2007 are summarized in the following
tables.





Distribution
      KWH Deliveries
            
            DecreaseResidential
            
            
            (1.5
            )%Commercial
            
            
            (1.4
            )%Industrial
            
            
            (1.0
            )%Decrease
      in Distribution Deliveries
            
            
            (1.2
            )%





65








Distribution
      Revenues
            
            Increase(In
      millions)Residential
            
            $
            -Commercial
            
            
            2Industrial
            
            
            6Increase
      in Distribution Revenues
            
            $
            8





Transmission
revenues were higher in the first nine months of 2008, compared to the same
period of 2007, due to increased auction revenue rights for transmission service
in MISO. CEI defers the difference between revenue from its transmission rider
and net transmission costs incurred in MISO, resulting in no material effect to
current period earnings.





Expenses





Total expenses
decreased by $19 million in the first nine months of 2008 compared to the
same period of 2007. The following table presents the change from the prior year
by expense category:





Expenses  -
      Changes
            
            Increase
              (Decrease)(In
      millions)Fuel
      costs
            
            $
            (40
            )Purchased
      power costs
            
            
            15Other
      operating costs
            
            
            (49
            )Provision for
      depreciation
            
            
            (1
            )Amortization
      of regulatory assets
            
            
            15Deferral of
      new regulatory assets
            
            
            43General
      taxes
            
            
            (2
            )Net
      Decrease in Expenses
            
            $
            (19
            )





The absence of fuel
costs in the first nine months of 2008 was due to the assignment of CEI’s
leasehold interests in the Mansfield Plant to FGCO in October 2007. Prior
to the assignment, CEI incurred fuel expenses and other operating costs related
to its leasehold interest in the plant. Higher purchased power costs reflected
higher unit prices, as provided for under the PSA with FES, partially offset by
a decrease in volume due to lower KWH sales. Other operating costs were lower
primarily due to the assignment of CEI’s leasehold interests in the Mansfield
plant as described above, partially offset by higher labor costs resulting from
storm restoration work performed during the first nine months of 2008. Higher
amortization of regulatory assets was primarily due to increased transition cost
amortization ($11 million) under the effective interest methodology and
increased amortization of MISO transmission cost deferrals ($4 million). The
decrease in the deferral of new regulatory assets was primarily due to lower
MISO cost deferrals ($19 million) and RCP fuel costs ($25 million), as more
transmission and generation costs were recovered from customers through
PUCO-approved riders. General taxes decreased primarily due to a $3 million
decrease in general tax reserves, partially offset by $1 million increase in
commercial activity taxes.





Other Expense





Other expense
increased by $13 million in the first nine months of 2008 compared to the
same period of 2007 primarily due to lower investment income and miscellaneous
income, partially offset by a reduction in interest expense. Lower investment
income is primarily the result of principal repayments during 2007 on notes
receivable from associated companies. The lower interest expense is primarily
due to $489 million in long-term debt redemptions during 2007, partially offset
by a new debt issuance of $250 million in March 2007. Miscellaneous income
decreased primarily due to reduced life insurance investment
values.





Legal
Proceedings





See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to CEI.





New Accounting Standards and
Interpretations





See the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to CEI.








66











Report
of Independent Registered Public Accounting Firm


























To the Stockholder
and Board of Directors of


The Cleveland
Electric Illuminating Company:





We have reviewed the
accompanying consolidated balance sheet of The Cleveland Electric Illuminating
Company and its subsidiaries as of September 30, 2008 and the related
consolidated statements of income and comprehensive income for each of the
three-month and nine-month periods ended September 30, 2008 and 2007 and the
consolidated statement of cash flows for the nine-month periods ended September
30, 2008 and 2007. These interim financial statements are the responsibility of
the Company’s management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2007, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 28, 2008, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying consolidated balance
sheet information as of December 31, 2007, is fairly stated in all material
respects in relation to the consolidated balance sheet from which it has been
derived.




PricewaterhouseCoopers
      LLP
              Cleveland,
      Ohio
              November 6,
      2008











67








THE
      CLEVELAND ELECTRIC ILLUMINATING COMPANYCONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE INCOME(Unaudited)Three
      Months
            
            
            Nine
      MonthsEnded
      September 30
            
            
            Ended
      Septmeber 302008
            
            
            2007
            
            
            2008
            
            
            2007(In
      thousands)REVENUES:Electric
      sales
            
            $
            505,425
            
            
            $
            510,577
            
            
            $
            1,342,327
            
            
            $
            1,366,396Excise tax
      collections
            
            
            18,652
            
            
            
            18,514
            
            
            
            53,447
            
            
            
            53,009Total
      revenues
            
            
            524,077
            
            
            
            529,091
            
            
            
            1,395,774
            
            
            
            1,419,405EXPENSES:Fuel
            
            
            -
            
            
            
            12,160
            
            
            
            -
            
            
            
            39,683Purchased
      power
            
            
            211,445
            
            
            
            216,194
            
            
            
            590,300
            
            
            
            575,520Other
      operating costs
            
            
            66,342
            
            
            
            85,114
            
            
            
            194,119
            
            
            
            243,140Provision for
      depreciation
            
            
            17,677
            
            
            
            18,913
            
            
            
            54,497
            
            
            
            56,094Amortization
      of regulatory assets
            
            
            48,155
            
            
            
            42,077
            
            
            
            124,936
            
            
            
            110,253Deferral of
      new regulatory assets
            
            
            (16,176
            )
            
            
            (37,692
            )
            
            
            (71,443
            )
            
            
            (114,708
            )General
      taxes
            
            
            36,722
            
            
            
            37,930
            
            
            
            109,230
            
            
            
            110,922Total
      expenses
            
            
            364,165
            
            
            
            374,696
            
            
            
            1,001,639
            
            
            
            1,020,904OPERATING
      INCOME
            
            
            159,912
            
            
            
            154,395
            
            
            
            394,135
            
            
            
            398,501OTHER
      INCOME (EXPENSE):Investment
      income
            
            
            8,390
            
            
            
            13,805
            
            
            
            25,972
            
            
            
            47,816Miscellaneous
      income (expense)
            
            
            (1,114
            )
            
            
            (760
            )
            
            
            (1,319
            )
            
            
            3,197Interest
      expense
            
            
            (31,024
            )
            
            
            (34,423
            )
            
            
            (94,479
            )
            
            
            (107,430
            )Capitalized
      interest
            
            
            200
            
            
            
            309
            
            
            
            584
            
            
            
            655Total other
      expense
            
            
            (23,548
            )
            
            
            (21,069
            )
            
            
            (69,242
            )
            
            
            (55,762
            )INCOME
      BEFORE INCOME TAXES
            
            
            136,364
            
            
            
            133,326
            
            
            
            324,893
            
            
            
            342,739INCOME
      TAXES
            
            
            42,977
            
            
            
            54,610
            
            
            
            107,082
            
            
            
            131,525NET
      INCOME
            
            
            93,387
            
            
            
            78,716
            
            
            
            217,811
            
            
            
            211,214OTHER
      COMPREHENSIVE INCOME (LOSS):Pension and
      other postretirement benefits
            
            
            (213
            )
            
            
            1,202
            
            
            
            (639
            )
            
            
            3,607Income tax
      expense (benefit) related to other comprehensive income
            
            
            (130
            )
            
            
            356
            
            
            
            (239
            )
            
            
            1,068Other
      comprehensive income (loss), net of tax
            
            
            (83
            )
            
            
            846
            
            
            
            (400
            )
            
            
            2,539TOTAL
      COMPREHENSIVE INCOME
            
            $
            93,304
            
            
            $
            79,562
            
            
            $
            217,411
            
            
            $
            213,753The
      accompanying Notes to Consolidated Financial Statements as they relate to
      The Cleveland Electric Illuminating Company are an
integralpart of these
      statements.






68







THE
      CLEVELAND ELECTRIC ILLUMINATING COMPANYCONSOLIDATED
      BALANCE SHEETS(Unaudited)September
      30,
            
            
            December
      31,2008
            
            
            2007(In
      thousands)ASSETSCURRENT
      ASSETS:Cash and cash
      equivalents
            
            $
            237
            
            
            $
            232Receivables-Customers
      (less accumulated provisions of $6,907,000 and $7,540,000respectively,
      for uncollectible accounts)
            
            
            292,735
            
            
            
            251,000Associated
      companies
            
            
            122,210
            
            
            
            166,587Other
            
            
            4,151
            
            
            
            12,184Notes
      receivable from associated companies
            
            
            21,682
            
            
            
            52,306Prepayments
      and other
            
            
            2,373
            
            
            
            2,327443,388
            
            
            
            484,636UTILITY
      PLANT:In
      service
            
            
            2,180,347
            
            
            
            2,256,956Less -
      Accumulated provision for depreciation
            
            
            836,058
            
            
            
            872,8011,344,289
            
            
            
            1,384,155Construction
      work in progress
            
            
            44,392
            
            
            
            41,1631,388,681
            
            
            
            1,425,318OTHER
      PROPERTY AND INVESTMENTS:Investment in
      lessor notes
            
            
            425,717
            
            
            
            463,431Other
            
            
            10,260
            
            
            
            10,285435,977
            
            
            
            473,716DEFERRED
      CHARGES AND OTHER ASSETS:Goodwill
            
            
            1,688,521
            
            
            
            1,688,521Regulatory
      assets
            
            
            796,475
            
            
            
            870,695Pension
      assets
            
            
            68,548
            
            
            
            62,471Property
      taxes
            
            
            76,000
            
            
            
            76,000Other
            
            
            9,036
            
            
            
            32,9872,638,580
            
            
            
            2,730,674$
            4,906,626
            
            
            $
            5,114,344LIABILITIES
      AND CAPITALIZATIONCURRENT
      LIABILITIES:Currently
      payable long-term debt
            
            $
            207,312
            
            
            $
            207,266Short-term
      borrowings-Associated
      companies
            
            
            367,422
            
            
            
            531,943Accounts
      payable-Associated
      companies
            
            
            124,335
            
            
            
            169,187Other
            
            
            5,704
            
            
            
            5,295Accrued
      taxes
            
            
            70,515
            
            
            
            94,991Accrued
      interest
            
            
            37,885
            
            
            
            13,895Other
            
            
            41,366
            
            
            
            34,350854,539
            
            
            
            1,056,927CAPITALIZATION:Common
      stockholder's equity-Common stock,
      without par value, authorized 105,000,000 shares -67,930,743
      shares outstanding
            
            
            878,199
            
            
            
            873,536Accumulated
      other comprehensive loss
            
            
            (69,529
            )
            
            
            (69,129
            )Retained
      earnings
            
            
            793,238
            
            
            
            685,428Total common
      stockholder's equity
            
            
            1,601,908
            
            
            
            1,489,835Long-term debt
      and other long-term obligations
            
            
            1,447,718
            
            
            
            1,459,9393,049,626
            
            
            
            2,949,774NONCURRENT
      LIABILITIES:Accumulated
      deferred income taxes
            
            
            727,615
            
            
            
            725,523Accumulated
      deferred investment tax credits
            
            
            13,442
            
            
            
            18,567Retirement
      benefits
            
            
            95,931
            
            
            
            93,456Deferred
      revenues - electric service programs
            
            
            9,594
            
            
            
            27,145Lease
      assignment payable to associated companies
            
            
            40,827
            
            
            
            131,773Other
            
            
            115,052
            
            
            
            111,1791,002,461
            
            
            
            1,107,643COMMITMENTS
      AND CONTINGENCIES (Note 11)$
            4,906,626
            
            
            $
            5,114,344The
      accompanying Notes to Consolidated Financial Statements as they relate to
      The Cleveland Electric IlluminatingCompany are an
      integral part of these balance sheets.





69








THE
      CLEVELAND ELECTRIC ILLUMINATING COMPANYCONSOLIDATED
      STATEMENTS OF CASH FLOWS(Unaudited)Nine
      MonthsEnded
      September 302008
            
            
            2007(In
      thousands)CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      income
            
            $
            217,811
            
            
            $
            211,214Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
            
            
            54,497
            
            
            
            56,094Amortization
      of regulatory assets
            
            
            124,936
            
            
            
            110,253Deferral of
      new regulatory assets
            
            
            (71,443
            )
            
            
            (114,708
            )Deferred rents
      and lease market valuation liability
            
            
            -
            
            
            
            (46,327
            )Deferred
      income taxes and investment tax credits, net
            
            
            4,623
            
            
            
            (40,964
            )Accrued
      compensation and retirement benefits
            
            
            (3,291
            )
            
            
            2,575Pension trust
      contribution
            
            
            -
            
            
            
            (24,800
            )Decrease
      (increase) in operating assets-Receivables
            
            
            43,927
            
            
            
            140,359Prepayments
      and other current assets
            
            
            (37
            )
            
            
            661Increase
      (decrease) in operating liabilities-Accounts
      payable
            
            
            (44,443
            )
            
            
            (143,210
            )Accrued
      taxes
            
            
            (19,613
            )
            
            
            17,301Accrued
      interest
            
            
            23,990
            
            
            
            22,360Electric
      service prepayment programs
            
            
            (17,551
            )
            
            
            (16,819
            )Other
            
            
            4,193
            
            
            
            2,996Net cash
      provided from operating activities
            
            
            317,599
            
            
            
            176,985CASH
      FLOWS FROM FINANCING ACTIVITIES:New
      Financing-Long-term
      debt
            
            
            -
            
            
            
            247,424Redemptions
      and Repayments-Long-term
      debt
            
            
            (508
            )
            
            
            (223,555
            )Short-term
      borrowings, net
            
            
            (176,354
            )
            
            
            (59,328
            )Dividend
      Payments-Common
      stock
            
            
            (110,000
            )
            
            
            (304,000
            )Net cash used
      for financing activities
            
            
            (286,862
            )
            
            
            (339,459
            )CASH
      FLOWS FROM INVESTING ACTIVITIES:Property
      additions
            
            
            (97,326
            )
            
            
            (100,583
            )Loan
      repayments from (loans to) associated companies, net
            
            
            30,624
            
            
            
            (13,863
            )Collection of
      principal on long-term notes receivable
            
            
            -
            
            
            
            220,974Redemption of
      lessor notes
            
            
            37,714
            
            
            
            56,177Other
            
            
            (1,744
            )
            
            
            (218
            )Net cash
      provided from (used for) investing activities
            
            
            (30,732
            )
            
            
            162,487Net increase
      in cash and cash equivalents
            
            
            5
            
            
            
            13Cash and cash
      equivalents at beginning of period
            
            
            232
            
            
            
            221Cash and cash
      equivalents at end of period
            
            $
            237
            
            
            $
            234The
      accompanying Notes to Consolidated Financial Statements as they relate to
      The Cleveland Electric IlluminatingCompany are an
      integral part of these statements.









70








THE
TOLEDO EDISON COMPANY





MANAGEMENT’S
NARRATIVE


ANALYSIS
OF RESULTS OF OPERATIONS








TE is a wholly owned
electric utility subsidiary of FirstEnergy. TE conducts business in northwestern
Ohio, providing regulated electric distribution services. TE also provides
generation services to those customers electing to retain TE as their power
supplier. TE’s power supply requirements are provided by FES – an affiliated
company.





Results of
Operations





Net income in the
first nine months of 2008 decreased to $70million from $73million in the same
period of 2007. The decrease resulted primarily from lower electric sales
revenues, higher purchased power costs and a decrease in the deferral of new
regulatory assets, partially offset by lower other operating costs.





Revenues





Revenues decreased
$66million, or
8.8%, in the first nine months of 2008, compared to the same period of 2007, due
to lower wholesale generation revenues ($114 million), partially offset by
increased retail generation revenues ($37million), distribution
revenues ($5million) and
transmission revenues ($6 million).





The decrease in
wholesale revenues was primarily due to lower associated company sales of KWH
from TE’s leasehold interests in generating plants. Revenues from TE’s leasehold
interests in Beaver Valley Unit 2 decreased by $50 million due to the unit’s
39-day refueling outage in the second quarter of 2008 and the incremental
pricing impacts related to the termination of TE’s sale agreement with CEI. At
the end of 2007, TE terminated its Beaver Valley Unit 2 output sale
agreement with CEI and is currently selling the 158 MW entitlement from its
18.26% leasehold interest in the unit to NGC. Revenues from PSA sales decreased
by $67 million in the first nine months of 2008 due to the assignment of TE’s
leasehold interests in the Bruce Mansfield Plant to FGCO in October 2007. Prior
to the assignment, TE sold power from its interests in the plant to
FGCO.





Retail generation
revenues increased in the first nine months of 2008 due to higher average prices
across all customer classes and increased KWH sales to commercial customers
compared to the same period of 2007. The higher average prices were driven by
the 2008 fuel cost recovery rider that became effective January 16, 2008
(see Regulatory Matters). Sales to residential customers decreased due to milder
weather in the first nine months of 2008 (cooling degree days decreased 15% from
the same period of 2007). The increase in sales to commercial customers was due
to less customer shopping; generation services provided by alternative suppliers
as a percentage of total sales delivered in TE’s franchise area decreased by
three percentage points. Industrial KWH sales decreased due in part to lower
sales to the automotive sector and a maintenance outage undertaken by a large
industrial customer during the first nine months of 2008.





Changes in retail
electric generation KWH sales and revenues in the first nine months of 2008 from
the same period of 2007 are summarized in the following tables.





IncreaseRetail
      Generation KWH Sales
            
            (Decrease)Residential
            
            
            (1.3
            )%Commercial
            
            
            4.9
            %Industrial
            
            
            (4.8
            )%Net
      Decrease in Retail Generation Sales
            
            
            (2.0
            )%





Retail
      Generation Revenues
            
            Increase(In
      millions)Residential
            
            $
            7Commercial
            
            
            11Industrial
            
            
            19Increase
      in Retail Generation Revenues
            
            $
            37








71





Revenues from
distribution throughput increased by $5 million in the first nine months of
2008 compared to the same period in 2007 due to higher average unit prices for
all customer classes, partially offset by lower KWH deliveries to all sectors.
The higher average prices resulted from PUCO-approved transmission rider
increases that became effective July 1, 2007 and July 1, 2008. The lower
KWH deliveries to residential and commercial customers in the first nine months
of 2008 reflected the weather impacts described above. As with the reduction in
generation sales, industrial KWH deliveries decreased in part due to lower sales
to the automotive sector and a maintenance outage undertaken by a large
industrial customer in 2008.








Changes in
distribution KWH deliveries and revenues in the first nine months of 2008 from
the same period of 2007 are summarized in the following tables.





Distribution
      KWH Deliveries
            
            DecreaseResidential
            
            
            (1.8
            )%Commercial
            
            
            (0.5
            )%Industrial
            
            
            (4.7
            )%Decrease
      in Distribution Deliveries
            
            
            (2.8
            )%





Distribution
      Revenues
            
            Increase(In
      millions)Residential
            
            $
            2Commercial
            
            
            2Industrial
            
            
            1Increase
      in Distribution Revenues
            
            $
            5





Expenses





Total expenses
decreased $40 million in the first nine months of 2008 from the same period
of 2007. The following table presents changes from the prior year by expense
category.





Expenses
      – Changes
            
            Increase
      (Decrease)(In
      millions)Purchased
      power costs
            
            $
            11Other
      operating costs
            
            
            (76
            )Provision for
      depreciation
            
            
            (3
            )Amortization
      of regulatory assets
            
            
            3Deferral of
      new regulatory assets
            
            
            23General
      taxes
            
            
            2Net
      Decrease in Expenses
            
            $
            (40
            )





Higher purchased
power costs primarily reflected higher unit prices as provided for under the PSA
with FES. Other operating costs decreased primarily due to the reversal of the
above-market lease liability ($23 million) associated with TE’s leasehold
interest in Beaver Valley Unit 2, as a result of the termination of the CEI sale
agreement described above, and lower fuel costs ($25 million) and other
operating costs ($28 million) due to the assignment of TE’s leasehold interests
in the Mansfield Plant in October 2007. These decreases were partially offset by
increased costs ($7 million) associated with TE’s leasehold interests in Beaver
Valley Unit 2, due to a refueling outage in the second quarter of 2008.
Depreciation expense decreased primarily due to the transfer of leasehold
improvements for the Mansfield Plant and Beaver Valley Unit 2 to FGCO and NGC,
respectively, during the first nine months of 2008.





The increase in the
amortization of regulatory assets was primarily due to increased amortization of
MISO transmission cost deferrals ($5 million), partially offset by lower
amortization of transition cost deferrals ($2 million) resulting from
reduced distribution deliveries. The change in the deferral of new regulatory
assets was primarily due to lower deferred fuel costs ($11 million) and
MISO transmission expenses ($7 million), as more generation and transmission
costs were recovered from customers through PUCO-approved riders, and lower RCP
distribution cost deferrals ($4 million). Higher general taxes primarily
reflected increased KWH taxes, property taxes and Ohio commercial activity
taxes.





Other Expense





Other expense
decreased $6 million in the first nine months of 2008, compared to the same
period of 2007, primarily due to lower interest expense, partially offset by
lower investment income. The lower interest expense resulted from lower money
pool borrowings from associated companies in the first nine months of 2008, and
the redemption of long-term debt ($55 million principal amount) since the
third quarter of 2007. The decrease in investment income resulted primarily from
principal repayments since the third quarter of 2007 on notes receivable from
associated companies and lower interest income from customer accounts receivable
financing activity.





72








Legal
Proceedings





See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to TE.





New Accounting Standards and
Interpretations





See the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to TE.










.


73










Report
of Independent Registered Public Accounting Firm


























To the Stockholder
and Board of


Directors of The
Toledo Edison Company:





We have reviewed the
accompanying consolidated balance sheet of The Toledo Edison Company and its
subsidiary as of September 30, 2008 and the related consolidated statements
of income and comprehensive income for each of the three-month and nine-month
periods ended September 30, 2008 and 2007 and the consolidated statement of cash
flows for the nine-month periods ended September 30, 2008 and 2007. These
interim financial statements are the responsibility of the Company’s
management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2007, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 28, 2008, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying consolidated balance
sheet information as of December 31, 2007, is fairly stated in all material
respects in relation to the consolidated balance sheet from which it has been
derived.




PricewaterhouseCoopers
      LLP
              Cleveland,
      Ohio
              November 6,
      2008











74


THE
      TOLEDO EDISON COMPANYCONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE INCOME(Unaudited)Three
      Months
              
              
              Nine
      MonthsEnded
      September 30
              
              
              Ended
      September 302008
              
              
              2007
              
              
              2008
              
              
              2007(In
      thousands)REVENUES:Electric
      sales
              
              $
              242,866
              
              
              $
              261,736
              
              
              $
              660,888
              
              
              $
              728,429Excise tax
      collections
              
              
              8,239
              
              
              
              7,926
              
              
              
              23,417
              
              
              
              22,026Total
      revenues
              
              
              251,105
              
              
              
              269,662
              
              
              
              684,305
              
              
              
              750,455EXPENSES:Purchased
      power
              
              
              111,809
              
              
              
              112,502
              
              
              
              315,957
              
              
              
              304,947Other
      operating costs
              
              
              47,010
              
              
              
              73,701
              
              
              
              143,144
              
              
              
              218,961Provision for
      depreciation
              
              
              7,682
              
              
              
              9,231
              
              
              
              24,648
              
              
              
              27,475Amortization
      of regulatory assets
              
              
              31,452
              
              
              
              30,460
              
              
              
              81,837
              
              
              
              79,284Deferral of
      new regulatory assets
              
              
              (5,574
              )
              
              
              (15,645
              )
              
              
              (23,997
              )
              
              
              (47,373
              )General
      taxes
              
              
              13,609
              
              
              
              11,912
              
              
              
              40,591
              
              
              
              38,646Total
      expenses
              
              
              205,988
              
              
              
              222,161
              
              
              
              582,180
              
              
              
              621,940OPERATING
      INCOME
              
              
              45,117
              
              
              
              47,501
              
              
              
              102,125
              
              
              
              128,515OTHER
      INCOME (EXPENSE):Investment
      income
              
              
              5,580
              
              
              
              6,721
              
              
              
              17,285
              
              
              
              21,255Miscellaneous
      expense
              
              
              (1,529
              )
              
              
              (2,153
              )
              
              
              (4,992
              )
              
              
              (7,309
              )Interest
      expense
              
              
              (5,832
              )
              
              
              (8,786
              )
              
              
              (17,445
              )
              
              
              (25,205
              )Capitalized
      interest
              
              
              19
              
              
              
              220
              
              
              
              144
              
              
              
              467Total other
      expense
              
              
              (1,762
              )
              
              
              (3,998
              )
              
              
              (5,008
              )
              
              
              (10,792
              )INCOME
      BEFORE INCOME TAXES
              
              
              43,355
              
              
              
              43,503
              
              
              
              97,117
              
              
              
              117,723INCOME
      TAXES
              
              
              12,174
              
              
              
              18,435
              
              
              
              27,614
              
              
              
              44,924NET
      INCOME
              
              
              31,181
              
              
              
              25,068
              
              
              
              69,503
              
              
              
              72,799OTHER
      COMPREHENSIVE INCOME (LOSS):Pension and
      other postretirement benefits
              
              
              (64
              )
              
              
              574
              
              
              
              (191
              )
              
              
              1,720Change in
      unrealized gain on available-for-sale-securities
              
              
              (247
              )
              
              
              1,946
              
              
              
              (767
              )
              
              
              1,656Other
      comprehensive income (loss)
              
              
              (311
              )
              
              
              2,520
              
              
              
              (958
              )
              
              
              3,376Income tax
      expense (benefit) related to othercomprehensive
      income
              
              
              (108
              )
              
              
              902
              
              
              
              (294
              )
              
              
              1,193Other
      comprehensive income (loss), net of tax
              
              
              (203
              )
              
              
              1,618
              
              
              
              (664
              )
              
              
              2,183TOTAL
      COMPREHENSIVE INCOME
              
              $
              30,978
              
              
              $
              26,686
              
              
              $
              68,839
              
              
              $
              74,982The
      accompanying Notes to Consolidated Financial Statements as they relate to
      The Toledo Edison Company are an integralpart of these
      statements.
  75
   THE
      TOLEDO EDISON COMPANYCONSOLIDATED
      BALANCE SHEETS(Unaudited)September 30,
              
              
              December 31,2008
              
              
              2007(In
      thousands)ASSETSCURRENT
      ASSETS:Cash and cash
      equivalents
              
              $
              24
              
              
              $
              22Receivables-Customers
              
              
              931
              
              
              
              449Associated
      companies
              
              
              58,215
              
              
              
              88,796Other (less
      accumulated provisions of $165,000 and $615,000,respectively,
      for uncollectible accounts)
              
              
              15,810
              
              
              
              3,116Notes
      receivable from associated companies
              
              
              111,519
              
              
              
              154,380Prepayments
      and other
              
              
              1,421
              
              
              
              865187,920
              
              
              
              247,628UTILITY
      PLANT:In
      service
              
              
              860,417
              
              
              
              931,263Less -
      Accumulated provision for depreciation
              
              
              402,952
              
              
              
              420,445457,465
              
              
              
              510,818Construction
      work in progress
              
              
              7,626
              
              
              
              19,740465,091
              
              
              
              530,558OTHER
      PROPERTY AND INVESTMENTS:Investment in
      lessor notes
              
              
              142,657
              
              
              
              154,646Long-term
      notes receivable from associated companies
              
              
              37,308
              
              
              
              37,530Nuclear plant
      decommissioning trusts
              
              
              68,438
              
              
              
              66,759Other
              
              
              1,691
              
              
              
              1,756250,094
              
              
              
              260,691DEFERRED
      CHARGES AND OTHER ASSETS:Goodwill
              
              
              500,576
              
              
              
              500,576Regulatory
      assets
              
              
              145,404
              
              
              
              203,719Pension
      assets
              
              
              31,059
              
              
              
              28,601Property
      taxes
              
              
              21,010
              
              
              
              21,010Other
              
              
              52,325
              
              
              
              20,496750,374
              
              
              
              774,402$
              1,653,479
              
              
              $
              1,813,279LIABILITIES
      AND CAPITALIZATIONCURRENT
      LIABILITIES:Currently
      payable long-term debt
              
              $
              34
              
              
              $
              34Accounts
      payable-Associated
      companies
              
              
              88,769
              
              
              
              245,215Other
              
              
              3,368
              
              
              
              4,449Notes payable
      to associated companies
              
              
              95,203
              
              
              
              13,396Accrued
      taxes
              
              
              20,508
              
              
              
              30,245Lease market
      valuation liability
              
              
              36,900
              
              
              
              36,900Other
              
              
              26,415
              
              
              
              22,747271,197
              
              
              
              352,986CAPITALIZATION:Common
      stockholder's equity-Common stock,
      $5 par value, authorized 60,000,000 shares -29,402,054
      shares outstanding
              
              
              147,010
              
              
              
              147,010Other paid-in
      capital
              
              
              175,643
              
              
              
              173,169Accumulated
      other comprehensive loss
              
              
              (11,270
              )
              
              
              (10,606
              )Retained
      earnings
              
              
              185,121
              
              
              
              175,618Total common
      stockholder's equity
              
              
              496,504
              
              
              
              485,191Long-term debt
      and other long-term obligations
              
              
              303,382
              
              
              
              303,397799,886
              
              
              
              788,588NONCURRENT
      LIABILITIES:Accumulated
      deferred income taxes
              
              
              100,872
              
              
              
              103,463Accumulated
      deferred investment tax credits
              
              
              6,882
              
              
              
              10,180Lease market
      valuation liability
              
              
              282,325
              
              
              
              310,000Retirement
      benefits
              
              
              66,201
              
              
              
              63,215Asset
      retirement obligations
              
              
              29,715
              
              
              
              28,366Deferred
      revenues - electric service programs
              
              
              4,073
              
              
              
              12,639Lease
      assignment payable to associated companies
              
              
              30,529
              
              
              
              83,485Other
              
              
              61,799
              
              
              
              60,357582,396
              
              
              
              671,705COMMITMENTS
      AND CONTINGENCIES (Note 11)$
              1,653,479
              
              
              $
              1,813,279The
      accompanying Notes to Consolidated Financial Statements as they relate to
      The Toledo Edison Companyare an
      integral part of these balance sheets.
  
 76
   THE
      TOLEDO EDISON COMPANYCONSOLIDATED
      STATEMENTS OF CASH FLOWS(Unaudited)Nine
      MonthsEnded
      September 302008
              
              
              2007(In
      thousands)CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      income
              
              $
              69,503
              
              
              $
              72,799Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
              
              
              24,648
              
              
              
              27,475Amortization
      of regulatory assets
              
              
              81,837
              
              
              
              79,284Deferral of
      new regulatory assets
              
              
              (23,997
              )
              
              
              (47,373
              )Deferred rents
      and lease market valuation liability
              
              
              (32,918
              )
              
              
              (23,551
              )Deferred
      income taxes and investment tax credits, net
              
              
              (4,163
              )
              
              
              (32,530
              )Accrued
      compensation and retirement benefits
              
              
              (196
              )
              
              
              3,493Pension trust
      contribution
              
              
              -
              
              
              
              (7,659
              )Decrease
      (increase) in operating assets-Receivables
              
              
              29,088
              
              
              
              (13,368
              )Prepayments
      and other current assets
              
              
              (556
              )
              
              
              224Increase
      (decrease) in operating liabilities-Accounts
      payable
              
              
              (157,527
              )
              
              
              9,515Accrued
      taxes
              
              
              (9,737
              )
              
              
              13,588Accrued
      interest
              
              
              4,663
              
              
              
              3,444Electric
      service prepayment programs
              
              
              (8,566
              )
              
              
              (7,650
              )Other
              
              
              (577
              )
              
              
              4,113Net cash
      provided from (used for) operating activities
              
              
              (28,498
              )
              
              
              81,804CASH
      FLOWS FROM FINANCING ACTIVITIES:New
      Financing-Short-term
      borrowings, net
              
              
              81,807
              
              
              
              37,191Redemptions
      and Repayments-Long-term
      debt
              
              
              (26
              )
              
              
              (30,014
              )Dividend
      Payments-Common
      stock
              
              
              (60,000
              )
              
              
              (120,000
              )Net cash
      provided from (used for) financing activities
              
              
              21,781
              
              
              
              (112,823
              )CASH
      FLOWS FROM INVESTING ACTIVITIES:Property
      additions
              
              
              (44,695
              )
              
              
              (41,573
              )Loan
      repayments from associated companies, net
              
              
              42,948
              
              
              
              21,438Collection of
      principal on long-term notes receivable
              
              
              135
              
              
              
              36,077Redemption of
      lessor notes
              
              
              11,989
              
              
              
              14,819Sales of
      investment securities held in trusts
              
              
              28,774
              
              
              
              39,260Purchases of
      investment securities held in trusts
              
              
              (31,297
              )
              
              
              (41,717
              )Other
              
              
              (1,135
              )
              
              
              2,713Net cash
      provided from investing activities
              
              
              6,719
              
              
              
              31,017Net increase
      (decrease) in cash and cash equivalents
              
              
              2
              
              
              
              (2
              )Cash and cash
      equivalents at beginning of period
              
              
              22
              
              
              
              22Cash and cash
      equivalents at end of period
              
              $
              24
              
              
              $
              20The
      accompanying Notes to Consolidated Financial Statements as they relate to
      The Toledo Edison Company arean integral
      part of these statements.


77







JERSEY
CENTRAL POWER & LIGHT COMPANY





MANAGEMENT’S
NARRATIVE


ANALYSIS
OF RESULTS OF OPERATIONS








JCP&L is a
wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts
business in New Jersey, providing regulated electric transmission and
distribution services. JCP&L also provides generation services to those
customers electing to retain JCP&L as their power supplier.





Results of
Operations





Net income for the
first nine months of 2008 decreased to $153million from $164million in the same
period in 2007. The decrease was primarily due to higher purchased power costs
and other expenses, partially offset by higher revenues and lower amortization
of regulatory assets.





Revenues





In the first nine
months of 2008, revenues increased $235 million, or 9%, as compared with the
same period of 2007. Retail and wholesale generation revenues increased by
$147million and
$97million,
respectively, while distribution revenues decreased by $3 million in the
first nine months of 2008.





Retail generation
revenues from all customer classes increased due to higher unit prices resulting
from the BGS auctions effective June 1, 2007, and June 1, 2008,
partially offset by decreased retail generation KWH sales. The decreased sales
volume was primarily caused by milder weather and customer shopping. In the
first nine months of 2008, heating degree days decreased 8.1%as compared to the first
nine months of 2007, while cooling degree days were unchanged. Customer shopping
in the commercial and industrial customer sectors increased by
3.7 percentage points and 1.3 percentage points, respectively, in the first
nine months of 2008.





Changes in retail
generation KWH sales and revenues by customer class in the first nine months of
2008 compared to the same period of 2007 are summarized in the following
tables:





Retail
      Generation KWH Sales
            
            DecreaseResidential
            
            
            (1.2)
            %Commercial
            
            
            (6.0)
            %Industrial
            
            
            (6.7)
            %Decrease
      in Generation Sales
            
            
            (3.4)
            %





Retail
      Generation Revenues
            
            Increase(In
      millions)Residential
            
            $
            99Commercial
            
            
            42Industrial
            
            
            6Increase
      in Generation Revenues
            
            $
            147





Wholesale generation
revenues increased $97million in the first
nine months of 2008 due to higher market prices, partially offset by a slight
decrease in sales volumes as compared to the first nine months of
2007.





Distribution
revenues decreased $3 million in the first nine months of 2008 as compared
to the same period of 2007 due to lower KWH deliveries, reflecting the weather
impacts described above, partially offset by a slight increase in composite unit
prices.





Changes in
distribution KWH deliveries and revenues by customer class in the first nine
months of 2008 compared to the same period in 2007 are summarized in the
following tables:





Distribution
      KWH Deliveries
            
            DecreaseResidential
            
            
            (1.2)
            %Commercial
            
            
            (1.4)
            %Industrial
            
            
            (1.5)
            %Decrease
      in Distribution Deliveries
            
            
            (1.3)
            %





78








Distribution
      Revenues
            
            Increase
              (Decrease)(In
      millions)Residential
            
            $
            1Commercial
            
            
            (4
            )Industrial
            
            
            -Net
      Decrease in Distribution Revenues
            
            $
            (3
            )





Expenses





Total expenses
increased by $236 million in the first nine months of 2008 as compared to
the same period of 2007. The following table presents changes from the prior
year period by expense category:





Expenses  -
      Changes
            
            Increase
              (Decrease)(In
      millions)Purchased
      power costs
            
            $
            246Other
      operating costs
            
            
            (1
            )Provision for
      depreciation
            
            
            6Amortization
      of regulatory assets
            
            
            (16
            )General
      taxes
            
            
            1Net
      increase in expenses
            
            $
            236





Purchased power
costs increased in the first nine months of 2008 primarily due to higher unit
prices resulting from the BGS auctions effective June 1, 2007, and June 1,
2008, partially offset by a decrease in purchases due to the lower generation
KWH sales discussed above. Depreciation expense increased primarily due to an
increase in depreciable property since the third quarter of 2007. Amortization
of regulatory assets decreased in the first nine months of 2008 primarily due to
the completion in December 2007 of certain regulatory asset amortizations
associated with TMI-2 and lower transition cost amortization due to the lower
KWH deliveries discussed above.





Other Expenses





Other expenses
increased by $13 million in the first nine months of 2008 as compared to
the same period in 2007 primarily due to interest expense associated with
JCP&L’s $550 million issuance of senior notes in May 2007 and reduced
life insurance investment values.





Sale of Investment





On April 17, 2008,
JCP&L closed on the sale of its 86-MW Forked River Power Plant to Maxim
Power Corp. for $20 million. In conjunction with this sale, FES entered
into a 10-year tolling agreement with Maxim for the entire capacity of the
plant. The sale is subject to regulatory accounting and did not have a material
impact on JCP&L’s earnings in the first nine months of 2008. The New Jersey
Rate Counsel has appealed the NJBPU’s approval of the sale to the Appellate
Division of the Superior Court of New Jersey, where it is currently
pending.





Legal
Proceedings





See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of other legal proceedings applicable to JCP&L.





New Accounting Standards and
Interpretations





See the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to
JCP&L.














79











Report
of Independent Registered Public Accounting Firm


























To the Stockholder
and Board of


Directors of Jersey
Central Power & Light Company:





We have reviewed the
accompanying consolidated balance sheet of Jersey Central Power & Light
Company and its subsidiaries as of September 30, 2008 and the related
consolidated statements of income and comprehensive income for each of the
three-month and nine-month periods ended September 30, 2008 and 2007 and the
consolidated statement of cash flows for the nine-month periods ended September
30, 2008 and 2007. These interim financial statements are the responsibility of
the Company’s management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2007, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 28, 2008, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying consolidated balance
sheet information as of December 31, 2007, is fairly stated in all material
respects in relation to the consolidated balance sheet from which it has been
derived.




PricewaterhouseCoopers
      LLP
              Cleveland,
      Ohio
              November 6,
      2008











80





JERSEY
      CENTRAL POWER & LIGHT COMPANYCONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE INCOME(Unaudited)Three
      Months
              
              
              Nine
      MonthsEnded
      September 30
              
              
              Ended
      September 302008
              
              
              2007
              
              
              2008
              
              
              2007(In
      thousands)REVENUES:Electric
      sales
              
              $
              1,087,245
              
              
              $
              1,018,049
              
              
              $
              2,691,782
              
              
              $
              2,457,146Excise tax
      collections
              
              
              15,358
              
              
              
              15,168
              
              
              
              39,792
              
              
              
              39,849Total
      revenues
              
              
              1,102,603
              
              
              
              1,033,217
              
              
              
              2,731,574
              
              
              
              2,496,995EXPENSES:Purchased
      power
              
              
              720,996
              
              
              
              654,418
              
              
              
              1,751,854
              
              
              
              1,505,420Other
      operating costs
              
              
              78,275
              
              
              
              87,010
              
              
              
              234,628
              
              
              
              236,225Provision for
      depreciation
              
              
              23,205
              
              
              
              22,032
              
              
              
              70,030
              
              
              
              63,867Amortization
      of regulatory assets
              
              
              102,954
              
              
              
              107,837
              
              
              
              280,980
              
              
              
              296,955General
      taxes
              
              
              19,476
              
              
              
              18,631
              
              
              
              52,042
              
              
              
              51,183Total
      expenses
              
              
              944,906
              
              
              
              889,928
              
              
              
              2,389,534
              
              
              
              2,153,650OPERATING
      INCOME
              
              
              157,697
              
              
              
              143,289
              
              
              
              342,040
              
              
              
              343,345OTHER
      INCOME (EXPENSE):Miscellaneous
      income (expense)
              
              
              (565
              )
              
              
              2,967
              
              
              
              459
              
              
              
              9,266Interest
      expense
              
              
              (25,747
              )
              
              
              (24,666
              )
              
              
              (75,051
              )
              
              
              (71,576
              )Capitalized
      interest
              
              
              257
              
              
              
              483
              
              
              
              963
              
              
              
              1,559Total other
      expense
              
              
              (26,055
              )
              
              
              (21,216
              )
              
              
              (73,629
              )
              
              
              (60,751
              )INCOME
      BEFORE INCOME TAXES
              
              
              131,642
              
              
              
              122,073
              
              
              
              268,411
              
              
              
              282,594INCOME
      TAXES
              
              
              55,752
              
              
              
              46,275
              
              
              
              115,623
              
              
              
              118,637NET
      INCOME
              
              
              75,890
              
              
              
              75,798
              
              
              
              152,788
              
              
              
              163,957OTHER
      COMPREHENSIVE INCOME (LOSS):Pension and
      other postretirement benefits
              
              
              (3,449
              )
              
              
              (2,114
              )
              
              
              (10,347
              )
              
              
              (6,344
              )Unrealized
      gain on derivative hedges
              
              
              69
              
              
              
              69
              
              
              
              207
              
              
              
              235Other
      comprehensive loss
              
              
              (3,380
              )
              
              
              (2,045
              )
              
              
              (10,140
              )
              
              
              (6,109
              )Income tax
      benefit related to other comprehensive loss
              
              
              (1,469
              )
              
              
              (994
              )
              
              
              (4,408
              )
              
              
              (2,973
              )Other
      comprehensive loss, net of tax
              
              
              (1,911
              )
              
              
              (1,051
              )
              
              
              (5,732
              )
              
              
              (3,136
              )TOTAL
      COMPREHENSIVE INCOME
              
              $
              73,979
              
              
              $
              74,747
              
              
              $
              147,056
              
              
              $
              160,821The
      accompanying Notes to Consolidated Financial Statements as they relate to
      Jersey Central Power & Light Company are anintegral
      part of these statements.
   81
 
 JERSEY
      CENTRAL POWER & LIGHT COMPANYCONSOLIDATED
      BALANCE SHEETS(Unaudited)September
      30,
              
              
              December
      31,2008
              
              
              2007(In
      thousands)ASSETSCURRENT
      ASSETS:Cash and cash
      equivalents
              
              $
              38
              
              
              $
              94Receivables-Customers
      (less accumulated provisions of $4,115,000 and $3,691,000,respectively,
      for uncollectible accounts)
              
              
              386,037
              
              
              
              321,026Associated
      companies
              
              
              45
              
              
              
              21,297Other
              
              
              51,020
              
              
              
              59,244Notes
      receivable - associated companies
              
              
              17,874
              
              
              
              18,428Prepaid
      taxes
              
              
              81,540
              
              
              
              1,012Other
              
              
              2,059
              
              
              
              17,603538,613
              
              
              
              438,704UTILITY
      PLANT:In
      service
              
              
              4,297,036
              
              
              
              4,175,125Less -
      Accumulated provision for depreciation
              
              
              1,547,099
              
              
              
              1,516,9972,749,937
              
              
              
              2,658,128Construction
      work in progress
              
              
              65,095
              
              
              
              90,5082,815,032
              
              
              
              2,748,636OTHER
      PROPERTY AND INVESTMENTS:Nuclear fuel
      disposal trust
              
              
              183,152
              
              
              
              176,512Nuclear plant
      decommissioning trusts
              
              
              158,418
              
              
              
              175,869Other
              
              
              2,176
              
              
              
              2,083343,746
              
              
              
              354,464DEFERRED
      CHARGES AND OTHER ASSETS:Regulatory
      assets
              
              
              1,295,024
              
              
              
              1,595,662Goodwill
              
              
              1,814,976
              
              
              
              1,826,190Pension
      Assets
              
              
              122,332
              
              
              
              100,615Other
              
              
              14,959
              
              
              
              16,3073,247,291
              
              
              
              3,538,774$
              6,944,682
              
              
              $
              7,080,578LIABILITIES
      AND CAPITALIZATIONCURRENT
      LIABILITIES:Currently
      payable long-term debt
              
              $
              28,713
              
              
              $
              27,206Short-term
      borrowings-Associated
      companies
              
              
              142,617
              
              
              
              130,381Accounts
      payable-Associated
      companies
              
              
              10,541
              
              
              
              7,541Other
              
              
              226,947
              
              
              
              193,848Accrued
      interest
              
              
              26,594
              
              
              
              9,318Cash
      collateral from suppliers
              
              
              23,510
              
              
              
              583Other
              
              
              123,273
              
              
              
              105,827582,195
              
              
              
              474,704CAPITALIZATION:Common
      stockholder's equity-Common stock,
      $10 par value, authorized 16,000,000 shares-14,421,637
      shares outstanding
              
              
              144,216
              
              
              
              144,216Other paid-in
      capital
              
              
              2,648,732
              
              
              
              2,655,941Accumulated
      other comprehensive loss
              
              
              (25,613
              )
              
              
              (19,881
              )Retained
      earnings
              
              
              204,376
              
              
              
              237,588Total common
      stockholder's equity
              
              
              2,971,711
              
              
              
              3,017,864Long-term debt
      and other long-term obligations
              
              
              1,540,208
              
              
              
              1,560,3104,511,919
              
              
              
              4,578,174NONCURRENT
      LIABILITIES:Power purchase
      contract loss liability
              
              
              602,626
              
              
              
              749,671Accumulated
      deferred income taxes
              
              
              791,220
              
              
              
              800,214Nuclear fuel
      disposal costs
              
              
              195,688
              
              
              
              192,402Asset
      retirement obligations
              
              
              93,798
              
              
              
              89,669Other
              
              
              167,236
              
              
              
              195,7441,850,568
              
              
              
              2,027,700COMMITMENTS
      AND CONTINGENCIES (Note 11)$
              6,944,682
              
              
              $
              7,080,578The
      accompanying Notes to Consolidated Financial Statements as they relate to
      Jersey Central Power & Light Companyare an
      integral part of these balance sheets.
   82
 JERSEY
      CENTRAL POWER & LIGHT COMPANYCONSOLIDATED
      STATEMENTS OF CASH FLOWS(Unaudited)Nine
      MonthsEnded
      September 302008
                
                
                2007(In
      thousands)CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      income
                
                $
                152,788
                
                
                $
                163,957Adjustments to
      reconcile net income to net cash from operating activities
    -Provision for
      depreciation
                
                
                70,030
                
                
                
                63,867Amortization
      of regulatory assets
                
                
                280,980
                
                
                
                296,955Deferred
      purchased power and other costs
                
                
                (132,820
                )
                
                
                (157,201
                )Deferred
      income taxes and investment tax credits, net
                
                
                1,051
                
                
                
                (23,786
                )Accrued
      compensation and retirement benefits
                
                
                (32,087
                )
                
                
                (17,543
                )Cash
      collateral received from (returned to) suppliers
                
                
                23,138
                
                
                
                (32,243
                )Pension trust
      contribution
                
                
                -
                
                
                
                (17,800
                )Decrease
      (increase) in operating assets-Receivables
                
                
                (43,742
                )
                
                
                (149,024
                )Materials and
      supplies
                
                
                348
                
                
                
                127Prepaid
      taxes
                
                
                (62,148
                )
                
                
                (28,337
                )Other current
      assets
                
                
                (114
                )
                
                
                2,079Increase
      (decrease) in operating liabilities-Accounts
      payable
                
                
                36,099
                
                
                
                (6,598
                )Accrued
      taxes
                
                
                2,082
                
                
                
                29,318Accrued
      interest
                
                
                17,276
                
                
                
                13,062Tax
      collections payable
                
                
                (12,493
                )
                
                
                (12,478
                )Other
                
                
                24,705
                
                
                
                2,534Net cash
      provided from operating activities
                
                
                325,093
                
                
                
                126,889CASH
      FLOWS FROM FINANCING ACTIVITIES:New
      Financing-Long-term
      debt
                
                
                -
                
                
                
                549,999Short-term
      borrowings, net
                
                
                12,236
                
                
                
                -Redemptions
      and Repayments-Long-term
      debt
                
                
                (19,138
                )
                
                
                (324,256
                )Short-term
      borrowings, net
                
                
                -
                
                
                
                (31,145
                )Common
      Stock
                
                
                -
                
                
                
                (125,000
                )Dividend
      Payments-Common
      stock
                
                
                (186,000
                )
                
                
                (43,000
                )Net cash
      provided from (used for) financing activities
                
                
                (192,902
                )
                
                
                26,598CASH
      FLOWS FROM INVESTING ACTIVITIES:Property
      additions
                
                
                (136,265
                )
                
                
                (144,668
                )Proceeds from
      asset sales
                
                
                20,000
                
                
                
                -Loan
      repayments from associated companies, net
                
                
                553
                
                
                
                1,722Sales of
      investment securities held in trusts
                
                
                186,564
                
                
                
                169,649Purchases of
      investment securities held in trusts
                
                
                (199,699
                )
                
                
                (181,794
                )Other
                
                
                (3,400
                )
                
                
                1,640Net cash used
      for investing activities
                
                
                (132,247
                )
                
                
                (153,451
                )Net increase
      (decrease) in cash and cash equivalents
                
                
                (56
                )
                
                
                36Cash and cash
      equivalents at beginning of period
                
                
                94
                
                
                
                41Cash and cash
      equivalents at end of period
                
                $
                38
                
                
                $
                77The
      accompanying Notes to Consolidated Financial Statements as they relate to
      Jersey Central Power & Light Companyare an
      integral part of these statements.









83











METROPOLITAN
EDISON COMPANY





MANAGEMENT’S
NARRATIVE


ANALYSIS
OF RESULTS OF OPERATIONS








Met-Ed is a wholly
owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in
eastern Pennsylvania, providing regulated electric transmission and distribution
services. Met-Ed also provides generation service to those customers electing to
retain Met-Ed as their power supplier.





Results of
Operations





Net income decreased
to $64 million in the first nine months of 2008, compared to $76 million in
the same period of 2007. The decrease was primarily due to higher purchased
power and other operating costs, partially offset by higher revenues and
deferrals of new regulatory assets.





Revenues





Revenues increased
by $105 million, or 9.2%, in the first nine months of 2008 principally due
to higher wholesale generation revenues. Wholesale revenues increased by
$96million in the
first nine months of 2008, compared to the same period of 2007, primarily
reflecting higher spot market prices for PJM market participants. Increased
distribution throughput revenues were partially offset by decreases in retail
generation revenues and PJM transmission revenues.





In the first nine
months of 2008, retail generation revenues decreased $1million primarily due to
lower KWH sales to the residential and industrial customer classes, partially
offset by higher KWH sales to commercial customers and higher composite unit
prices in all customer classes.





Changes in retail
generation sales and revenues in the first nine months of 2008 compared to the
same period of 2007 are summarized in the following tables:





IncreaseRetail
      Generation KWH Sales
            
            (Decrease)Residential
            
            
            (0.8
            )%Commercial
            
            
            1.8
            %Industrial
            
            
            (3.4
            )%Net
      Decrease in Retail Generation Sales
            
            
            (0.7
            )%





IncreaseRetail
      Generation Revenues
            
            (Decrease)(In
      millions)Residential
            
            $
            (1
            )Commercial
            
            
            4Industrial
            
            
            (4
            )Net
      Decrease in Retail Generation Revenues
            
            $
            (1
            )





Revenues from
distribution throughput increased $27 million in the first nine months of
2008, compared to the same period in 2007. Higher rates received for
transmission services, resulting from the annual update of Met-Ed’s TSC rider
effective June 1, 2008 (see Regulatory Matters), were partially offset by
decreased distribution rates. Decreased KWH deliveries in the residential and
industrial customer classes were partially offset by increased KWH deliveries to
commercial customers.





Changes in
distribution KWH deliveries and revenues in the first nine months of 2008
compared to the same period of 2007 are summarized in the following
tables:





84








IncreaseDistribution
      KWH Deliveries
            
            (Decrease)Residential
            
            
            (0.8
            )%Commercial
            
            
            1.8
            %Industrial
            
            
            (3.4
            )%Net
      Decrease in Distribution Deliveries
            
            
            (0.7
            )%





Distribution
      Revenues
            
            Increase(In
      millions)Residential
            
            $
            11Commercial
            
            
            11Industrial
            
            
            5Increase
      in Distribution Revenues
            
            $
            27





PJM transmission
revenues decreased by $18million in the first
nine months of 2008 compared to the same period of 2007, primarily due to
decreased PJM FTR revenue. Met-Ed defers the difference between transmission
revenues and net transmission costs incurred in PJM, resulting in no material
effect to current period earnings.





Operating Expenses





Total operating
expenses increased by $116 million in the first nine months of 2008
compared to the same period of 2007. The following table presents changes from
the prior year by expense category:





Expenses
      – Changes
            
            Increase
              (Decrease)(In
      millions)Purchased
      power costs
            
            $
            96Other
      operating costs
            
            
            35Provision for
      depreciation
            
            
            2Amortization
      of regulatory assets
            
            
            (1
            )Deferral of
      new regulatory assets
            
            
            (18
            )General
      taxes
            
            
            2Net
      Increase in expenses
            
            $
            116





Purchased power
costs increased by $96 million in the first nine months of 2008 due to higher
composite unit prices from non-affiliates in PJM. Other operating costs
increased by $35 million in the first nine months of 2008 primarily due to
higher transmission expenses.





The deferral of new
regulatory assets increased in the first nine months of 2008 primarily due to
increased transmission cost deferrals ($29 million) and universal service
charge deferrals ($4 million), partially offset by the absence of the 2007
deferral of previously expensed decommissioning costs ($15 million) for the
Saxton nuclear research facility (see Regulatory Matters).





Other Expense





Other expense
increased $8 million in the first nine months of 2008 primarily due to a
decrease in interest earned on stranded regulatory assets, reflecting lower
regulatory asset balances, and reduced life insurance investment values,
partially offset by lower interest expense.





Legal
Proceedings





See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to Met-Ed.





New Accounting Standards and
Interpretations





See the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to
Met-Ed.











85











Report
of Independent Registered Public Accounting Firm


























To the Stockholder
and Board of


Directors of
Metropolitan Edison Company:





We have reviewed the
accompanying consolidated balance sheet of Metropolitan Edison Company and its
subsidiaries as of September 30, 2008 and the related consolidated
statements of income and comprehensive income for each of the three-month and
nine-month periods ended September 30, 2008 and 2007 and the consolidated
statement of cash flows for the nine-month periods ended September 30, 2008 and
2007. These interim financial statements are the responsibility of the Company’s
management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2007, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 28, 2008, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying consolidated balance
sheet information as of December 31, 2007, is fairly stated in all material
respects in relation to the consolidated balance sheet from which it has been
derived.




PricewaterhouseCoopers
      LLP
              Cleveland,
      Ohio
              November 6,
      2008











86




METROPOLITAN
      EDISON COMPANYCONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE INCOME(Unaudited)Three
      Months
              
              
              Nine
      MonthsEnded
      September 30
              
              
              Ended
      September 302008
              
              
              2007
              
              
              2008
              
              
              2007(In
      thousands)REVENUES:Electric
      sales
              
              $
              434,742
              
              
              $
              391,083
              
              
              $
              1,188,171
              
              
              $
              1,087,460Gross receipts
      tax collections
              
              
              20,793
              
              
              
              19,524
              
              
              
              59,669
              
              
              
              55,146Total
      revenues
              
              
              455,535
              
              
              
              410,607
              
              
              
              1,247,840
              
              
              
              1,142,606EXPENSES:Purchased
      power
              
              
              245,699
              
              
              
              209,842
              
              
              
              680,424
              
              
              
              584,249Other
      operating costs
              
              
              126,659
              
              
              
              106,104
              
              
              
              350,704
              
              
              
              315,227Provision for
      depreciation
              
              
              11,394
              
              
              
              11,154
              
              
              
              33,446
              
              
              
              31,969Amortization
      of regulatory assets
              
              
              34,642
              
              
              
              36,853
              
              
              
              101,383
              
              
              
              101,965Deferral of
      new regulatory assets
              
              
              (30,962
              )
              
              
              (19,151
              )
              
              
              (111,545
              )
              
              
              (93,772
              )General
      taxes
              
              
              23,030
              
              
              
              21,986
              
              
              
              64,887
              
              
              
              63,208Total
      expenses
              
              
              410,462
              
              
              
              366,788
              
              
              
              1,119,299
              
              
              
              1,002,846OPERATING
      INCOME
              
              
              45,073
              
              
              
              43,819
              
              
              
              128,541
              
              
              
              139,760OTHER
      INCOME (EXPENSE):Interest
      income
              
              
              4,016
              
              
              
              7,239
              
              
              
              14,368
              
              
              
              22,740Miscellaneous
      income
              
              
              88
              
              
              
              1,366
              
              
              
              568
              
              
              
              3,973Interest
      expense
              
              
              (11,014
              )
              
              
              (13,291
              )
              
              
              (33,666
              )
              
              
              (38,471
              )Capitalized
      interest
              
              
              93
              
              
              
              292
              
              
              
              73
              
              
              
              940Total other
      expense
              
              
              (6,817
              )
              
              
              (4,394
              )
              
              
              (18,657
              )
              
              
              (10,818
              )INCOME
      BEFORE INCOME TAXES
              
              
              38,256
              
              
              
              39,425
              
              
              
              109,884
              
              
              
              128,942INCOME
      TAXES
              
              
              16,270
              
              
              
              14,737
              
              
              
              45,866
              
              
              
              53,145NET
      INCOME
              
              
              21,986
              
              
              
              24,688
              
              
              
              64,018
              
              
              
              75,797OTHER
      COMPREHENSIVE INCOME (LOSS):Pension and
      other postretirement benefits
              
              
              (2,233
              )
              
              
              (1,452
              )
              
              
              (6,699
              )
              
              
              (4,357
              )Unrealized
      gain on derivative hedges
              
              
              84
              
              
              
              83
              
              
              
              252
              
              
              
              251Other
      comprehensive loss
              
              
              (2,149
              )
              
              
              (1,369
              )
              
              
              (6,447
              )
              
              
              (4,106
              )Income tax
      benefit related to other comprehensive loss
              
              
              (971
              )
              
              
              (693
              )
              
              
              (2,912
              )
              
              
              (2,078
              )Other
      comprehensive loss, net of tax
              
              
              (1,178
              )
              
              
              (676
              )
              
              
              (3,535
              )
              
              
              (2,028
              )TOTAL
      COMPREHENSIVE INCOME
              
              $
              20,808
              
              
              $
              24,012
              
              
              $
              60,483
              
              
              $
              73,769The
      accompanying Notes to Consolidated Financial Statements as they relate to
      Metropolitan Edison Company are an integralpart of these
      statements.
  87
   METROPOLITAN
      EDISON COMPANYCONSOLIDATED
      BALANCE SHEETS(Unaudited)September
      30,
              
              
              December
      31,2008
              
              
              2007(In
      thousands)ASSETSCURRENT
      ASSETS:Cash and cash
      equivalents
              
              $
              129
              
              
              $
              135Receivables-Customers
      (less accumulated provisions of $3,905,000 and $4,327,000respectively,
      for uncollectible accounts)
              
              
              149,363
              
              
              
              142,872Associated
      companies
              
              
              22,060
              
              
              
              27,693Other
              
              
              21,130
              
              
              
              18,909Notes
      receivable from associated companies
              
              
              11,412
              
              
              
              12,574Prepaid
      taxes
              
              
              19,626
              
              
              
              14,615Other
              
              
              481
              
              
              
              1,348224,201
              
              
              
              218,146UTILITY
      PLANT:In
      service
              
              
              2,044,493
              
              
              
              1,972,388Less -
      Accumulated provision for depreciation
              
              
              770,510
              
              
              
              751,7951,273,983
              
              
              
              1,220,593Construction
      work in progress
              
              
              32,801
              
              
              
              30,5941,306,784
              
              
              
              1,251,187OTHER
      PROPERTY AND INVESTMENTS:Nuclear plant
      decommissioning trusts
              
              
              256,366
              
              
              
              286,831Other
              
              
              982
              
              
              
              1,360257,348
              
              
              
              288,191DEFERRED
      CHARGES AND OTHER ASSETS:Goodwill
              
              
              418,568
              
              
              
              424,313Regulatory
      assets
              
              
              540,785
              
              
              
              494,947Pension
      assets
              
              
              59,740
              
              
              
              51,427Other
              
              
              30,714
              
              
              
              36,4111,049,807
              
              
              
              1,007,098$
              2,838,140
              
              
              $
              2,764,622LIABILITIES
      AND CAPITALIZATIONCURRENT
      LIABILITIES:Currently
      payable long-term debt
              
              $
              28,500
              
              
              $
              -Short-term
      borrowings-Associated
      companies
              
              
              65,286
              
              
              
              185,327Other
              
              
              250,000
              
              
              
              100,000Accounts
      payable-Associated
      companies
              
              
              23,643
              
              
              
              29,855Other
              
              
              63,656
              
              
              
              66,694Accrued
      taxes
              
              
              2,483
              
              
              
              16,020Accrued
      interest
              
              
              7,273
              
              
              
              6,778Other
              
              
              30,858
              
              
              
              27,393471,699
              
              
              
              432,067CAPITALIZATION:Common
      stockholder's equity-Common stock,
      without par value, authorized 900,000 shares-859,500 shares
      outstanding
              
              
              1,198,206
              
              
              
              1,203,186Accumulated
      other comprehensive loss
              
              
              (18,932
              )
              
              
              (15,397
              )Accumulated
      deficit
              
              
              (75,139
              )
              
              
              (139,157
              )Total common
      stockholder's equity
              
              
              1,104,135
              
              
              
              1,048,632Long-term debt
      and other long-term obligations
              
              
              513,721
              
              
              
              542,1301,617,856
              
              
              
              1,590,762NONCURRENT
      LIABILITIES:Accumulated
      deferred income taxes
              
              
              455,898
              
              
              
              438,890Accumulated
      deferred investment tax credits
              
              
              7,922
              
              
              
              8,390Nuclear fuel
      disposal costs
              
              
              44,205
              
              
              
              43,462Asset
      retirement obligations
              
              
              168,367
              
              
              
              160,726Retirement
      benefits
              
              
              5,252
              
              
              
              8,681Other
              
              
              66,941
              
              
              
              81,644748,585
              
              
              
              741,793COMMITMENTS
      AND CONTINGENCIES (Note 11)$
              2,838,140
              
              
              $
              2,764,622The
      accompanying Notes to Consolidated Financial Statements as they relate to
      Metropolitan Edison Company are anintegral part
      of these balance sheets.
  88
   METROPOLITAN
      EDISON COMPANYCONSOLIDATED
      STATEMENTS OF CASH FLOWS(Unaudited)Nine
      MonthsEnded
      September 302008
              
              
              2007(In
      thousands)CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      income
              
              $
              64,018
              
              
              $
              75,797Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
              
              
              33,446
              
              
              
              31,969Amortization
      of regulatory assets
              
              
              101,383
              
              
              
              101,965Deferred costs
      recoverable as regulatory assets
              
              
              (9,673
              )
              
              
              (53,276
              )Deferral of
      new regulatory assets
              
              
              (111,545
              )
              
              
              (93,772
              )Deferred
      income taxes and investment tax credits, net
              
              
              39,919
              
              
              
              20,514Accrued
      compensation and retirement benefits
              
              
              (18,948
              )
              
              
              (14,404
              )Cash
      collateral
              
              
              -
              
              
              
              1,650Pension trust
      contribution
              
              
              -
              
              
              
              (11,012
              )Decrease
      (increase) in operating assets-Receivables
              
              
              (19,751
              )
              
              
              (57,599
              )Prepayments
      and other current assets
              
              
              (4,144
              )
              
              
              7,227Increase
      (decrease) in operating liabilities-Accounts
      payable
              
              
              (9,250
              )
              
              
              (79,316
              )Accrued
      taxes
              
              
              (13,285
              )
              
              
              3,024Accrued
      interest
              
              
              495
              
              
              
              (153
              )Other
              
              
              13,510
              
              
              
              11,386Net cash
      provided from (used for) operating activities
              
              
              66,175
              
              
              
              (56,000
              )CASH
      FLOWS FROM FINANCING ACTIVITIES:New
      Financing-Long-term
      debt
              
              
              28,500
              
              
              
              -Short-term
      borrowings, net
              
              
              29,959
              
              
              
              193,324Redemptions
      and Repayments-Long-term
      debt
              
              
              (28,640
              )
              
              
              (50,000
              )Net cash
      provided from financing activities
              
              
              29,819
              
              
              
              143,324CASH
      FLOWS FROM INVESTING ACTIVITIES:Property
      additions
              
              
              (87,536
              )
              
              
              (74,812
              )Sales of
      investment securities held in trusts
              
              
              131,915
              
              
              
              153,943Purchases of
      investment securities held in trusts
              
              
              (140,429
              )
              
              
              (162,573
              )Loans from
      (to) associated companies, net
              
              
              1,163
              
              
              
              (3,511
              )Other
              
              
              (1,113
              )
              
              
              (375
              )Net cash used
      for investing activities
              
              
              (96,000
              )
              
              
              (87,328
              )Net decrease
      in cash and cash equivalents
              
              
              (6
              )
              
              
              (4
              )Cash and cash
      equivalents at beginning of period
              
              
              135
              
              
              
              130Cash and cash
      equivalents at end of period
              
              $
              129
              
              
              $
              126The
      accompanying Notes to Consolidated Financial Statements as they relate to
      Metropolitan Edison Company are anintegral part
      of these statements.


89








PENNSYLVANIA
ELECTRIC COMPANY





MANAGEMENT’S
NARRATIVE


ANALYSIS
OF RESULTS OF OPERATIONS








Penelec is a wholly
owned electric utility subsidiary of FirstEnergy. Penelec conducts business in
northern and south central Pennsylvania, providing regulated transmission and
distribution services. Penelec also provides generation services to those
customers electing to retain Penelec as their power supplier.





Results of
Operations





Net income decreased
to $62 million in the first nine months of 2008, compared to $74 million in
the same period of 2007. The decrease was primarily due to increased purchased
power costs, net amortization of regulatory assets, interest expense and other
operating costs, partially offset by higher revenues.





Revenues





Revenues increased
by $96 million, or 9.2%, in the first nine months of 2008 primarily due to
higher retail and wholesale generation revenues, distribution throughput
revenues and PJM transmission revenues. Wholesale revenues increased
$76 million in the first nine months of 2008, compared to the same period
of 2007, primarily reflecting higher spot market prices for PJM market
participants.





In the first nine
months of 2008, retail generation revenues increased $3 million primarily due to
higher composite unit prices in all customer classes and higher KWH sales to
commercial customers, partially offset by a slight decrease in KWH sales to
industrial customers.





Changes in retail
generation sales and revenues in the first nine months of 2008 compared to the
same period of 2007 are summarized in the following tables:





Retail
      Generation KWH Sales
            
            Increase
              (Decrease)Residential
            
            
            -Commercial
            
            
            0.7
            %Industrial
            
            
            (0.3
            )
      %Net
      Increase in Retail Generation Sales
            
            
            0.2
            %





Retail
      Generation Revenues
            
            Increase(In
      millions)Residential
            
            $
            1Commercial
            
            
            2Industrial
            
            
            -Increase
      in Retail Generation Revenues
            
            $
            3





Revenues from
distribution throughput increased $7 million in the first nine months of 2008
compared to the same period of 2007. Higher usage in the commercial and
industrial sectors along with an increase in transmission rates, resulting from
the annual update of Penelec’s TSC rider effective June 1, 2008 (see
Regulatory Matters), was partially offset by a decrease in distribution
rates.





Changes in
distribution KWH deliveries and revenues in the first nine months of 2008
compared to the same period of 2007 are summarized in the following
tables:





Distribution
      KWH Deliveries
            
            IncreaseResidential
            
            
            -Commercial
            
            
            0.7
            %Industrial
            
            
            1.7
            %Increase
      in Distribution Deliveries
            
            
            0.8
            %








90








Distribution
      Revenues
            
            Increase
              (Decrease)(In
      millions)Residential
            
            $
            6Commercial
            
            
            2Industrial
            
            
            (1
            )Net
      Increase in Distribution Revenues
            
            $
            7





PJM transmission
revenues increased by $12 million in the first nine months of 2008 compared to
the same period of 2007, primarily due to higher PJM FTR revenue. Penelec defers
the difference between transmission revenues and net transmission costs incurred
in PJM, resulting in no material effect to current period earnings.





Operating Expenses





Total operating
expenses increased by $105 million in the first nine months of 2008 as compared
with the same period of 2007. The following table presents changes from the
prior year by expense category:





Expenses
      - Changes
            
            Increase(In
      millions)Purchased
      power costs
            
            $
            69Other
      operating costs
            
            
            6Provision for
      depreciation
            
            
            4Amortization
      of regulatory assets, net
            
            
            23General
      taxes
            
            
            3Increase
      in expenses
            
            $
            105





Purchased power
costs increased by $69 million, or 11.7%, in the first nine months of 2008
compared to the same period of 2007, due primarily to higher composite unit
prices from non-affiliates in the PJM market. Other operating costs increased by
$6 million in the first nine months of 2008, principally due to higher
transmission expenses and higher expenses related to Penelec’s customer
assistance programs. Depreciation expense increased primarily due to an increase
in depreciable property since the third quarter of 2007.





Amortization of
regulatory assets (net of deferrals) increased in the first nine months of 2008
primarily due to the absence of the 2007 deferral of previously expensed
decommissioning costs ($12 million) for the Saxton nuclear research
facility (see Regulatory Matters) and decreased transmission cost deferrals ($16
million), partially offset by an increase in universal service charge deferrals
($5 million).





In the first nine
months of 2008, general taxes increased from the same period of 2007, due to
higher gross receipts taxes ($4 million), partially offset by lower capital
stock taxes ($1 million).





Other Expense





In the first nine
months of 2008, other expense increased primarily due to higher interest expense
associated with Penelec’s $300 million senior note issuance in August 2007
and reduced life insurance investment values.





Legal
Proceedings





See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to Penelec.





New Accounting Standards and
Interpretations





See the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to
Penelec.





91











Report
of Independent Registered Public Accounting Firm


























To the Stockholder
and Board of


Directors of
Pennsylvania Electric Company:





We have reviewed the
accompanying consolidated balance sheet of Pennsylvania Electric Company and its
subsidiaries as of September 30, 2008 and the related consolidated
statements of income and comprehensive income for each of the three-month and
nine-month periods ended September 30, 2008 and 2007 and the consolidated
statement of cash flows for the nine-month periods ended September 30, 2008 and
2007. These interim financial statements are the responsibility of the Company’s
management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2007, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 28, 2008, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying consolidated balance
sheet information as of December 31, 2007, is fairly stated in all material
respects in relation to the consolidated balance sheet from which it has been
derived.




PricewaterhouseCoopers
      LLP
              Cleveland,
      Ohio
              November 6,
      2008











92





PENNSYLVANIA
      ELECTRIC COMPANYCONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE INCOME(Unaudited)Three Months
              
              
              Nine MonthsEnded September 30
              
              
              Ended
      September 302008
              
              
              2007
              
              
              2008
              
              
              2007(In
      thousands)REVENUES:Electric
      sales
              
              $
              372,576
              
              
              $
              336,798
              
              
              $
              1,083,986
              
              
              $
              991,769Gross receipts
      tax collections
              
              
              17,200
              
              
              
              16,637
              
              
              
              52,704
              
              
              
              48,989Total
      revenues
              
              
              389,776
              
              
              
              353,435
              
              
              
              1,136,690
              
              
              
              1,040,758EXPENSES:Purchased
      power
              
              
              230,656
              
              
              
              203,247
              
              
              
              657,681
              
              
              
              588,583Other
      operating costs
              
              
              54,727
              
              
              
              51,571
              
              
              
              175,904
              
              
              
              169,299Provision for
      depreciation
              
              
              14,097
              
              
              
              12,566
              
              
              
              40,531
              
              
              
              36,678Amortization
      of regulatory assets, net
              
              
              23,415
              
              
              
              20,861
              
              
              
              55,346
              
              
              
              32,648General
      taxes
              
              
              20,285
              
              
              
              19,433
              
              
              
              60,485
              
              
              
              57,634Total
      expenses
              
              
              343,180
              
              
              
              307,678
              
              
              
              989,947
              
              
              
              884,842OPERATING
      INCOME
              
              
              46,596
              
              
              
              45,757
              
              
              
              146,743
              
              
              
              155,916OTHER
      INCOME (EXPENSE):Miscellaneous
      income (expense)
              
              
              (93
              )
              
              
              1,483
              
              
              
              774
              
              
              
              5,035Interest
      expense
              
              
              (14,934
              )
              
              
              (14,017
              )
              
              
              (45,157
              )
              
              
              (38,426
              )Capitalized
      interest
              
              
              57
              
              
              
              194
              
              
              
              (679
              )
              
              
              737Total other
      expense
              
              
              (14,970
              )
              
              
              (12,340
              )
              
              
              (45,062
              )
              
              
              (32,654
              )INCOME
      BEFORE INCOME TAXES
              
              
              31,626
              
              
              
              33,417
              
              
              
              101,681
              
              
              
              123,262INCOME
      TAXES
              
              
              9,058
              
              
              
              10,387
              
              
              
              39,324
              
              
              
              49,025NET
      INCOME
              
              
              22,568
              
              
              
              23,030
              
              
              
              62,357
              
              
              
              74,237OTHER
      COMPREHENSIVE INCOME (LOSS):Pension and
      other postretirement benefits
              
              
              (3,474
              )
              
              
              (2,825
              )
              
              
              (10,421
              )
              
              
              (8,475
              )Unrealized
      gain on derivative hedges
              
              
              16
              
              
              
              16
              
              
              
              48
              
              
              
              49Change in
      unrealized gain on available-for-sale securities
              
              
              2
              
              
              
              10
              
              
              
              (8
              )
              
              
              (6
              )Other
      comprehensive loss
              
              
              (3,456
              )
              
              
              (2,799
              )
              
              
              (10,381
              )
              
              
              (8,432
              )Income tax
      benefit related to other comprehensive loss
              
              
              (1,510
              )
              
              
              (1,294
              )
              
              
              (4,536
              )
              
              
              (3,894
              )Other
      comprehensive loss, net of tax
              
              
              (1,946
              )
              
              
              (1,505
              )
              
              
              (5,845
              )
              
              
              (4,538
              )TOTAL
      COMPREHENSIVE INCOME
              
              $
              20,622
              
              
              $
              21,525
              
              
              $
              56,512
              
              
              $
              69,699The
      accompanying Notes to Consolidated Financial Statements as they relate to
      Pennsylvania Electric Company are an integralpart of these
      statements.
  93
   PENNSYLVANIA
      ELECTRIC COMPANYCONSOLIDATED
      BALANCE SHEETS(Unaudited)September
      30,
              
              
              December
      31,2008
              
              
              2007(In
      thousands)ASSETSCURRENT
      ASSETS:Cash and cash
      equivalents
              
              $
              36
              
              
              $
              46Receivables-Customers
      (less accumulated provisions of $3,240,000 and $3,905,000respectively,
      for uncollectible accounts)
              
              
              130,427
              
              
              
              137,455Associated
      companies
              
              
              57,715
              
              
              
              22,014Other
              
              
              20,367
              
              
              
              19,529Notes
      receivable from associated companies
              
              
              15,406
              
              
              
              16,313Prepaid
      taxes
              
              
              31,313
              
              
              
              1,796Other
              
              
              494
              
              
              
              1,281255,758
              
              
              
              198,434UTILITY
      PLANT:In
      service
              
              
              2,290,777
              
              
              
              2,219,002Less -
      Accumulated provision for depreciation
              
              
              858,150
              
              
              
              838,6211,432,627
              
              
              
              1,380,381Construction
      work in progress
              
              
              29,503
              
              
              
              24,2511,462,130
              
              
              
              1,404,632OTHER
      PROPERTY AND INVESTMENTS:Nuclear plant
      decommissioning trusts
              
              
              128,594
              
              
              
              137,859Non-utility
      generation trusts
              
              
              115,938
              
              
              
              112,670Other
              
              
              299
              
              
              
              531244,831
              
              
              
              251,060DEFERRED
      CHARGES AND OTHER ASSETS:Goodwill
              
              
              771,085
              
              
              
              777,904Pension
      assets
              
              
              75,992
              
              
              
              66,111Other
              
              
              29,610
              
              
              
              33,893876,687
              
              
              
              877,908$
              2,839,406
              
              
              $
              2,732,034LIABILITIES
      AND CAPITALIZATIONCURRENT
      LIABILITIES:Currently
      payable long-term debt
              
              $
              145,000
              
              
              $
              -Short-term
      borrowings-Associated
      companies
              
              
              30,483
              
              
              
              214,893Other
              
              
              250,000
              
              
              
              -Accounts
      payable-Associated
      companies
              
              
              83,058
              
              
              
              83,359Other
              
              
              47,796
              
              
              
              51,777Accrued
      taxes
              
              
              3,923
              
              
              
              15,111Accrued
      interest
              
              
              14,034
              
              
              
              13,167Other
              
              
              30,297
              
              
              
              25,311604,591
              
              
              
              403,618CAPITALIZATION:Common
      stockholder's equity-Common stock,
      $20 par value, authorized 5,400,000 shares-4,427,577
      shares outstanding
              
              
              88,552
              
              
              
              88,552Other paid-in
      capital
              
              
              914,863
              
              
              
              920,616Accumulated
      other comprehensive income (loss)
              
              
              (899
              )
              
              
              4,946Retained
      earnings
              
              
              50,300
              
              
              
              57,943Total common
      stockholder's equity
              
              
              1,052,816
              
              
              
              1,072,057Long-term debt
      and other long-term obligations
              
              
              632,910
              
              
              
              777,2431,685,726
              
              
              
              1,849,300NONCURRENT
      LIABILITIES:Regulatory
      liabilities
              
              
              104,927
              
              
              
              73,559Asset
      retirement obligations
              
              
              85,748
              
              
              
              81,849Accumulated
      deferred income taxes
              
              
              253,798
              
              
              
              210,776Retirement
      benefits
              
              
              40,864
              
              
              
              41,298Other
              
              
              63,752
              
              
              
              71,634549,089
              
              
              
              479,116COMMITMENTS
      AND CONTINGENCIES (Note 11)$
              2,839,406
              
              
              $
              2,732,034The
      accompanying Notes to Consolidated Financial Statements as they relate to
      Pennsylvania Electric Company arean integral
      part of these statements.
  94
   PENNSYLVANIA
      ELECTRIC COMPANYCONSOLIDATED
      STATEMENTS OF CASH FLOWS(Unaudited)Nine
      MonthsEnded
      September 302008
              
              
              2007(In
      thousands)CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      income
              
              $
              62,357
              
              
              $
              74,237Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
              
              
              40,531
              
              
              
              36,678Amortization
      of regulatory assets, net
              
              
              55,346
              
              
              
              32,648Deferred costs
      recoverable as regulatory assets
              
              
              (20,304
              )
              
              
              (54,228
              )Deferred
      income taxes and investment tax credits, net
              
              
              68,377
              
              
              
              8,065Accrued
      compensation and retirement benefits
              
              
              (21,190
              )
              
              
              (16,032
              )Cash
      collateral
              
              
              -
              
              
              
              50Pension trust
      contribution
              
              
              -
              
              
              
              (13,436
              )Decrease
      (increase) in operating assets-Receivables
              
              
              (42,971
              )
              
              
              13,809Prepayments
      and other current assets
              
              
              (28,730
              )
              
              
              (4,757
              )Increase
      (decrease) in operating liabilities-Accounts
      payable
              
              
              (3,437
              )
              
              
              14,299Accrued
      taxes
              
              
              (11,521
              )
              
              
              (4,930
              )Accrued
      interest
              
              
              867
              
              
              
              6,608Other
              
              
              14,663
              
              
              
              9,197Net cash
      provided from operating activities
              
              
              113,988
              
              
              
              102,208CASH
      FLOWS FROM FINANCING ACTIVITIES:New
      Financing-Long-term
      debt
              
              
              45,000
              
              
              
              297,149Short-term
      borrowings, net
              
              
              65,590
              
              
              
              53,082Redemptions
      and Repayments-Long-term
      debt
              
              
              (45,332
              )
              
              
              -Common
      stock
              
              
              -
              
              
              
              (200,000
              )Dividend
      Payments-Common
      stock
              
              
              (70,000
              )
              
              
              (125,000
              )Net cash
      provided from (used for) financing activities
              
              
              (4,742
              )
              
              
              25,231CASH
      FLOWS FROM INVESTING ACTIVITIES:Property
      additions
              
              
              (94,810
              )
              
              
              (70,076
              )Loan
      repayments from associated companies, net
              
              
              907
              
              
              
              2,378Sales of
      investment securities held in trust
              
              
              84,499
              
              
              
              94,292Purchases of
      investment securities held in trust
              
              
              (96,950
              )
              
              
              (150,711
              )Other
              
              
              (2,902
              )
              
              
              (3,328
              )Net cash used
      for investing activities
              
              
              (109,256
              )
              
              
              (127,445
              )Net decrease
      in cash and cash equivalents
              
              
              (10
              )
              
              
              (6
              )Cash and cash
      equivalents at beginning of period
              
              
              46
              
              
              
              44Cash and cash
      equivalents at end of period
              
              $
              36
              
              
              $
              38The
      accompanying Notes to Consolidated Financial Statements as they relate to
      Pennsylvania Electric Company arean integral
      part of these statements.





95










COMBINED
MANAGEMENT’S DISCUSSION


AND
ANALYSIS OF REGISTRANT SUBSIDIARIES








The following is a
combined presentation of certain disclosures referenced in Management’s
Narrative Analysis of Results of Operations of FES and the Utilities. This
information should be read in conjunction with (i) FES’ and the Utilities’
respective Consolidated Financial Statements and Management’s Narrative Analysis
of Results of Operations; (ii) the Combined Notes to Consolidated Financial
Statements as they relate to FES and the Utilities; and (iii) FES’ and the
Utilities’ respective 2007 Annual Reports on Form 10-K.





Regulatory
Matters(Applicable to each of
the Utilities)





In Ohio, New Jersey
and Pennsylvania, laws applicable to electric industry restructuring contain
similar provisions that are reflected in the Utilities' respective state
regulatory plans. These provisions include:





·
            restructuring
      the electric generation business and allowing the Utilities' customers to
      select a competitive electric generation supplier other than the
      Utilities;·
            establishing
      or defining the PLR obligations to customers in the Utilities' service
      areas;·
            providing the
      Utilities with the opportunity to recover certain costs not otherwise
      recoverable in a competitive generation market;·
            itemizing
      (unbundling) the price of electricity into its component elements –
      including generation, transmission, distribution and stranded costs
      recovery charges;·
            continuing
      regulation of the Utilities' transmission and distribution systems;
      and·
            requiring
      corporate separation of regulated and unregulated business
      activities.





The Utilities and
ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU
have authorized for recovery from customers in future periods or for which
authorization is probable. Without the probability of such authorization, costs
currently recorded as regulatory assets would have been charged to income as
incurred. Regulatory assets that do not earn a current return as of
September 30, 2008 were $64 million for JCP&L and $64 million for
Met-Ed. Regulatory assets not earning a current return are expected to be
recovered by 2014 for JCP&L and by 2020 for Met-Ed. The following table
discloses regulatory assets by company:





September
      30,
            
            December
      31,
            
            IncreaseRegulatory
      Assets*
            
            2008
            
            2007
            
            (Decrease)(In
      millions)OE
            
            $
            621
            
            $
            737
            
            $
            (116
            )CEI
            
            
            796
            
            
            871
            
            
            (75
            )TE
            
            
            145
            
            
            204
            
            
            (59
            )JCP&L
            
            
            1,295
            
            
            1,596
            
            
            (301
            )Met-Ed
            
            
            541
            
            
            495
            
            
            46ATSI
            
            
            35
            
            
            42
            
            
            (7
            )Total
            
            $
            3,433
            
            $
            3,945
            
            $
            (512
            )





*
            Penelec had
      net regulatory liabilities of approximately $105 million and
      $74 million as of September 30, 2008 and December 31, 2007,
      respectively. These net regulatory liabilities are included in Other
      Non-current Liabilities on the Consolidated Balance
  Sheets.








96








Ohio(Applicable to OE, CEI and TE)





On January 4,
2006, the PUCO issued an order authorizing the Ohio Companies to recover certain
increased fuel costs through a fuel rider and to defer certain other increased
fuel costs to be incurred from January 1, 2006 through December 31,
2008, including interest on the deferred balances. The order also provided for
recovery of the deferred costs over a twenty-five-year period through
distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that
the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio
Companies “to collect deferred increased fuel costs through future distribution
rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred
distribution-related expenses” and remanded the matter to the PUCO for further
consideration. On September 10, 2007 the Ohio Companies filed an
application with the PUCO that requested the implementation of two
generation-related fuel cost riders to collect the increased fuel costs that
were previously authorized to be deferred. On January 9, 2008 the PUCO
approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel
costs to be incurred in 2008 commencing January 1, 2008 through
December 31, 2008, which is expected to be approximately $189 million
(OE - $92 million, CEI - $69 million and TE - $28 million). In
addition, the PUCO ordered the Ohio Companies to file a separate application for
an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel
costs. On February 8, 2008, the Ohio Companies filed an application
proposing to recover $226 million (OE - $114 million, CEI - $79 million and
TE - $33 million) of deferred fuel costs and carrying charges for 2006 and 2007
pursuant to a separate fuel rider. Recovery of the deferred fuel costs is
addressed in the Ohio Companies’ comprehensive ESP filing, as described below.
If the recovery of the deferred fuel costs is not resolved in the ESP, or in the
event the MRO is implemented, recovery of the deferred fuel costs will be
resolved in the proceeding that was instituted with the PUCO on February 8,
2008, as referenced above.





On June 7, 2007, the
Ohio Companies filed an application for an increase in electric distribution
rates with the PUCO and, on August 6, 2007, updated their filing to support
a distribution rate increase of $332 million (OE - $156 million,
CEI - $108 million and TE - $68 million). On December 4, 2007,
the PUCO Staff issued its Staff Reports containing the results of its
investigation into the distribution rate request. In its reports, the PUCO Staff
recommended a distribution rate increase in the range of $161 million to
$180 million (OE - $57 million to $66 million, CEI -
$54 million to $61 million and TE - $50 million to
$53 million), with $108 million to $127 million for distribution
revenue increases and $53 million for recovery of costs deferred under
prior cases. Evidentiary hearings began on January 29, 2008 and continued
through February 25, 2008. During the evidentiary hearings and filing of
briefs, the PUCO Staff decreased their recommended revenue increase to a range
of $117 million to $135 million. Additionally, in testimony submitted
on February 11, 2008, the PUCO Staff adopted a position regarding interest
deferred for RCP-related deferrals, line extension deferrals and transition tax
deferrals that, if upheld by the PUCO, would result in the write-off of
approximately $58 million (OE - $38 million, CEI - $13 million
and TE - $7 million) of interest costs deferred through September 30, 2008.
The Ohio Companies’ electric distribution rate request is addressed in their
comprehensive ESP filing, as described below.





On May 1, 2008,
Governor Strickland signed SB221, which became effective on July 31, 2008.
The bill requires all utilities to file an ESP with the PUCO. A utility also may
file an MRO in which it would have to prove the following objective market
criteria:





·
            the utility or
      its transmission service affiliate belongs to a FERC approved RTO, or
      there is comparable and nondiscriminatory access to the electric
      transmission grid;





·
            the RTO has a
      market-monitor function and the ability to mitigate market power or the
      utility’s market conduct, or a similar market monitoring function exists
      with the ability to identify and monitor market conditions and conduct;
      and





·
            a published
      source of information is available publicly or through subscription that
      identifies pricing information for traded electricity products, both on-
      and off-peak, scheduled for delivery two years into the
      future.





On July 31, 2008,
the Ohio Companies filed with the PUCO a comprehensive ESP and MRO. The MRO
outlines a CBP that would be implemented if the ESP is not approved by the PUCO.
Under SB221, a PUCO ruling on the ESP filing is required within 150 days and an
MRO decision is required within 90 days. The ESP proposes to phase in new
generation rates for customers beginning in 2009 for up to a three-year period
and would resolve the Ohio Companies’ collection of fuel costs deferred in 2006
and 2007, and the distribution rate request described above. Major provisions of
the ESP include:





·
            a phase-in of
      new generation rates for up to a three-year period, whereby customers
      would receive a 10% phase-in credit; related costs (expected to
      approximate $429 million (OE - $198 million, CEI - $150 million and TE -
      $81 million) in 2009, $488 million (OE - $226 million, CEI - $170 million
      and TE - $92 million) in 2010 and $553 million (OE - $257 million, CEI -
      $193 million and TE - $103 million) in 2011) would be deferred for future
      collection over a period not to exceed 10
years;





·
            a reconcilable
      rider to recover fuel transportation cost surcharges in excess of $30
      million in 2009, $20 million in 2010 and $10 million in
    2011;





97








·
            generation
      rate adjustments to recover any increase in fuel costs in 2011 over fuel
      costs incurred in 2010 for FES’ generation assets used to support the
      ESP;





·
            generation
      rate adjustments to recover the costs of complying with new requirements
      for certain renewable energy resources, new taxes and new environmental
      laws or new interpretations of existing laws that take effect after
      January 1, 2008 and exceed $50 million during the plan
    period;





·
            an RCP fuel
      rider to recover the 2006 and 2007 deferred fuel costs and carrying
      charges (described above) over a period not to exceed 25
      years;





·
            the resolution
      of outstanding issues pending in the Ohio Companies’ distribution rate
      case (described above), including annual electric distribution rate
      increases of $75 million for OE, $34.5 million for CEI and $40.5 million
      for TE. The new distribution rates would be effective January 1, 2009, for
      OE and TE and May 1, 2009 for CEI, with a commitment to maintain
      distribution rates through 2013. CEI also would be authorized to defer $25
      million in distribution-related costs incurred from January 1, 2009,
      through April 30, 2009;





·
            an adjustable
      delivery service improvement rider, effective January 1, 2009, through
      December 31, 2013, to ensure the Ohio Companies maintain and improve
      customer standards for service and
reliability;





·
            the waiver of
      RTC charges for CEI’s customers as of January 1, 2009, which would
      result in CEI’s write-off of approximately $485 million of estimated
      unrecoverable transition costs;





·
            the continued
      recovery of transmission costs, including MISO, ancillary services and
      congestion charges, through an annually adjusted transmission rider; a
      separate rider will be established to recover costs incurred annually
      between May 1st
      and September 30th
      for capacity purchases required to meet FERC, NERC, MISO and other
      applicable standards for planning reserve margin requirements in excess of
      amounts provided by FES as described in the ESP (the separate application
      for the recovery of these costs was filed on October 17,
      2008);





·
            a deferred
      transmission cost recovery rider effective January 1, 2009, through
      December 31, 2010 to recover transmission costs deferred by the Ohio
      Companies in 2005 and accumulated carrying charges through December 31,
      2008; a deferred distribution cost recovery rider effective
      January 1, 2011, to recover distribution costs deferred under the
      RCP, CEI’s additional $25 million of cost deferrals in 2009, line
      extension deferrals and transition tax
  deferrals;





·
            the deferral
      of annual storm damage expenses in excess of $13.9 million, certain line
      extension costs, as well as depreciation, property tax obligations and
      post in-service carrying charges on energy delivery capital investments
      for reliability and system efficiency placed in service after December 31,
      2008. Effective January 1, 2014, a rider will be established to collect
      the deferred balance and associated carrying charges over a 10-year
      period; and





·
            a commitment
      by the Ohio Companies to invest in aggregate at least $1 billion in
      capital improvements in their energy delivery systems through 2013 and
      fund $25 million for energy efficiency programs and $25 million
      for economic development and job retention programs through
      2013.





Evidentiary hearings
in the ESP case concluded on October 31, 2008 and no further hearings are
scheduled. The parties are required to submit initial briefs by November 21,
2008, with all reply briefs due by December 12, 2008.





The Ohio Companies’
MRO filing outlines a CBP for providing retail generation supply if the ESP is
not approved by the PUCO or is changed and not accepted by the Ohio Companies.
The CBP would use a “slice-of-system” approach where suppliers bid on tranches
(approximately 100 MW) of the Ohio Companies’ total customer load. If the Ohio
Companies proceed with the MRO option, successful bidders (including affiliates)
would be required to post independent credit requirements and could be subject
to significant collateral calls depending upon power price movement. On
September 16, 2008, the PUCO staff filed testimony and evidentiary hearings
were held. The PUCO failed to act on October 29, 2008 as required under the
statute.  The Ohio Companies are unable to predict the outcome of this
proceeding.





The Ohio Companies
included an interim pricing proposal as part of their ESP filing, if additional
time is necessary for final PUCO approval of either the ESP or MRO. FES will be
required to obtain FERC authorization to sell electric capacity or energy to the
Ohio Companies under the ESP or MRO, unless a waiver is obtained (see FERC
Matters).





98








Pennsylvania(Applicable to FES, Met-Ed, Penelec, OE and Penn)





Met-Ed and Penelec
purchase a portion of their PLR and default service requirements from FES
through a fixed-price partial requirements wholesale power sales agreement. The
agreement allows Met-Ed and Penelec to sell the output of NUG energy to the
market and requires FES to provide energy at fixed prices to replace any NUG
energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and
default service obligations. The fixed price under the agreement is expected to
remain below wholesale market prices during the term of the agreement. If Met-Ed
and Penelec were to replace the entire FES supply at current market power prices
without corresponding regulatory authorization to increase their generation
prices to customers, each company would likely incur a significant increase in
operating expenses and experience a material deterioration in credit quality
metrics. Under such a scenario, each company's credit profile would no longer be
expected to support an investment grade rating for their fixed income
securities. Based on the PPUC’s January 11, 2007 order described below, if
FES ultimately determines to terminate, reduce, or significantly modify the
agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps
in 2010, timely regulatory relief is not likely to be granted by the PPUC. See
FERC Matters below for a description of the Third Restated Partial Requirements
Agreement, executed by the parties on October 31, 2008, that limits
the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the
event of a third party supplier default, the increased costs to Met-Ed and
Penelec could be material.


Met-Ed and Penelec
made a comprehensive transition rate filing with the PPUC on April 10, 2006
to address a number of transmission, distribution and supply issues. If Met-Ed's
and Penelec's preferred approach involving accounting deferrals had been
approved, annual revenues would have increased by $216 million and
$157 million, respectively. That filing included, among other things, a
request to charge customers for an increasing amount of market-priced power
procured through a CBP as the amount of supply provided under the then existing
FES agreement was to be phased out. Met-Ed and Penelec also requested approval
of a January 12, 2005 petition for the deferral of transmission-related
costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested
recovery of annual transmission and related costs incurred on or after
January 1, 2007, plus the amortized portion of 2006 costs over a ten-year
period, along with applicable carrying charges, through an adjustable rider.
Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG
stranded costs were also included in the filing. On May 4, 2006, the PPUC
consolidated the remand of the FirstEnergy and GPU merger proceeding, related to
the quantification and allocation of merger savings, with the comprehensive
transition rate filing case.





The PPUC entered its
opinion and order in the comprehensive rate filing proceeding on
January 11, 2007. The order approved the recovery of transmission costs,
including the transmission-related deferral for January 1, 2006 through
January 10, 2007, and determined that no merger savings from prior years
should be considered in determining customers’ rates. The request for increases
in generation supply rates was denied as were the requested changes to NUG
expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased
Met-Ed’s and Penelec’s distribution rates by $80 million and
$19 million, respectively. These decreases were offset by the increases
allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request
for recovery of Saxton decommissioning costs was granted and, in January 2007,
Met-Ed and Penelec recognized income of $15 million and $12 million,
respectively, to establish regulatory assets for those previously expensed
decommissioning costs. Overall rates increased by 5.0% for Met-Ed
($59 million) and 4.5% for Penelec ($50 million).





On March 30, 2007,
MEIUG and PICA filed a Petition for Review with the Commonwealth Court of
Pennsylvania asking the Court to review the PPUC’s determination on transmission
(including congestion) and the transmission deferral. Met-Ed and Penelec filed a
Petition for Review on April 13, 2007 on the issues of consolidated tax savings
and the requested generation rate increase. The OCA filed its Petition for
Review on April 13, 2007, on the issues of transmission (including
congestion) and recovery of universal service costs from only the residential
rate class. From June through October 2007, initial responsive and reply briefs
were filed by various parties. The Commonwealth
Court issued its decision on November 7, 2008, which affirmed the PPUC's
January 11, 2007 order in all respects, including the deferral and recovery
of transmission and congestion related costs.





On May 22, 2008, the
PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the
period June 1, 2008, through May 31, 2009. Various intervenors filed
complaints against Met-Ed’s and Penelec’s TSC filings.  In addition,
the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC,
while at the same time allowing the company to implement the rider June 1,
2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to
consolidate the complaints against Met-Ed with its investigation and a
litigation schedule was adopted with hearings for both companies scheduled to
begin in January 2009. The TSCs include a component for under-recovery of actual
transmission costs incurred during the prior period (Met-Ed - $144 million
and Penelec - $4 million) and future transmission cost projections for June 2008
through May 2009 (Met-Ed - $258 million and Penelec - $92 million).
Met-Ed received approval from the PPUC of a transition approach that would
recover past under-recovered costs plus carrying charges through the new TSC
over thirty-one months and defer a portion of the projected costs
($92 million) plus carrying charges for recovery through future TSCs by
December 31, 2010.





99




On February 1, 2007,
the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of
proposed legislation that, according to the Governor, is designed to reduce
energy costs, promote energy independence and stimulate the economy. Elements of
the EIS include the installation of smart meters, funding for solar panels on
residences and small businesses, conservation and demand reduction programs to
meet energy growth, a requirement that electric distribution companies acquire
power that results in the “lowest reasonable rate on a long-term basis,” the
utilization of micro-grids and a three year phase-in of rate increases. On
July 17, 2007 the Governor signed into law two pieces of energy
legislation. The first amended the Alternative Energy Portfolio Standards Act of
2004 to, among other things, increase the percentage of solar energy that must
be supplied at the conclusion of an electric distribution company’s transition
period. The second law allows electric distribution companies, at their sole
discretion, to enter into long term contracts with large customers and to build
or acquire interests in electric generation facilities specifically to supply
long-term contracts with such customers. A special legislative session on energy
was convened in mid-September 2007 to consider other aspects of the EIS. The
Pennsylvania House and Senate on March 11, 2008 and December 12, 2007,
respectively, passed different versions of bills to fund the Governor’s EIS
proposal. As part of the 2008 state budget negotiations, the Alternative Energy
Investment Act was enacted creating a $650 million alternative energy fund to
increase the development and use of alternative and renewable energy, improve
energy efficiency and reduce energy consumption.  On October 8, 2008,
House Bill 2200 as amended, was voted out of the full Senate and adopted by the
House. On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200
into law which becomes effective on November 14, 2008 as Act 129 of
2008.  The bill addresses issues such as: energy efficiency and peak
load reduction; generation procurement; time-of-use rates; smart meters and
alternative energy.  Act 129 requires
utilities to file with the PPUC an energy efficiency and peak load reduction
plan by July 1, 2009 and a smart meter procurement and installation plan by
August 14, 2009.




Major provisions of
the legislation include:




·
              power acquired
      by utilities to serve customers after rate caps expire will be procured
      through a competitive procurement process that must include a mix of
      long-term and short-term contracts and spot market
    purchases;
 
 ·
              the
      competitive procurement process must be approved by the PPUC and may
      include auctions, request for proposals, and/or bilateral
      agreements;
 
 ·
              utilities must
      provide for the installation of smart meter technology within 15
      years;
 
 ·
              a minimum
      reduction in peak demand of 4.5% by May 31,
  2013;
 
 ·
              minimum
      reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31,
      2013, respectively; and
 
 ·
              an expanded
      definition of alternative energy to include additional types of
      hydroelectric and biomass
facilities.
 The current
legislative session ends on November 30, 2008, and any pending legislation
addressing rate mitigation and the expiration of rate caps not enacted by that
time must be re-introduced in order to be considered in the next legislative
session which begins in January 2009.  While the form and impact of
such legislation is uncertain, several legislators and the Governor have
indicated their intent to address these issues next year.





On September 25,
2008, Met-Ed and Penelec filed for Commission approval of a Voluntary Prepayment
Plan that would provide an opportunity for residential and small commercial
customers to pre-pay an amount, which would earn interest at 7.5%, on their
monthly electric bills in 2009 and 2010, to be used to reduce electric rates in
2011 and 2012. Met-Ed and Penelec also intend to file a generation procurement
plan for 2011 and beyond with the PPUC later this year or early next year.
Met-Ed and Penelec requested that the PPUC approve the Plan by mid-December 2008
and are currently awaiting a decision.





New Jersey(Applicable to JCP&L)





JCP&L is
permitted to defer for future collection from customers the amounts by which its
costs of supplying BGS to non-shopping customers and costs incurred under NUG
agreements exceed amounts collected through BGS and NUGC rates and market sales
of NUG energy and capacity. As of September 30, 2008, the accumulated
deferred cost balance totaled approximately $210 million.





In accordance with
an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7,
2004 supporting continuation of the current level and duration of the funding of
TMI-2 decommissioning costs by New Jersey customers without a reduction,
termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study. This study resulted in an updated
total decommissioning cost estimate of $729 million (in 2003 dollars)
compared to the estimated $528 million (in 2003 dollars) from the prior
1995 decommissioning study. The DRA filed comments on February 28, 2005
requesting that decommissioning funding be suspended. On March 18, 2005,
JCP&L filed a response to those comments. JCP&L responded to additional
NJBPU staff discovery requests in May and November 2007 and also submitted
comments in the proceeding in November 2007. A schedule for further NJBPU
proceedings has not yet been set.





100








On August 1, 2005,
the NJBPU established a proceeding to determine whether additional ratepayer
protections are required at the state level in light of the repeal of the PUHCA
pursuant to the EPACT. The NJBPU approved regulations effective October 2,
2006 that prevent a holding company that owns a gas or electric public utility
from investing more than 25% of the combined assets of its utility and
utility-related subsidiaries into businesses unrelated to the utility industry.
These regulations are not expected to materially impact JCP&L. Also, in the
same proceeding, the NJBPU Staff issued an additional draft proposal on
March 31, 2006 addressing various issues including access to books and
records, ring-fencing, cross subsidization, corporate governance and related
matters. With the approval of the NJBPU Staff, the affected utilities jointly
submitted an alternative proposal on June 1, 2006. The NJBPU Staff
circulated revised drafts of the proposal to interested stakeholders in November
2006 and again in February 2007. On February 1, 2008, the NJBPU accepted
proposed rules for publication in the New Jersey Register on March 17,
2008. A public hearing on these proposed rules was held on April 23, 2008
and comments from interested parties were submitted by May 19,
2008.





New Jersey statutes
require that the state periodically undertake a planning process, known as the
EMP, to address energy related issues including energy security, economic
growth, and environmental impact. The EMP is to be developed with involvement of
the Governor’s Office and the Governor’s Office of Economic Growth, and is to be
prepared by a Master Plan Committee, which is chaired by the NJBPU President and
includes representatives of several State departments. In October 2006, the
current EMP process was initiated through the creation of a number of working
groups to obtain input from a broad range of interested stakeholders including
utilities, environmental groups, customer groups, and major customers. In
addition, public stakeholder meetings were held in 2006, 2007 and the first half
of 2008.





On April 17, 2008, a
draft EMP was released for public comment. The final EMP was issued on October
22, 2008 and establishes five major goals:





·
            maximize
      energy efficiency to achieve a 20% reduction in energy consumption by
      2020;





·
            reduce peak
      demand for electricity by 5,700 MW by
2020;





·
            meet 30% of
      the state’s electricity needs with renewable energy by
    2020;





·
            examine smart
      grid technology and develop additional cogeneration and other generation
      resources consistent with the state’s greenhouse gas targets;
      and





·
            invest in
      innovative clean energy technologies and businesses to stimulate the
      industry’s growth in New Jersey.





The final EMP will
be followed by appropriate legislation and regulation as necessary. At this
time, JCP&L cannot predict the outcome of this process nor determine the
impact, if any, such legislation or regulation may have on its
operations.





FERC Matters(Applicable to FES and each of the Utilities)




Transmission
Service between MISO and PJM





On November 18,
2004, the FERC issued an order eliminating the through and out rate for
transmission service between the MISO and PJM regions. The FERC’s intent was to
eliminate multiple transmission charges for a single transaction between the
MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission
owners within MISO and PJM to submit compliance filings containing a rate
mechanism to recover lost transmission revenues created by elimination of this
charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a
16-month transition period. The FERC issued orders in 2005 setting the SECA for
hearing. The presiding judge issued an initial decision on August 10, 2006,
rejecting the compliance filings made by MISO, PJM, and the transmission owners,
and directing new compliance filings. This decision is subject to review and
approval by the FERC. Briefs addressing the initial decision were filed on
September 11, 2006 and October 20, 2006. A final order could be issued by
the FERC by year-end 2008.  In the meantime, FirstEnergy affiliates
have been negotiating and entering into settlement agreements with other parties
in the docket to mitigate the risk of lower transmission revenue collection
associated with an adverse order.  On September 26, 2008, the
MISO and PJM transmission owners filed a motion requesting that the FERC approve
the pending settlements and act on the initial decision.





101








PJM Transmission Rate
Design





On January 31, 2005,
certain PJM transmission owners made filings with the FERC pursuant to a
settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
Penelec were parties to that proceeding and joined in two of the filings. In the
first filing, the settling transmission owners submitted a filing justifying
continuation of their existing rate design within the PJM RTO. Hearings were
held and numerous parties appeared and litigated various issues concerning PJM
rate design; notably AEP, which proposed to create a "postage stamp", or average
rate for all high voltage transmission facilities across PJM and a zonal
transmission rate for facilities below 345 kV. This proposal would have the
effect of shifting recovery of the costs of high voltage transmission lines to
other transmission zones, including those where JCP&L, Met-Ed, and Penelec
serve load. On April 19, 2007, the FERC issued an order finding that the
PJM transmission owners’ existing “license plate” or zonal rate design was just
and reasonable and ordered that the current license plate rates for existing
transmission facilities be retained. On the issue of rates for new transmission
facilities, the FERC directed that costs for new transmission facilities that
are rated at 500 kV or higher are to be collected from all transmission zones
throughout the PJM footprint by means of a postage-stamp rate. Costs for new
transmission facilities that are rated at less than 500 kV, however, are to be
allocated on a “beneficiary pays” basis. The FERC found that PJM’s current
beneficiary-pays cost allocation methodology is not sufficiently detailed and,
in a related order that also was issued on April 19, 2007, directed that
hearings be held for the purpose of establishing a just and reasonable cost
allocation methodology for inclusion in PJM’s tariff.





On May 18, 2007,
certain parties filed for rehearing of the FERC’s April 19, 2007 order. On
January 31, 2008, the requests for rehearing were denied. The FERC’s orders
on PJM rate design will prevent the allocation of a portion of the revenue
requirement of existing transmission facilities of other utilities to JCP&L,
Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new
500 kV and above transmission facilities on a PJM-wide basis will reduce the
costs of future transmission to be recovered from the JCP&L, Met-Ed and
Penelec zones. A partial settlement agreement addressing the “beneficiary pays”
methodology for below 500 kV facilities, but excluding the issue of allocating
new facilities costs to merchant transmission entities, was filed on September
14, 2007. The agreement was supported by the FERC’s Trial Staff, and was
certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued
an order conditionally approving the settlement subject to the submission of a
compliance filing.  The compliance filing was submitted on
August 29, 2008, and the FERC issued an order accepting the compliance
filing on October 15, 2008.  The remaining merchant transmission cost
allocation issues were the subject of a hearing at the FERC in May
2008.  An initial decision was issued by the Presiding Judge on
September 18, 2008.  PJM and FERC trial staff each filed a Brief on
Exceptions to the initial decision on October 20, 2008.  Briefs
Opposing Exceptions are due on November 10, 2008. On February 11,
2008, AEP appealed the FERC’s April 19, 2007 and January 31, 2008 orders to
the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce
Commission, the PUCO and Dayton Power & Light have also appealed these
orders to the Seventh Circuit Court of Appeals. The appeals of these parties and
others have been consolidated for argument in the Seventh Circuit.





Post
Transition Period Rate Design





The FERC had
directed MISO, PJM, and the respective transmission owners to make filings on or
before August 1, 2007 to reevaluate transmission rate design within MISO, and
between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the
vast majority of transmission owners, including FirstEnergy affiliates, which
proposed to retain the existing transmission rate design. These filings were
approved by the FERC on January 31, 2008. As a result of the FERC’s approval,
the rates charged to FirstEnergy’s load-serving affiliates for transmission
service over existing transmission facilities in MISO and PJM are unchanged. In
a related filing, MISO and MISO transmission owners requested that the current
MISO pricing for new transmission facilities that spreads 20% of the cost of new
345 kV and higher transmission facilities across the entire MISO footprint
(known as the RECB methodology) be retained.





On September 17, 2007, AEP filed a
complaint under Sections 206 and 306 of the Federal Power Act seeking to have
the entire transmission rate design and cost allocation methods used by MISO and
PJM declared unjust, unreasonable, and unduly discriminatory, and to have the
FERC fix a uniform regional transmission rate design and cost allocation method
for the entire MISO and PJM “Super Region” that recovers the average cost of new
and existing transmission facilities operated at voltages of 345 kV and above
from all transmission customers. Lower voltage facilities would continue to be
recovered in the local utility transmission rate zone through a license plate
rate. AEP requested a refund effective October 1, 2007, or alternatively,
February 1, 2008. On January 31, 2008, the FERC issued an order denying the
complaint. The effect of this order is to prevent the shift of significant costs
to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP is pending
before the FERC.





102








MISO Ancillary Services Market and
Balancing Area Consolidation





MISO made a filing
on September 14, 2007 to establish an ASM for regulation, spinning and
supplemental reserves, to consolidate the existing 24 balancing areas within the
MISO footprint, and to establish MISO as the NERC registered balancing authority
for the region. These markets would permit generators to sell, and load-serving
entities to purchase, their operating reserve requirements in a competitive
market. FirstEnergy supports the proposal to establish markets for Ancillary
Services and consolidate existing balancing areas. On February 25, 2008, the
FERC issued an order approving the ASM subject to certain compliance filings.
Numerous parties filed requests for rehearing on March 26, 2008. On
June 23, 2008, the FERC issued an order granting in part and denying in
part rehearing.





On February 29,
2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor
ASM and Consolidated Balancing Authority Initiative Verification plan and status
and Real-Time Operations ASM Reversion plan. FERC action on this compliance
filing remains pending. On March 26, 2008, MISO submitted a tariff filing in
compliance with the FERC’s 30-day directives in the February 25 order. Numerous
parties submitted comments and protests on April 16, 2008. The FERC issued an
order accepting the revisions pending further compliance on June 23, 2008. On
April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s
60-day directives in the February 25 order. FERC action on this compliance
filing remains pending. On May 23, 2008, MISO submitted its amended Balancing
Authority Agreement. On July 21, 2008, the FERC issued an order conditionally
accepting the amended Balancing Authority Agreement and requiring a further
compliance filing.  On August 19, 2008, MISO submitted its compliance
filing to the FERC.  On July 25, 2008, MISO submitted another
Readiness Certification.  The FERC has not yet acted on this
submission.  MISO announced on August 26, 2008 that the startup
of its market is postponed indefinitely.  MISO commits to make a
filing giving at least sixty days notice of the new effective date. The latest
announced effective date for market startup is January 6, 2009.





Interconnection
Agreement with AMP-Ohio





On May 29, 2008, TE
filed with the FERC a proposed Notice of Cancellation effective midnight
December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio
protested this filing. TE also filed a Petition for Declaratory Order seeking a
FERC ruling, in the alternative if cancellation is not accepted, of TE's right
to file for an increase in rates effective January 1, 2009, for power
provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a
pleading agreeing that TE may seek an increase in rates, but arguing that any
increase is limited to the cost of generation owned by TE affiliates. On
August 18, 2008, the FERC issued an order that suspended the cancellation
of the Agreement for five months, to become effective on June 1, 2009, and
established expedited hearing procedures on issues raised in the filing and TE’s
Petition for Declaratory Order. On October 14, 2008, the parties filed a
settlement agreement and mutual notice of cancellation of the Interconnection
Agreement effective midnight December 31, 2008.  Upon acceptance by
the FERC, this filing will terminate the litigation and the Interconnection
Agreement, among other effects.





Duquesne’s
Request to Withdraw from PJM





On November 8, 2007,
Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and
to join MISO. In its filing, Duquesne asked the FERC to be relieved of certain
capacity payment obligations to PJM for capacity auctions conducted prior to its
departure from PJM, but covering service for planning periods through
May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is
to avoid paying future obligations created by PJM’s forward capacity market. On
January 17, 2008, the FERC conditionally approved Duquesne’s request to
exit PJM. Among other conditions, the FERC obligated Duquesne zone load-serving
entities to pay their PJM capacity obligations through May 31,
2011.





FirstEnergy desires
to continue to use its Duquesne zone generation resources to serve load in PJM.
On April 18, 2008, the FERC issued its Order on Motion for Emergency
Clarification on whether Duquesne-zone generators could participate in PJM’s May
2008 auction for the 2011-2012 planning year. In the order, the FERC ruled
that although the status of the Duquesne-zone generators will change to
“External Resource” upon Duquesne’s exit from PJM, these generators could
contract with PJM for the transmission reservations necessary to participate in
the May 2008 auction. FirstEnergy has complied with the FERC’s order by
obtaining executed transmission service agreements for firm point-to-point
transmission service for the 2011-2012 delivery year and, as such, FirstEnergy
satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM
auction.





The FERC also
directed MISO and PJM to resolve the substantive and procedural issues
associated with Duquesne’s transition into MISO. As directed, PJM filed thirteen
load-serving entity Capacity Payment Agreements and a Capacity Portability
Agreement with the FERC. The Capacity Payment Agreements addressed Duquesne Zone
load-serving entity obligations through May 31, 2011 with regards to RPM
Capacity while the Capacity Portability Agreement addressed operational issues
associated with the portability of such capacity. On September 30, 2008, the
FERC approved both agreements, subject to conditions, taking notice of many
operational and procedural issues brought forth by FirstEnergy and other market
participants.





103








Several issues
surrounding Duquesne’s transition into MISO continue to be contested at the
FERC. Specifically, Duquesne’s obligation to pay for transmission expansion
costs allocated to the Duquesne zone when they were a member of PJM, and other
issues in which market participants wish to be held harmless by Duquesne’s
transition. FirstEnergy filed for rehearing on these issues on October 3, 2008.
Duquesne’s transition into MISO is also contingent upon the start of MISO’s
ancillary services market and consolidation of its balancing authorities,
currently scheduled for January 6, 2009.





Complaint
against PJM RPM Auction





On May 30,
2008, a group of PJM load-serving entities, state commissions, consumer
advocates, and trade associations (referred to collectively as the RPM Buyers)
filed a complaint at the FERC against PJM alleging that three of the
four transitional RPM auctions yielded prices that are unjust and
unreasonable under the Federal Power Act. Most of the parties comprising
the RPM Buyers group were parties to the settlement approved by the FERC that
established the RPM. In the complaint, the RPM Buyers request that the
total projected payments to RPM sellers for the three auctions at issue be
materially reduced. On July 11, 2008, PJM filed its answer to the
complaint, in which it denied the allegation that the rates are unjust and
unreasonable. Also on that date, FirstEnergy filed a motion to
intervene.





On September 19,
2008, the FERC denied the RPM Buyers complaint. However, the FERC did grant the
RPM Buyers request for a technical conference to review aspects of the RPM. The
FERC also ordered PJM to file on or before December 15, 2008, a report on
its progress on contemplating adjustments to the RPM as suggested by the Brattle
Group in its report reviewing the RPM. The technical conference will take place
in February, 2009. On October 20, 2008, the RPM Buyers filed a request for
rehearing of the FERC’s September 19, 2008 order.





MISO
Resource Adequacy Proposal





MISO made a filing
on December 28, 2007 that would create an enforceable planning reserve
requirement in the MISO tariff for load-serving entities such as the Ohio
Companies, Penn Power, and FES. This requirement is proposed to become effective
for the planning year beginning June 1, 2009. The filing would permit MISO to
establish the reserve margin requirement for load-serving entities based upon a
one day loss of load in ten years standard, unless the state utility regulatory
agency establishes a different planning reserve for load-serving entities in its
state. FirstEnergy believes the proposal promotes a mechanism that will result
in commitments from both load-serving entities and resources, including both
generation and demand side resources that are necessary for reliable resource
adequacy and planning in the MISO footprint. Comments on the filing were filed
on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy
proposal on March 26, 2008, requiring MISO to submit to further compliance
filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27,
2008, MISO submitted a compliance filing to address issues associated with
planning reserve margins. On June 17, 2008, various parties submitted comments
and protests to MISO’s compliance filing. FirstEnergy submitted comments
identifying specific issues that must be clarified and addressed. On
June 25, 2008, MISO submitted a second compliance filing establishing the
enforcement mechanism for the reserve margin requirement which establishes
deficiency payments for load-serving entities that do not meet the resource
adequacy requirements. Numerous parties, including FirstEnergy, protested this
filing.   On October 20, 2008, the FERC issued three orders
essentially permitting the MISO Resource Adequacy program to proceed with some
modifications.  First, the FERC accepted MISO's financial settlement
approach for enforcement of Resource Adequacy subject to a compliance filing
modifying the cost of new entry penalty. Second, the FERC conditionally accepted
MISO's compliance filing on the qualifications for purchase power agreements to
be capacity resources, load forecasting, loss of load expectation, and planning
reserve zones. Additional compliance filings were directed on accreditation of
load modifying resources and price responsive demand. Finally, the FERC largely
denied rehearing of its March 26 order with the exception of issues related to
behind the meter resources and certain ministerial matters. Issuance of these
orders is not expected to delay the June 1, 2009 start date for MISO
Resource Adequacy.





Organized
Wholesale Power Markets





The FERC issued a
final rule on October 17, 2008, amending its regulations to “improve the
operation of organized wholesale electric markets in the areas of: (1) demand
response and market pricing during periods of operating reserve shortage; (2)
long-term power contracting; (3) market-monitoring policies; and (4) the
responsiveness of RTOs and ISOs to their customers and other
stakeholders.”  The RTOs and ISOs were directed to submit amendments
to their respective tariffs to address these market operation
improvements.  The final rule directs RTOs to adopt market rules
permitting prices to increase during periods of supply shortages and to permit
enhanced participation by demand response resources.  It also codifies
and defines for the first time the roles and duties of independent market
monitors within RTOs.  Finally, it adopts requirements for enhanced
access by stakeholders to RTO boards of directors.  RTOs are directed
to make compliance filings six months from the effective date of the final
rule.  The final rule is not expected to have any material effect on
FirstEnergy's operations within MISO and PJM.





104








FES
Sales to Affiliates





On October 24, 2008,
FES, on its own behalf and on behalf of its generation-controlling subsidiaries,
filed an application with the FERC seeking a waiver of the affiliate sales
restrictions between FES and the Ohio Companies. The purpose of the waiver is to
ensure thatFESwill be able to continue supplying
a material portion of the electric load requirements of the Ohio Companies in
January 2009 pursuant to either an ESP or MRO as filed with the
PUCO. FES previously obtained a similar waiver for electricity sales
to its affiliates in New Jersey, New York, and Pennsylvania.  A ruling
by the FERC is expected the week of December 15, 2008.





On October 31, 2008,
FES executed a Third Restated Partial Requirements Agreement with
Met-Ed, Penelec, and The Waverly Power and Light Company (Waverly)
effective November 1, 2008.  The Third Restated Partial Requirements
Agreement limits the amount of capacity and energy required to be supplied by
FES in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply
requirements. Met-Ed, Penelec, and Waverly have committed resources in
place for the balance of their expected power supply during 2009 and
2010.  Under the Third Restated Partial Requirements Agreement,
Met-Ed, Penelec, and Waverly are responsible for obtaining additional power
supply requirements created by the default or failure of supply of their
committed resources. Prices for the power provided by FES were not changed in
the Third Restated Partial Requirements Agreement.




Environmental
Matters





Various federal,
state and local authorities regulate FES and the Companies with regard to air
and water quality and other environmental matters. The effects of compliance on
FES and the Companies with regard to environmental matters could have a material
adverse effect on their earnings and competitive position to the extent that
they compete with companies that are not subject to such regulations and,
therefore, do not bear the risk of costs associated with compliance, or failure
to comply, with such regulations. FES estimates capital expenditures for
environmental compliance of approximately $1.4 billion for the period
2008-2012.





FES and the
Companies accrue environmental liabilities only when they conclude that it is
probable that they have an obligation for such costs and can reasonably estimate
the amount of such costs. Unasserted claims are reflected in FES’ and the
Companies’ determination of environmental liabilities and are accrued in the
period that they become both probable and reasonably estimable.





Clean Air Act
Compliance(Applicable to FES)





FES is required to
meet federally-approved SO2 emissions
regulations. Violations of such regulations can result in the shutdown of the
generating unit involved and/or civil or criminal penalties of up to $32,500 for
each day the unit is in violation. The EPA has an interim enforcement policy for
SO2
regulations in Ohio that allows for compliance based on a 30-day averaging
period. FES believes it is currently in compliance with this policy, but cannot
predict what action the EPA may take in the future with respect to the interim
enforcement policy.





The EPA Region 5
issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June
15, 2006, alleging violations to various sections of the CAA. FES has disputed
those alleged violations based on its CAA permit, the Ohio SIP and other
information provided to the EPA at an August 2006 meeting with the EPA. The EPA
has several enforcement options (administrative compliance order, administrative
penalty order, and/or judicial, civil or criminal action) and has indicated that
such option may depend on the time needed to achieve and demonstrate compliance
with the rules alleged to have been violated. On June 5, 2007, the EPA
requested another meeting to discuss “an appropriate compliance program” and a
disagreement regarding emission limits applicable to the common stack for Bay
Shore Units 2, 3 and 4.





FES complies with
SO2
reduction requirements under the Clean Air Act Amendments of 1990 by burning
lower-sulfur fuel, generating more electricity from lower-emitting plants,
and/or using emission allowances. NOX reductions
required by the 1990 Amendments are being achieved through combustion controls
and the generation of more electricity at lower-emitting plants. In September
1998, the EPA finalized regulations requiring additional NOX reductions
at FES' facilities. The EPA's NOX Transport
Rule imposes uniform reductions of NOX emissions
(an approximate 85% reduction in utility plant NOX emissions
from projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NOX emissions
are contributing significantly to ozone levels in the eastern United States. FES
believes its facilities are also complying with the NOX budgets
established under SIPs through combustion controls and post-combustion controls,
including Selective Catalytic Reduction and SNCR systems, and/or using emission
allowances.





105








In 1999 and 2000,
the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn
based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR
Litigation) and filed similar complaints involving 44 other U.S. power plants.
This case, along with seven other similar cases, is referred to as the NSR
cases.  OE’s and Penn’s settlement with the EPA, the DOJ and three
states (Connecticut, New Jersey and New York) that resolved all issues related
to the Sammis NSR litigation was approved by the Court on July 11, 2005. This
settlement agreement, in the form of a consent decree, requires reductions of
NOX
and SO2 emissions
at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the
installation of pollution control devices and provides for stipulated penalties
for failure to install and operate such pollution controls in accordance with
that agreement. Capital expenditures necessary to complete requirements of the
Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion
for 2008-2012 ($650 million of which is expected to be spent during 2008,
with the largest portion of the remaining $650 million expected to be spent
in 2009). This amount is included in the estimated capital expenditures for
environmental compliance referenced above. On September 8, 2008, the
Environmental Enforcement Section of the DOJ sent a letter to OE regarding its
view that the company was not in compliance with the Sammis NSR Litigation
consent decree because the installation of an SNCR at Eastlake Unit 5 was not
completed by December 31, 2006. However, the DOJ acknowledged that stipulated
penalties could not apply under the terms of the Sammis NSR Litigation consent
decree because Eastlake Unit 5 was idled on December 31, 2006 pending
installation of the SNCR and advised that it had exercised its discretion not to
seek any other penalties for this alleged non-compliance. OE disputed the DOJ's
interpretation of the consent decree in a letter dated September 22, 2008.
Although the Eastlake Unit 5 issue is no longer active, OE filed a dispute
resolution petition on October 23, 2008, with the United States District
Court for the Southern District of Ohio, due to potential impacts on its
compliance decisions with respect to Burger Units 4 and 5. Under the Sammis NSR
Litigation consent decree, an election to repower by December 31, 2012,
install flue gas desulfurization (FGD) by December 31, 2010, or permanently shut
down those units by December 31, 2010, is due no later than
December 31, 2008. Although FirstEnergy will meet the December 31,
2008 deadline for making an election, one potential compliance option, should
FGD be elected, would be to idle Burger Units 4 and 5 on December 31, 2010
pending completion of the FGD installation. Thus, OE is seeking a determination
by the Court whether this approach is indeed in compliance with the terms of the
Sammis NSR Litigation consent decree. The Court has scheduled a hearing on OE’s
dispute resolution petition for November 17, 2008. The outcome of this
dispute resolution process could have an impact on the option FirstEnergy
ultimately elects with respect to Burger Units 4 and 5.





On April 2,
2007, the United States Supreme Court ruled that changes in annual emissions (in
tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must
be used to determine whether an emissions increase triggers NSR. Subsequently,
on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize
changes in the hourly emission rate (in kilograms/hour) to determine whether an
emissions increase triggers NSR. The EPA has not yet issued a final regulation.
FGCO’s future cost of compliance with those regulations may be substantial and
will depend on how they are ultimately implemented.





On May 22, 2007,
FirstEnergy and FGCO received a notice letter, required 60 days prior to the
filing of a citizen suit under the federal CAA, alleging violations of air
pollution laws at the Bruce Mansfield Plant, including opacity limitations.
Prior to the receipt of this notice, the Plant was subject to a Consent Order
and Agreement with the Pennsylvania Department of Environmental Protection
concerning opacity emissions under which efforts to achieve compliance with the
applicable laws will continue. On October 18, 2007, PennFuture filed a
complaint, joined by three of its members, in the United States District Court
for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy
filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008,
the Court denied the motion to dismiss, but also ruled that monetary damages
could not be recovered under the public nuisance claim. In July 2008, three
additional complaints were filed against FGCO in the United States District
Court for the Western District of Pennsylvania seeking damages based on Bruce
Mansfield Plant air emissions. In addition to seeking damages, two of the
complaints seek to enjoin the Bruce Mansfield Plant from operating except in a
“safe, responsible, prudent and proper manner”, one being a complaint filed on
behalf of twenty-one individuals and the other being a class action complaint,
seeking certification as a class action with the eight named plaintiffs as the
class representatives. On October 14, 2008, the Court granted FGCO’s motion
to consolidate discovery for all four complaints pending against the Bruce
Mansfield Plant. FGCO believes the claims are without merit and intends to
defend itself against the allegations made in these complaints.





On December 18,
2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations
at the Portland Generation Station against Reliant (the current owner and
operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in
1999), GPU, Inc. and Met-Ed.  Specifically, New Jersey alleges that
"modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without
preconstruction NSR or permitting under the CAA's prevention of significant
deterioration program, and seeks injunctive relief, penalties, attorney fees and
mitigation of the harm caused by excess emissions. On March 14, 2008,
Met-Ed filed a motion to dismiss the citizen suit claims against it and a
stipulation in which the parties agreed that GPU, Inc. should be dismissed from
this case. On March 26, 2008, GPU, Inc. was dismissed by the United States
District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe
Energy is disputed.  By letter dated October 1, 2008, New Jersey
informed the Court of its intent to file an amended complaint. Met-Ed is unable
to predict the outcome of this matter.





106








On June 11, 2008,
the EPA issued a Notice and Finding of Violation to MEW alleging that
"modifications" at the Homer City Power Station occurred since 1988 to the
present without preconstruction NSR or permitting under the CAA's prevention of
significant deterioration program. MEW is seeking indemnification from Penelec,
the co-owner (along with New York State Electric and Gas Company) and operator
of the Homer City Power Station prior to its sale in 1999.  The scope
of Penelec’s indemnity obligation to and from MEW is
disputed.  Penelec is unable to predict the outcome of this
matter.





On May 16, 2008,
FGCO received a request from the EPA for information pursuant to Section 114(a)
of the CAA for certain operating and maintenance information regarding the
Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA
to determine whether these generating sources are complying with the NSR
provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an
ACO modifying that request and setting forth a schedule for FGCO’s response.
FGCO complied with the modified schedule and otherwise intends to fully comply
with the ACO, but, at this time, is unable to predict the outcome of this
matter.





On August 18, 2008,
FirstEnergy received a request from the EPA for information pursuant to Section
114(a) of the CAA for certain operating and maintenance information regarding
the Avon Lake and Niles generating plants, as well as a copy of a nearly
identical request directed to the current owner, Reliant Energy, to allow the
EPA to determine whether these generating sources are complying with the NSR
provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s
information request, but, at this time, is unable to predict the outcome of this
matter.





National Ambient
Air Quality Standards(Applicable to FES)





In March 2005,
the EPA finalized the CAIR covering a total of 28 states (including Michigan,
New Jersey, Ohio and Pennsylvania) and the District of Columbia based on
proposed findings that air emissions from 28 eastern states and the District of
Columbia significantly contribute to non-attainment of the NAAQS for fine
particles and/or the "8-hour" ozone NAAQS in other states. CAIR would have
required reductions of NOX and
SO2
emissions in two phases (Phase I in 2009 for NOX, 2010 for
SO2
and Phase II in 2015 for both NOX and
SO2),
ultimately capping SO2 emissions
in affected states to just 2.5 million tons annually and NOX emissions
to just 1.3 million tons annually. CAIR was challenged in the United States
Court of Appeals for the District of Columbia and on July 11, 2008, the Court
vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from
the ground up.” The Court ruling also vacated the CAIR regional cap and trade
requirements for SO2 and
NOX,
which is currently not expected to, but may, materially impair the value of
emissions allowances obtained for future compliance. On September 24, 2008, the
EPA, utility, mining and certain environmental advocacy organizations petitioned
the Court for a rehearing to reconsider its ruling vacating CAIR.  On
October 21, 2008, the Court ordered the parties who appealed CAIR to file
responses to the rehearing petitions by November 5, 2008 and directed them to
address (1) whether any party is seeking vacatur of CAIR and (2) whether the
Court should stay its vacatur of CAIR until EPA promulgates a revised rule. The
future cost of compliance with these regulations may be substantial and will
depend on the Court’s ruling on rehearing, as well as the action taken by the
EPA or Congress in response to the Court’s ruling.





Mercury Emissions(Applicable to FES)





In December 2000,
the EPA announced it would proceed with the development of regulations regarding
hazardous air pollutants from electric power plants, identifying mercury as the
hazardous air pollutant of greatest concern. In March 2005, the EPA finalized
the CAMR, which provides a cap-and-trade program to reduce mercury emissions
from coal-fired power plants in two phases; initially, capping national mercury
emissions at 38 tons by 2010 (as a "co-benefit" from implementation of
SO2
and NOX emission
caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states
and environmental groups appealed the CAMR to the United States Court of Appeals
for the District of Columbia. On February 8, 2008, the Court vacated the
CAMR, ruling that the EPA failed to take the necessary steps to “de-list”
coal-fired power plants from its hazardous air pollutant program and, therefore,
could not promulgate a cap-and-trade program. The EPA petitioned for rehearing
by the entire Court, which denied the petition on May 20, 2008.  On
October 17, 2008, the EPA (and an industry group) petitioned the United
States Supreme Court for review of the Court’s ruling vacating CAMR. The Supreme
Court could grant the EPA’s petition and alter some or all of the lower Court’s
decision, or the EPA could take regulatory action to promulgate new mercury
emission standards for coal-fired power plants. FGCO’s future cost of compliance
with mercury regulations may be substantial and will depend on the action taken
by the EPA and on how they are ultimately implemented.





Pennsylvania has
submitted a new mercury rule for EPA approval that does not provide a
cap-and-trade approach as in the CAMR, but rather follows a command-and-control
approach imposing emission limits on individual sources. It is anticipated that
compliance with these regulations, if approved by the EPA and implemented, would
not require the addition of mercury controls at the Bruce Mansfield Plant, FES’
only Pennsylvania coal-fired power plant, until 2015, if at all.





107








Climate Change(Applicable to FES)





In December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol, to address global warming by reducing the amount of man-made
GHG emitted by developed countries by 2012. The United States signed the Kyoto
Protocol in 1998 but it was never submitted for ratification by the United
States Senate. However, the Bush administration has committed the United States
to a voluntary climate change strategy to reduce domestic GHG intensity – the
ratio of emissions to economic output – by 18% through 2012. Also, in an
April 16, 2008 speech, President Bush set a policy goal of stopping the
growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In
addition, the EPACT established a Committee on Climate Change Technology to
coordinate federal climate change activities and promote the development and
deployment of GHG reducing technologies.





There are a number
of initiatives to reduce GHG emissions under consideration at the federal, state
and international level.  At the international level, efforts to reach
a new global agreement to reduce GHG emissions post-2012 have begun with the
Bali Roadmap, which outlines a two-year process designed to lead to an agreement
in 2009. At the federal level, members of Congress have introduced several bills
seeking to reduce emissions of GHG in the United States, and the Senate
Environment and Public Works Committee has passed one such bill. State
activities, primarily the northeastern states participating in the Regional
Greenhouse Gas Initiative and western states led by California, have coordinated
efforts to develop regional strategies to control emissions of certain
GHGs.





On April 2, 2007,
the United States Supreme Court found that the EPA has the authority to regulate
CO2
emissions from automobiles as “air pollutants” under the CAA. Although this
decision did not address CO2 emissions
from electric generating plants, the EPA has similar authority under the CAA to
regulate “air pollutants” from those and other facilities. On July 11,
2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting
input from the public on the effects of climate change and the potential
ramifications of regulation of CO2 under the
CAA.





FES cannot currently
estimate the financial impact of climate change policies, although potential
legislative or regulatory programs restricting CO2 emissions
could require significant capital and other expenditures. The CO2 emissions
per KWH of electricity generated by FES is lower than many regional competitors
due to its diversified generation sources, which include low or non-CO2 emitting
gas-fired and nuclear generators.





Clean Water Act(Applicable to FES)





Various water
quality regulations, the majority of which are the result of the federal Clean
Water Act and its amendments, apply to FES' plants. In addition, Ohio, New
Jersey and Pennsylvania have water quality standards applicable to FES'
operations. As provided in the Clean Water Act, authority to grant federal
National Pollutant Discharge Elimination System water discharge permits can be
assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such
authority.





On September 7,
2004, the EPA established new performance standards under Section 316(b) of the
Clean Water Act for reducing impacts on fish and shellfish from cooling water
intake structures at certain existing large electric generating plants. The
regulations call for reductions in impingement mortality (when aquatic organisms
are pinned against screens or other parts of a cooling water intake system) and
entrainment (which occurs when aquatic life is drawn into a facility's cooling
water system). On January 26, 2007, the United States Court of Appeals for the
Second Circuit remanded portions of the rulemaking dealing with impingement
mortality and entrainment back to the EPA for further rulemaking and eliminated
the restoration option from the EPA’s regulations. On July 9, 2007, the EPA
suspended this rule, noting that until further rulemaking occurs, permitting
authorities should continue the existing practice of applying their best
professional judgment to minimize impacts on fish and shellfish from cooling
water intake structures. On April 14, 2008, the Supreme Court of the United
States granted a petition for a writ of certiorari to review one significant
aspect of the Second Circuit Court’s opinion which is whether
Section 316(b) of the Clean Water Act authorizes the EPA to compare costs
with benefits in determining the best technology available for minimizing
adverse environmental impact at cooling water intake structures.  Oral
argument before the Supreme Court is scheduled for December 2, 2008. FES is
studying various control options and their costs and effectiveness. Depending on
the results of such studies, the outcome of the Supreme Court’s review of the
Second Circuit’s decision, the EPA’s further rulemaking and any action taken by
the states exercising best professional judgment, the future costs of compliance
with these standards may require material capital expenditures.





Regulation of
Hazardous Waste(Applicable to FES and each of the
Utilities)





As a result of the
Resource Conservation and Recovery Act of 1976, as amended, and the Toxic
Substances Control Act of 1976, federal and state hazardous waste regulations
have been promulgated. Certain fossil-fuel combustion waste products, such as
coal ash, were exempted from hazardous waste disposal requirements pending the
EPA's evaluation of the need for future regulation. The EPA subsequently
determined that regulation of coal ash as a hazardous waste is unnecessary. In
April 2000, the EPA announced that it will develop national standards regulating
disposal of coal ash under its authority to regulate non-hazardous
waste.





108








Under NRC
regulations, FirstEnergy must ensure that adequate funds will be available to
decommission its nuclear facilities.  As of September 30, 2008,
FirstEnergy had approximately $1.9 billion invested in external trusts to be
used for the decommissioning and environmental remediation of Davis-Besse,
Beaver Valley, Perry and TMI-2. As part of the application to the NRC to
transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005,
FirstEnergy agreed to contribute another $80 million to these trusts by 2010.
Consistent with NRC guidance, utilizing a “real” rate of return on these funds
of approximately 2% over inflation, these trusts are expected to exceed the
minimum decommissioning funding requirements set by the NRC. Conservatively,
these estimates do not include any rate of return that the trusts may earn over
the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1
as it relates to the timing of the decommissioning of TMI-2) seeks for these
facilities.





The Utilities have
been named as PRPs at waste disposal sites, which may require cleanup under the
Comprehensive Environmental Response, Compensation, and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site may be liable on a
joint and several basis. Therefore, environmental liabilities that are
considered probable have been recognized on the Consolidated Balance Sheet as of
September 30, 2008, based on estimates of the total costs of cleanup, the
Utilities' proportionate responsibility for such costs and the financial ability
of other unaffiliated entities to pay. Total liabilities of approximately
$94 million (JCP&L - $68 million, TE - $1 million, CEI -
$1 million and FirstEnergy Corp. - $24 million) have been accrued
through September 30, 2008. Included in the total for JCP&L are accrued
liabilities of approximately $57 million for environmental remediation of
former manufactured gas plants in New Jersey, which are being recovered by
JCP&L through a non-bypassable SBC.





Other Legal
Proceedings





Power Outages and
Related Litigation(Applicable to JCP&L)





In July 1999, the
Mid-Atlantic States experienced a severe heat wave, which resulted in power
outages throughout the service territories of many electric utilities, including
JCP&L's territory. In an investigation into the causes of the outages and
the reliability of the transmission and distribution systems of all four of New
Jersey’s electric utilities, the NJBPU concluded that there was not a prima
facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or
improper service to its customers. Two class action lawsuits (subsequently
consolidated into a single proceeding) were filed in New Jersey Superior Court
in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory.





In August 2002, the
trial Court granted partial summary judgment to JCP&L and dismissed the
plaintiffs' claims for consumer fraud, common law fraud, negligent
misrepresentation, and strict product liability. In November 2003, the trial
Court granted JCP&L's motion to decertify the class and denied plaintiffs'
motion to permit into evidence their class-wide damage model indicating damages
in excess of $50 million. These class decertification and damage rulings were
appealed to the Appellate Division. The Appellate Division issued a decision in
July 2004, affirming the decertification of the originally certified class, but
remanding for certification of a class limited to those customers directly
impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a
common incident involving the failure of the bushings of two large transformers
in the Red Bank substation resulting in planned and unplanned outages in the
area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify
the class based on a very limited number of class members who incurred damages
and also filed a motion for summary judgment on the remaining plaintiffs’ claims
for negligence, breach of contract and punitive damages. In July 2006, the New
Jersey Superior Court dismissed the punitive damage claim and again decertified
the class based on the fact that a vast majority of the class members did not
suffer damages and those that did would be more appropriately addressed in
individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate
Division which, in March 2007, reversed the decertification of the Red Bank
class and remanded this matter back to the Trial Court to allow plaintiffs
sufficient time to establish a damage model or individual proof of damages.
JCP&L filed a petition for allowance of an appeal of the Appellate Division
ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings
are continuing in the Superior Court and a case management conference with the
presiding Judge was held on June 13, 2008.  At that conference,
the plaintiffs stated their intent to drop their efforts to create a class-wide
damage model and, instead of dismissing the class action, expressed their desire
for a bifurcated trial on liability and damages. The judge directed the
plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed
under this scenario.  Thereafter, the judge expects to hold another
pretrial conference to address plaintiffs' proposed procedure.JCP&L has received
the plaintiffs’ proposed plan of action, and intends to file its objection to
the proposed plan, and also file a renewed motion to decertify the class.
JCP&L is defending this action but is unable to predict the outcome. No
liability has been accrued as of September 30, 2008.





109





Nuclear Plant
Matters(Applicable to FES)





On May 14, 2007, the
Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply
to an April 2, 2007 NRC request for information about two reports prepared
by expert witnesses for an insurance arbitration (the insurance claim was
subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse.
The NRC indicated that this information was needed for the NRC “to determine
whether an Order or other action should be taken pursuant to 10 CFR 2.202, to
provide reasonable assurance that FENOC will continue to operate its licensed
facilities in accordance with the terms of its licenses and the Commission’s
regulations.” FENOC was directed to submit the information to the NRC within 30
days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that
it accepts full responsibility for the mistakes and omissions leading up to the
damage to the reactor vessel head and that it remains committed to operating
Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC
submitted a supplemental response clarifying certain aspects of the DFI response
to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a
confirmatory order imposing these commitments. FENOC must inform the NRC’s
Office of Enforcement after it completes the key commitments embodied in the
NRC’s order. FENOC has conducted the employee training required by the
confirmatory order and a consultant has performed follow-up reviews to ensure
the effectiveness of that training.  The NRC continues to monitor
FENOC’s compliance with all the commitments made in the confirmatory
order.





In August 2007,
FENOC submitted an application to the NRC to renew the operating licenses for
the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The
NRC is required by statute to provide an opportunity for members of the public
to request a hearing on the application. No members of the public, however,
requested a hearing on the Beaver Valley license renewal application. On
September 24, 2008, the NRC issued a draft supplemental Environmental
Impact Statement for Beaver Valley. FENOC will continue to work with the
NRC Staff as it completes its environmental and technical reviews of the license
renewal application, and expects to obtain renewed licenses for the Beaver
Valley Power Station in 2009. If renewed licenses are issued by the NRC, the
Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for
Units 1 and 2, respectively.





Other Legal
Matters(Applicable to OE, JCP&L and FES)





There are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to normal business operations pending against FES and the Utilities. The
other potentially material items not otherwise discussed above are described
below.





On August 22, 2005,
a class action complaint was filed against OE in Jefferson County, Ohio Common
Pleas Court, seeking compensatory and punitive damages to be determined at trial
based on claims of negligence and eight other tort counts alleging damages from
W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking
injunctive relief to eliminate harmful emissions and repair property damage and
the institution of a medical monitoring program for class members. On
April 5, 2007, the Court rejected the plaintiffs’ request to certify this
case as a class action and, accordingly, did not appoint the plaintiffs as class
representatives or their counsel as class counsel. On July 30, 2007,
plaintiffs’ counsel voluntarily withdrew their request for reconsideration of
the April 5, 2007 Court order denying class certification and the Court
heard oral argument on the plaintiffs’ motion to amend their complaint, which OE
opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to
amend their complaint. The plaintiffs have appealed the Court’s denial of the
motion for certification as a class action and motion to amend their complaint
and oral argument was held on November 5, 2008.





JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
panel decided not to hear testimony on damages and closed the proceedings. On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district Court granted a union motion to dismiss, as premature,
a JCP&L appeal of the award filed on October 18, 2005. A final order
identifying the individual damage amounts was issued on October 31, 2007.
The award appeal process was initiated. The union filed a motion with the
federal Court to confirm the award and JCP&L filed its answer and
counterclaim to vacate the award on December 31, 2007. JCP&L and the
union filed briefs in June and July of 2008 and oral arguments were held in the
fall. The Court has yet to render its decision. JCP&L recognized a liability
for the potential $16 million award in 2005.





The union employees
at the Bruce Mansfield Plant have been working without a labor contract since
February 15, 2008. The parties are continuing to bargain with the assistance of
a federal mediator. FES has a strike mitigation plan ready in the event of a
strike.





FES and the
Utilities accrue legal liabilities only when they conclude that it is probable
that they have an obligation for such costs and can reasonably estimate the
amount of such costs. If it were ultimately determined that FES and the
Utilities have legal liability or are otherwise made subject to liability based
on the above matters, it could have a material adverse effect their financial
condition, results of operations and cash flows.





110








New
Accounting Standards and Interpretations(Applicable to FES and
each of the Utilities)





SFAS 141(R) – “Business
Combinations”





In December 2007,
the FASB issued SFAS 141(R), which: (i) requires the acquiring entity in a
business combination to recognize all assets acquired and liabilities assumed in
the transaction; (ii) establishes the acquisition-date fair value as the
measurement objective for all assets acquired and liabilities assumed; and (iii)
requires the acquirer to disclose to investors and other users all of the
information they need to evaluate and understand the nature and financial effect
of the business combination. The Standard includes both core principles and
pertinent application guidance, eliminating the need for numerous EITF issues
and other interpretative guidance. SFAS 141(R) will affect business combinations
entered into by FirstEnergy that close after January 1, 2009. In addition,
the Standard also affects the accounting for changes in deferred tax valuation
allowances and income tax uncertainties made after January 1, 2009, that
were established as part of a business combination prior to the implementation
of this Standard. Under SFAS 141(R), adjustments to the acquired entity’s
deferred tax assets and uncertain tax position balances occurring outside the
measurement period will be recorded as a component of income tax expense, rather
than goodwill.The
impact of FirstEnergy’s application of this Standard in periods after
implementation will be dependent upon acquisitions at that time.





SFAS
160 - “Non-controlling Interests in Consolidated Financial Statements – an
Amendment of ARB No. 51”





In December 2007,
the FASB issued SFAS 160 that establishes accounting and reporting standards for
the noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an
ownership interest in the consolidated entity that should be reported as equity
in the consolidated financial statements. This Statement is effective for fiscal
years, and interim periods within those fiscal years, beginning on or after
December 15, 2008. Early adoption is prohibited. The Statement is not
expected to have a material impact on FES’ or the Utilities’ financial
statements.





SFAS
      161 - “Disclosures about Derivative Instruments and Hedging Activities –
      an Amendment of FASB Statement No.
133”





In March 2008, the
FASB issued SFAS 161 that enhances the current disclosure framework for
derivative instruments and hedging activities. The Statement requires that
objectives for using derivative instruments be disclosed in terms of underlying
risk and accounting designation. The FASB believes that additional required
disclosure of the fair values of derivative instruments and their gains and
losses in a tabular format will provide a more complete picture of the location
in an entity’s financial statements of both the derivative positions existing at
period end and the effect of using derivatives during the reporting period.
Disclosing information about credit-risk-related contingent features is designed
to provide information on the potential effect on an entity’s liquidity from
using derivatives. This Statement also requires cross-referencing within the
footnotes to help users of financial statements locate important information
about derivative instruments. The Statement is effective for reporting periods
beginning after November 15, 2008. FES expects this Standard to increase
its disclosure requirements for derivative instruments and hedging
activities.








111








COMBINED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(UNAUDITED)








1.
ORGANIZATION AND BASIS OF PRESENTATION





FirstEnergy is a
diversified energy company that holds, directly or indirectly, all of the
outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a
wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and
its subsidiaries FGCO and NGC, and FESC.





FirstEnergy and its
subsidiaries follow GAAP and comply with the regulations, orders, policies and
practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC
and the NJBPU. The preparation of financial statements in conformity with GAAP
requires management to make periodic estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses and disclosure of
contingent assets and liabilities. Actual results could differ from these
estimates. The reported results of operations are not indicative of results of
operations for any future period.





These statements
should be read in conjunction with the financial statements and notes included
in the combined Annual Report on Form 10-K for the year ended December 31,
2007 for FirstEnergy, FES and the Utilities. The consolidated unaudited
financial statements of FirstEnergy, FES and each of the Utilities reflect all
normal recurring adjustments that, in the opinion of management, are necessary
to fairly present results of operations for the interim periods. Certain prior
year amounts have been reclassified to conform to the current year presentation.
Unless otherwise indicated, defined terms used herein have the meanings set
forth in the accompanying Glossary of Terms.





FirstEnergy and its
subsidiaries consolidate all majority-owned subsidiaries over which they
exercise control and, when applicable, entities for which they have a
controlling financial interest. Intercompany transactions and balances are
eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 9) when it
is determined to be the VIE's primary beneficiary. Investments in
non-consolidated affiliates over which FirstEnergy and its subsidiaries have the
ability to exercise significant influence, but not control (20-50% owned
companies, joint ventures and partnerships) follow the equity method of
accounting. Under the equity method, the interest in the entity is reported as
an investment in the Consolidated Balance Sheets and the percentage share of the
entity’s earnings is reported in the Consolidated Statements of
Income.





The consolidated
financial statements as of September 30, 2008 and for the three-month and
nine-month periods ended September 30, 2008 and 2007, have been reviewed by
PricewaterhouseCoopers LLP, an independent registered public accounting firm.
Their report (dated November 6, 2008) is included herein. The report of
PricewaterhouseCoopers LLP states that they did not audit and they do not
express an opinion on that unaudited financial information. Accordingly, the
degree of reliance on their report on such information should be restricted in
light of the limited nature of the review procedures applied.
PricewaterhouseCoopers LLP is not subject to the liability provisions of Section
11 of the Securities Act of 1933 for their report on the unaudited financial
information because that report is not a “report” or a “part” of a registration
statement prepared or certified by PricewaterhouseCoopers LLP within the meaning
of Sections 7 and 11 of the Securities Act of 1933.





2.  EARNINGS
PER SHARE





Basic earnings per
share of common stock is computed using the weighted average of actual common
shares outstanding during the respective period as the denominator. The
denominator for diluted earnings per share of common stock reflects the weighted
average of common shares outstanding plus the potential additional common shares
that could result if dilutive securities and other agreements to issue common
stock were exercised. On March 2, 2007, FirstEnergy repurchased approximately
14.4 million shares, or 4.5%, of its outstanding common stock through an
accelerated share repurchase program at an initial price of approximately
$900 million. A final purchase price adjustment of $51 million was
settled in cash on December 13, 2007. The following table reconciles basic
and diluted earnings per share of common stock:





112








Three
      Months
            
            Nine
      MonthsEnded
      September 30
            
            Ended
      September 30Reconciliation
      of Basic and Diluted Earnings per Share
            
            2008
            
            2007
            
            2008
            
            2007(In
      millions, except per share amounts)Net
      income
            
            $
            471
            
            $
            413
            
            $
            1,010
            
            $
            1,041Average shares
      of common stock outstanding – Basic
            
            
            304
            
            
            304
            
            
            304
            
            
            307Assumed
      exercise of dilutive stock options and awards
            
            
            3
            
            
            3
            
            
            3
            
            
            4Average shares
      of common stock outstanding – Dilutive
            
            
            307
            
            
            307
            
            
            307
            
            
            311Basic earnings
      per share
            
            $
            1.55
            
            $
            1.36
            
            $
            3.32
            
            $
            3.39Diluted
      earnings per share
            
            $
            1.54
            
            $
            1.34
            
            $
            3.29
            
            $
            3.35





3.
GOODWILL





In a business
combination, the excess of the purchase price over the estimated fair values of
assets acquired and liabilities assumed is recognized as goodwill. Based on the
guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment
at least annually and more frequently as indicators of impairment arise. In
accordance with the accounting standard, if the fair value of a reporting unit
is less than its carrying value (including goodwill), the goodwill is tested for
impairment. If impairment is indicated, FirstEnergy recognizes a loss –
calculated as the difference between the implied fair value of a reporting
unit's goodwill and the carrying value of the goodwill.





FirstEnergy's 2008
annual review was completed in the third quarter of 2008 with no impairment
indicated. As discussed in Note 12(B), the Ohio Companies filed a
comprehensive ESP and MRO with the PUCO on July 31, 2008. The annual
goodwill impairment analysis assumed management's best estimate of the outcome
of those filings. There was no impairment indicated for FirstEnergy and the
Ohio Companies based on a probability-weighted outcome of the ESP and MRO
proceedings. If the PUCO’s final decision authorizes less revenue recovery than
the amounts assumed, an additional impairment analysis would be performed at
that time that could result in future goodwill impairment.





FirstEnergy's
goodwill primarily relates to its energy delivery services segment. In the first
and third quarters of 2008, FirstEnergy adjusted goodwill by $1 million and $23
million, respectively, of the former GPU companies due to the realization of tax
benefits that had been reserved under purchase accounting. The following tables
reconcile changes to goodwill for the three months and nine months ended
September 30, 2008.





Three
      Months Ended
            
            FirstEnergy
            
            FES
            
            CEI
            
            TE
            
            JCP&L
            
            Met-Ed
            
            Penelec(In
      millions)Balance as of
      July 1, 2008
            
            $
            5,606
            
            $
            24
            
            $
            1,689
            
            $
            501
            
            $
            1,826
            
            $
            424
            
            $
            778Adjustments
      related to GPU acquisition
            
            
            (23
            )
            
            -
            
            
            -
            
            
            -
            
            
            (11
            )
            
            (5
            )
            
            (7
            )Balance as of
      September 30, 2008
            
            $
            5,583
            
            $
            24
            
            $
            1,689
            
            $
            501
            
            $
            1,815
            
            $
            419
            
            $
            771





Nine
      Months Ended
            
            FirstEnergy
            
            FES
            
            CEI
            
            TE
            
            JCP&L
            
            Met-Ed
            
            Penelec(In
      millions)Balance as of
      January 1, 2008
            
            $
            5,607
            
            $
            24
            
            $
            1,689
            
            $
            501
            
            $
            1,826
            
            $
            425
            
            $
            778Adjustments
      related to GPU acquisition
            
            
            (24
            )
            
            -
            
            
            -
            
            
            -
            
            
            (11
            )
            
            (6
            )
            
            (7
            )Balance as of
      September 30, 2008
            
            $
            5,583
            
            $
            24
            
            $
            1,689
            
            $
            501
            
            $
            1,815
            
            $
            419
            
            $
            771








4.  DIVESTITURES
AND DISCONTINUED OPERATIONS





On March 7, 2008,
FirstEnergy sold certain telecommunication assets, resulting in a net after-tax
gain of $19.3 million. The sale of assets did not meet the criteria for
classification as discontinued operations as of September 30, 2008.





5.  FAIR
VALUE MEASURES





Effective January 1,
2008, FirstEnergy adopted SFAS 157, which provides a framework for measuring
fair value under GAAP and, among other things, requires enhanced disclosures
about assets and liabilities recognized at fair value. FirstEnergy also adopted
SFAS 159 on January 1, 2008, which provides the option to measure certain
financial assets and financial liabilities at fair value. FirstEnergy has
analyzed its financial assets and financial liabilities within the scope of
SFAS 159 and, as of September 30, 2008, has elected not to record
eligible assets and liabilities at fair value.





113








As defined in SFAS
157, fair value is the price that would be received for an asset or paid to
transfer a liability (exit price) in the principal or most advantageous market
for the asset or liability in an orderly transaction between willing market
participants on the measurement date. SFAS 157 establishes a fair value
hierarchy that prioritizes the inputs used to measure fair value. The hierarchy
gives the highest priority to unadjusted quoted market prices in active markets
for identical assets or liabilities (Level 1) and the lowest priority to
unobservable inputs (Level 3). The three levels of the fair value hierarchy
defined by SFAS 157 are as follows:





Level 1 – Quoted
prices are available in active markets for identical assets or liabilities as of
the reporting date. Active markets are those where transactions for the asset or
liability occur in sufficient frequency and volume to provide pricing
information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities
primarily consist of exchange-traded derivatives and equity securities listed on
active exchanges that are held in various trusts.





Level 2 – Pricing
inputs are either directly or indirectly observable in the market as of the
reporting date, other than quoted prices in active markets included in Level 1.
FirstEnergy’s Level 2 assets and liabilities consist primarily of investments in
debt securities held in various trusts and commodity forwards. Additionally,
Level 2 includes those financial instruments that are valued using models or
other valuation methodologies based on assumptions that are observable in the
marketplace throughout the full term of the instrument, can be derived from
observable data or are supported by observable levels at which transactions are
executed in the marketplace. These models are primarily industry-standard models
that consider various assumptions, including quoted forward prices for
commodities, time value, volatility factors, and current market and contractual
prices for the underlying instruments, as well as other relevant economic
measures. Instruments in this category include non-exchange-traded derivatives
such as forwards and certain interest rate swaps.





Level 3 – Pricing
inputs include inputs that are generally less observable from objective sources.
These inputs may be used with internally developed methodologies that result in
management’s best estimate of fair value. FirstEnergy develops its view of the
future market price of key commodities through a combination of market
observation and assessment (generally for the short term) and fundamental
modeling (generally for the longer term). Key fundamental electricity model
inputs are generally directly observable in the market or derived from publicly
available historic and forecast data. Some key inputs reflect forecasts
published by industry leading consultants who generally employ similar
fundamental modeling approaches. Fundamental model inputs and results, as well
as the selection of consultants, reflect the consensus of appropriate
FirstEnergy management. Level 3 instruments include those that may be more
structured or otherwise tailored to customers’ needs. FirstEnergy’s Level 3
instruments consist of NUG contracts.





FirstEnergy utilizes
market data and assumptions that market participants would use in pricing the
asset or liability, including assumptions about risk and the risks inherent in
the inputs to the valuation technique. These inputs can be readily observable,
market corroborated, or generally unobservable. FirstEnergy primarily applies
the market approach for recurring fair value measurements using the best
information available. Accordingly, FirstEnergy maximizes the use of observable
inputs and minimizes the use of unobservable inputs.





The following table
sets forth FirstEnergy’s financial assets and financial liabilities that are
accounted for at fair value by level within the fair value hierarchy as of
September 30, 2008. As required by SFAS 157, assets and liabilities are
classified in their entirety based on the lowest level of input that is
significant to the fair value measurement. FirstEnergy’s assessment of the
significance of a particular input to the fair value measurement requires
judgment and may affect the valuation of fair value assets and liabilities and
their placement within the fair value hierarchy levels.





September
      30, 2008Recurring
      Fair Value Measures
            
            Level
      1
            
            Level
      2
            
            Level
      3
            
            Total(In
      millions)Assets:Derivatives
            
            $
            -
            
            $
            45
            
            $
            -
            
            $
            45Nuclear
      decommissioning trusts
            
            
            761
            
            
            1,112
            
            
            -
            
            
            1,873Other
      investments
            
            
            19
            
            
            312
            
            
            -
            
            
            331Total
            
            $
            780
            
            $
            1,469
            
            $
            -
            
            $
            2,249Liabilities:Derivatives
            
            $
            8
            
            $
            19
            
            $
            -
            
            $
            27NUG
      contracts(1)
            
            
            -
            
            
            -
            
            
            603
            
            
            603Total
            
            $
            8
            
            $
            19
            
            $
            603
            
            $
            630





(1)
            NUG contracts
      are completely offset by regulatory
assets.





114








The determination of
the above fair value measures takes into consideration various factors required
under SFAS 157. These factors include the credit standing of the
counterparties involved, the impact of credit enhancements (such as cash
deposits, LOCs and priority interests) and the impact of nonperformance
risk.





Exchange-traded
derivative contracts, which include some futures and options, are generally
based on unadjusted quoted market prices in active markets and are classified
within Level 1. Forwards, options and swap contracts that are not
exchange-traded are classified as Level 2 as the fair values of these items are
based on Intercontinental Exchange quotes or market transactions in the OTC
markets. In addition, complex or longer-term structured transactions can
introduce the need for internally-developed model inputs that may not be
observable in or corroborated by the market. When such inputs have a significant
impact on the measurement of fair value, the instrument is classified as Level
3.





Nuclear
decommissioning trusts consist of equity securities listed on active exchanges
classified as Level 1 and various debt securities and collective trusts
classified as Level 2. Other investments represent the NUG trusts, spent nuclear
fuel trusts and rabbi trust investments, which primarily consist of various debt
securities and collective trusts classified as Level 2.





The following tables
provide a reconciliation of changes in the fair value of NUG contracts
classified as Level 3 in the fair value hierarchy for the three and nine months
ended September 30, 2008:





Three
      Months
            
            
            Nine
      Months(In
      millions)Balance at
      beginning of period
            
            $
            644
            
            
            $
            750Realized
      and unrealized gains (losses)(1)
            
            
            (32
            )
            
            
            (120
            )Purchases,
      sales, issuances and settlements, net(1)
            
            
            (9
            )
            
            
            (27
            )Net
      transfers to (from) Level 3
            
            
            -
            
            
            
            -Balance as of
      September 30, 2008
            
            $
            603
            
            
            $
            603Change in
      unrealized gains (losses) relating toinstruments
      held as of September 30, 2008
            
            $
            (32
            )
            
            $
            (120
            )




(1)Changes in the
      fair value of NUG contracts are completely offset by regulatory assets and
      do not impact earnings





Under FSP FAS 157-2,
“Effective Date of FASB Statement No. 157”, FirstEnergy deferred until January
1, 2009, the election of SFAS 157 for financial assets and financial liabilities
measured at fair value on a non-recurring basis and is currently evaluating the
impact of SFAS 157 on those financial assets and financial
liabilities.





6.
DERIVATIVE INSTRUMENTS





FirstEnergy is
exposed to financial risks resulting from the fluctuation of interest rates and
commodity prices, including prices for electricity, natural gas, coal and energy
transmission. To manage the volatility relating to these exposures, FirstEnergy
uses a variety of derivative instruments, including forward contracts, options,
futures contracts and swaps. The derivatives are used principally for hedging
purposes. FirstEnergy's Risk Policy Committee, comprised of members of senior
management, provides general management oversight for risk management activities
throughout FirstEnergy. They are responsible for promoting the effective design
and implementation of sound risk management programs. They also oversee
compliance with corporate risk management policies and established risk
management practices.





FirstEnergy accounts
for derivative instruments in its Consolidated Balance Sheet at their fair value
unless they meet the criteria for the normal purchases and normal sales
exception. Derivatives that meet those criteria are accounted for at cost.
FirstEnergy regularly assesses derivatives based on the normal purchases and
normal sales criteria and expects no changes in eligibility for the normal
purchases and normal sales exception. The changes in the fair value of
derivative instruments that do not meet the normal purchases and normal sales
exception are recorded as other expense, as AOCL, or as part of the value of the
hedged item, depending on whether or not it is designated as part of a hedge
transaction, the nature of the hedge transaction and hedge effectiveness.
FirstEnergy does not offset fair value for the right to reclaim collateral or
the obligation to return collateral.





FirstEnergy hedges
anticipated transactions using cash flow hedges. Such transactions include
hedges of anticipated electricity, natural gas and other commodity purchases and
anticipated interest payments associated with future debt issues. The effective
portion of such hedges are initially recorded in equity as other comprehensive
income or loss and are subsequently included in net income as the underlying
hedged commodities are delivered or interest payments are made. Gains and losses
from any ineffective portion of cash flow hedges are recognized directly in net
income.





115








The net deferred
losses of $64 million included in AOCL as of September 30, 2008, for
derivative hedging activity, as compared to $75 million as of
December 31, 2007, resulted from a net $3 million increase related to
current hedging activity and a $14 million decrease due to net hedge losses
reclassified to earnings during the nine months ended September 30, 2008.
Based on current estimates, approximately $16 million (after tax) of the net
deferred losses on derivative instruments in AOCL as of September 30, 2008
are expected to be reclassified to earnings during the next twelve months as
hedged transactions occur. The fair value of these derivative instruments
fluctuate from period to period based on various market factors, including
commodity prices, counterparty credit and interest rates.





FirstEnergy has
entered into swaps that have been designated as fair value hedges of fixed-rate,
long-term debt issues to protect against the risk of changes in the fair value
of fixed-rate debt instruments due to lower interest rates. In order to reduce
counterparty exposure and lessen variable debt exposure under current market
conditions, FirstEnergy unwound its remaining interest rate swaps. During the
first nine months of 2008, FirstEnergy received $3 million to terminate
interest rate swaps with an aggregate notional value of $250 million. As of
September 30, 2008, FirstEnergy has no outstanding interest rate swaps
hedging fixed-rate long term debt.





During 2007 and the
first nine months of 2008, FirstEnergy entered into several forward-starting
swap agreements (forward swaps) in order to hedge a portion of the consolidated
interest rate risk associated with the anticipated issuance of variable-rate
short-term debt and fixed-rate long-term debt securities, by one or more of its
subsidiaries, as outstanding debt matures during 2008 and 2009. These
derivatives are treated as cash flow hedges, protecting against the risk of
changes in future interest payments resulting from changes in benchmark U.S.
Treasury and LIBOR rates between the date of hedge inception and the date of the
debt issuance. FirstEnergy considers counterparty credit and nonperformance risk
in its hedge assessments and continues to expect the forward-starting swaps to
be effective in protecting against the risk of changes in future interest
payments. During the first nine months of 2008, FirstEnergy terminated swaps
with a notional value of $750 million and entered into swaps with a
notional value of $950 million. FirstEnergy paid $16 million related
to the terminations, $5 million of which was deemed ineffective and
recognized in current period earnings. FirstEnergy will recognize the remaining
loss over the life of the associated future debt. As of September 30, 2008,
FirstEnergy had forward swaps with an aggregate notional amount of
$600 million and a fair value of $(0.2) million.





7.
ASSET RETIREMENT OBLIGATIONS





FirstEnergy has
recognized applicable legal obligations under SFAS 143 for nuclear power plant
decommissioning, reclamation of a sludge disposal pond and closure of two coal
ash disposal sites. In addition, FirstEnergy has recognized conditional
retirement obligations (primarily for asbestos remediation) in accordance with
FIN 47.





The ARO of $1.3
billion as of September 30, 2008 is primarily related to the future nuclear
decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear
generating facilities. FirstEnergy utilized an expected cash flow approach to
measure the fair value of the nuclear decommissioning ARO.





FirstEnergy
maintains nuclear decommissioning trust funds that are legally restricted for
purposes of settling the nuclear decommissioning ARO. As of September 30,
2008, the fair value of the decommissioning trust assets was approximately
$1.9 billion.





The following tables
analyze changes to the ARO balance during the three months and nine months ended
September 30, 2008 and 2007, respectively.





ARO
      Reconciliation
            
            FirstEnergy
            
            FES
            
            OE
            
            CEI
            
            TE
            
            JCP&L
            
            Met-Ed
            
            Penelec(In
      millions)Balance, July
      1, 2008
            
            $
            1,307
            
            $
            836
            
            $
            96
            
            $
            2
            
            $
            29
            
            $
            92
            
            $
            166
            
            $
            84Liabilities
      incurred
            
            
            5
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Liabilities
      settled
            
            
            (1
            )
            
            (1
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Accretion
            
            
            21
            
            
            14
            
            
            1
            
            
            -
            
            
            1
            
            
            2
            
            
            2
            
            
            2Revisions in
      estimated cash flows
            
            
            (18
            )
            
            -
            
            
            (18
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Balance,
      September 30, 2008
            
            $
            1,314
            
            $
            849
            
            $
            79
            
            $
            2
            
            $
            30
            
            $
            94
            
            $
            168
            
            $
            86Balance, July
      1, 2007
            
            $
            1,228
            
            $
            784
            
            $
            91
            
            $
            2
            
            $
            27
            
            $
            87
            
            $
            156
            
            $
            79Liabilities
      incurred
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Liabilities
      settled
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Accretion
            
            
            19
            
            
            13
            
            
            1
            
            
            -
            
            
            1
            
            
            1
            
            
            2
            
            
            2Revisions in
      estimated cash flows
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Balance,
      September 30, 2007
            
            $
            1,247
            
            $
            797
            
            $
            92
            
            $
            2
            
            $
            28
            
            $
            88
            
            $
            158
            
            $
            81








116








ARO
      Reconciliation
            
            FirstEnergy
            
            FES
            
            OE
            
            CEI
            
            TE
            
            JCP&L
            
            Met-Ed
            
            Penelec(In
      millions)Balance,
      January 1, 2008
            
            $
            1,267
            
            $
            810
            
            $
            94
            
            $
            2
            
            $
            28
            
            $
            90
            
            $
            161
            
            $
            82Liabilities
      incurred
            
            
            5
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Liabilities
      settled
            
            
            (2
            )
            
            (1
            )
            
            (1
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Accretion
            
            
            62
            
            
            40
            
            
            4
            
            
            -
            
            
            2
            
            
            4
            
            
            7
            
            
            4Revisions in
      estimated cash flows
            
            
            (18
            )
            
            -
            
            
            (18
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Balance,
      September 30, 2008
            
            $
            1,314
            
            $
            849
            
            $
            79
            
            $
            2
            
            $
            30
            
            $
            94
            
            $
            168
            
            $
            86Balance,
      January 1, 2007
            
            $
            1,190
            
            $
            760
            
            $
            88
            
            $
            2
            
            $
            27
            
            $
            84
            
            $
            151
            
            $
            77Liabilities
      incurred
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Liabilities
      settled
            
            
            (2
            )
            
            (1
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Accretion
            
            
            59
            
            
            38
            
            
            4
            
            
            -
            
            
            1
            
            
            4
            
            
            7
            
            
            4Revisions in
      estimated cash flows
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Balance,
      September 30, 2007
            
            $
            1,247
            
            $
            797
            
            $
            92
            
            $
            2
            
            $
            28
            
            $
            88
            
            $
            158
            
            $
            81








8.
PENSION AND OTHER POSTRETIREMENT BENEFITS





FirstEnergy provides
noncontributory defined benefit pension plans that cover substantially all of
its subsidiaries’ employees. The trusteed plans provide defined benefits based
on years of service and compensation levels. FirstEnergy’s funding policy is
based on actuarial computations using the projected unit credit method.
FirstEnergy uses a December 31 measurement date for its pension and other
postretirement benefit plans. The fair value of the plan assets represents the
actual market value as of December 31, 2007. FirstEnergy also provides a
minimum amount of noncontributory life insurance to retired employees in
addition to optional contributory insurance. Health care benefits, which include
certain employee contributions, deductibles and co-payments, are available upon
retirement to employees hired prior to January 1, 2005, their dependents
and, under certain circumstances, their survivors. FirstEnergy recognizes the
expected cost of providing pension benefits and other postretirement benefits
from the time employees are hired until they become eligible to receive those
benefits. In addition, FirstEnergy has obligations to former or inactive
employees after employment, but before retirement, for disability-related
benefits.





The components of
FirstEnergy's net periodic pension cost and other postretirement benefit cost
(including amounts capitalized) for the three months and nine months ended
September 30, 2008 and 2007, consisted of the following:





Three
      Months
            
            Nine
      MonthsEnded
      September 30
            
            Ended
      September 30Pension
      Benefits
            
            2008
            
            2007
            
            2008
            
            2007(In
      millions)Service
      cost
            
            $
            21
            
            $
            21
            
            $
            62
            
            $
            63Interest
      cost
            
            
            72
            
            
            71
            
            
            217
            
            
            213Expected
      return on plan assets
            
            
            (116
            )
            
            (112
            )
            
            (347
            )
            
            (337
            )Amortization
      of prior service cost
            
            
            3
            
            
            2
            
            
            7
            
            
            7Recognized net
      actuarial loss
            
            
            1
            
            
            10
            
            
            4
            
            
            31Net periodic
      cost (credit)
            
            $
            (19
            )
            $
            (8
            )
            $
            (57
            )
            $
            (23
            )








Three
      Months
            
            Nine
      MonthsEnded
      September 30
            
            Ended
      September 30Other
      Postretirement Benefits
            
            2008
            
            2007
            
            2008
            
            2007(In
      millions)Service
      cost
            
            $
            5
            
            $
            5
            
            $
            14
            
            $
            16Interest
      cost
            
            
            18
            
            
            17
            
            
            55
            
            
            52Expected
      return on plan assets
            
            
            (13
            )
            
            (12
            )
            
            (38
            )
            
            (38
            )Amortization
      of prior service cost
            
            
            (37
            )
            
            (37
            )
            
            (111
            )
            
            (112
            )Recognized net
      actuarial loss
            
            
            12
            
            
            11
            
            
            35
            
            
            34Net periodic
      cost (credit)
            
            $
            (15
            )
            $
            (16
            )
            $
            (45
            )
            $
            (48
            )





Pension and
postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries
employing the plan participants. FES and the Utilities capitalize employee
benefits related to construction projects. The net periodic pension costs and
net periodic postretirement benefit costs (including amounts capitalized)
recognized by FES and each of the Utilities for the three months and nine months
ended September 30, 2008 and 2007 were as follows:





117








Three
      Months
            
            Nine
      MonthsEnded
      September 30
            
            Ended
      September 30Pension
      Benefit Cost (Credit)
            
            2008
            
            2007
            
            2008
            
            2007(In
      millions)FES
            
            $
            4
            
            $
            5
            
            $
            11
            
            $
            16OE
            
            
            (6
            )
            
            (4
            )
            
            (20
            )
            
            (12
            )CEI
            
            
            (1
            )
            
            -
            
            
            (3
            )
            
            1TE
            
            
            (1
            )
            
            -
            
            
            (2
            )
            
            -JCP&L
            
            
            (4
            )
            
            (2
            )
            
            (11
            )
            
            (7
            )Met-Ed
            
            
            (3
            )
            
            (2
            )
            
            (8
            )
            
            (5
            )Penelec
            
            
            (3
            )
            
            (2
            )
            
            (10
            )
            
            (8
            )Other
      FirstEnergy subsidiaries
            
            
            (5
            )
            
            (3
            )
            
            (14
            )
            
            (8
            )$
            (19
            )
            $
            (8
            )
            $
            (57
            )
            $
            (23
            )








Three
      Months
            
            Nine
      MonthsEnded
      September 30
            
            Ended
      September 30Other
      Postretirement Benefit Cost (Credit)
            
            2008
            
            2007
            
            2008
            
            2007(In
      millions)FES
            
            $
            (2
            )
            $
            (2
            )
            $
            (5
            )
            $
            (7
            )OE
            
            
            (2
            )
            
            (3
            )
            
            (5
            )
            
            (8
            )CEI
            
            
            1
            
            
            1
            
            
            2
            
            
            3TE
            
            
            1
            
            
            1
            
            
            3
            
            
            4JCP&L
            
            
            (4
            )
            
            (4
            )
            
            (12
            )
            
            (12
            )Met-Ed
            
            
            (3
            )
            
            (3
            )
            
            (8
            )
            
            (8
            )Penelec
            
            
            (3
            )
            
            (3
            )
            
            (10
            )
            
            (10
            )Other
      FirstEnergy subsidiaries
            
            
            (3
            )
            
            (3
            )
            
            (10
            )
            
            (10
            )$
            (15
            )
            $
            (16
            )
            $
            (45
            )
            $
            (48
            )





Under the Pension
Protection Act of 2006, companies are generally required make a scheduled series
of contributions to fund 100% of outstanding qualified pension benefit
obligations over a seven year period. As of December 31, 2007,
FirstEnergy’s pension plan was overfunded, and, therefore, FirstEnergy will not
be required to make any contributions in 2009 for the 2008 plan year. However,
the overall actual asset return as of December 31, 2008 may reduce the value of
the pension plan’s assets to the level where contributions would be required in
2010 for the 2009 plan year.





9.
VARIABLE INTEREST ENTITIES





FIN 46R addresses
the consolidation of VIEs, including special-purpose entities, that are not
controlled through voting interests or in which the equity investors do not bear
the entity's residual economic risks and rewards. FirstEnergy and its
subsidiaries consolidate a VIE when they are determined to be the VIE's primary
beneficiary as defined by FIN 46R.





Mining
Operations





On July 16, 2008,
FirstEnergy Ventures Corp., a subsidiary of FirstEnergy, entered into a joint
venture with the Boich Companies, a Columbus, Ohio-based coal company, to
acquire a majority stake in the Signal Peak mining and coal transportation
operations near Roundup, Montana. FirstEnergy made a $125 million equity
investment in the joint venture, which acquired 80% of the mining operations
(Signal Peak Energy, LLC) and 100% of the transportation operations, with
FirstEnergy Ventures Corp. owning a 45% economic interest and an affiliate of
the Boich Companies owning a 55% economic interest in the joint venture. Both
parties have a 50% voting interest in the joint venture. After January 2010, the
joint venture will have 18 months to exercise an option to acquire the remaining
20% stake in the mining operations. In accordance with FIN 46R, FirstEnergy
is including the limited liability companies created for the mining and
transportation operations of this joint venture in its consolidated financial
statements.





Trusts





FirstEnergy’s
consolidated financial statements include PNBV and Shippingport, VIEs created in
1996 and 1997, respectively, to refinance debt originally issued in connection
with sale and leaseback transactions. PNBV and Shippingport financial data are
included in the consolidated financial statements of OE and CEI,
respectively.





PNBV was established
to purchase a portion of the lease obligation bonds issued in connection with
OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver
Valley Unit 2. OE used debt and available funds to purchase the notes issued by
PNBV. Ownership of PNBV includes a 3% equity interest by an unaffiliated third
party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary
of OE. Shippingport was established to purchase all of the lease obligation
bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and
leaseback transaction in 1987. CEI and TE used debt and available funds to
purchase the notes issued by Shippingport.





118








Loss
Contingencies





FES and the Ohio
Companies are exposed to losses under their applicable sale and leaseback
agreements upon the occurrence of certain contingent events that each company
considers unlikely to occur. The maximum exposure under these provisions
represents the net amount of casualty value payments due upon the occurrence of
specified casualty events that render the applicable plant worthless. Net
discounted lease payments would not be payable if the casualty loss payments are
made. The following table shows each company’s net exposure to loss based upon
the casualty value provisions mentioned above as of September 30,
2008:





Maximum
      Exposure
            
            Discounted
              Lease
      Payments, net
            
            Net
      Exposure(in
      millions)FES
            
            $
            1,363
            
            $
            1,209
            
            $
            154OE
            
            788
            
            597
            
            191CEI
            
            718
            
            79
            
            639TE
            
            718
            
            421
            
            297





In
October 2007, CEI and TE assigned their leasehold interests in the Bruce
Mansfield Plant to FGCO, which assumed all of CEI’s and TE’s obligations arising
under those leases. FGCO subsequently transferred the Unit 1 portion of these
leasehold interests, as well as FGCO’s leasehold interests under its
July 2007 Bruce Mansfield Unit 1 sale and leaseback transaction to a newly
formed wholly-owned subsidiary in December 2007. The subsidiary assumed all
of the lessee obligations associated with the assigned interests. However, CEI
and TE will remain primarily liable on the 1987 leases and related agreements as
to the lessors and other parties to the agreements. FGCO remains primarily
liable on the 2007 leases and related agreements, and FES remains primarily
liable as a guarantor under the related 2007 guarantees, as to the lessors and
other parties to the respective agreements. These assignments terminate
automatically upon the termination of the underlying leases.





During the second
quarter of 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987
sale and leaseback of the Perry Plant and approximately 43.5 MW of lessor equity
interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. Also in the
second quarter of 2008, NGC purchased 158.5 MW of lessor equity interests
in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2, which
purchases were undertaken in connection with the previously disclosed exercise
of the periodic purchase option provided in the TE and CEI sale and leaseback
arrangements. The Ohio Companies continue to lease these MW under the respective
sale and leaseback arrangements and the related lease debt remains
outstanding.





Power Purchase Agreements





In accordance with
FIN 46R, FirstEnergy evaluated its power purchase agreements and determined that
certain NUG entities may be VIEs to the extent they own a plant that sells
substantially all of its output to the Utilities and the contract price for
power is correlated with the plant’s variable costs of production. FirstEnergy,
through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately
30 long-term power purchase agreements with NUG entities. The agreements were
entered into pursuant to the Public Utility Regulatory Policies Act of 1978.
FirstEnergy was not involved in the creation of, and has no equity or debt
invested in, these entities.





FirstEnergy has
determined that for all but eight of these entities, neither JCP&L, Met-Ed
nor Penelec have variable interests in the entities or the entities are
governmental or not-for-profit organizations not within the scope of
FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the
remaining eight entities, which sell their output at variable prices that
correlate to some extent with the operating costs of the plants. As required by
FIN 46R, FirstEnergy periodically requests from these eight entities the
information necessary to determine whether they are VIEs or whether JCP&L,
Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to
obtain the requested information, which in most cases was deemed by the
requested entity to be proprietary. As such, FirstEnergy applied the scope
exception that exempts enterprises unable to obtain the necessary information to
evaluate entities under FIN 46R.





Since FirstEnergy
has no equity or debt interests in the NUG entities, its maximum exposure to
loss relates primarily to the above-market costs it may incur for power.
FirstEnergy expects any above-market costs it incurs to be recovered from
customers. Purchased power costs from these entities during the three months and
nine months ended September 30, 2008 and 2007 are shown in the following
table:





119








Three
      Months Ended
            
            Nine
      Months EndedSeptember
      30
            
            September
      302008
            
            2007
            
            2008
            
            2007(In
      millions)JCP&L
            
            $
            26
            
            $
            30
            
            $
            67
            
            $
            71Met-Ed
            
            
            12
            
            
            13
            
            
            44
            
            
            40Penelec
            
            
            8
            
            
            7
            
            
            25
            
            
            22Total
            
            $
            46
            
            $
            50
            
            $
            136
            
            $
            133





Transition Bonds





The consolidated
financial statements of FirstEnergy and JCP&L include the results of
JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned
limited liability companies of JCP&L. In June 2002, JCP&L Transition
Funding sold $320 million of transition bonds to securitize the recovery of
JCP&L's bondable stranded costs associated with the previously divested
Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition
Funding II sold $182 million of transition bonds to securitize the recovery
of deferred costs associated with JCP&L’s supply of BGS.





JCP&L did not
purchase and does not own any of the transition bonds, which are included as
long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As
of September 30, 2008, $377 million of the transition bonds were
outstanding. The transition bonds are the sole obligations of JCP&L
Transition Funding and JCP&L Transition Funding II and are collateralized by
each company’s equity and assets - principally bondable transition
property.





Bondable transition
property under New Jersey law represents the irrevocable right of a utility
company to charge, collect and receive from its customers, through a
non-bypassable transition bond charge (TBC), the principal amount and interest
on transition bonds and other fees and expenses associated with their issuance.
JCP&L sold its bondable transition property to JCP&L Transition Funding
and JCP&L Transition Funding II and, as servicer, manages and administers
the bondable transition property, including the billing, collection and
remittance of the TBC, pursuant to separate servicing agreements with JCP&L
Transition Funding and JCP&L Transition Funding II. For the two series of
transition bonds, JCP&L is entitled to aggregate quarterly servicing fees of
$157,000 payable from TBC collections.





10.
INCOME TAXES





FirstEnergy accounts
for uncertainty in income taxes recognized in a company’s financial statements
in accordance with FIN 48. This interpretation prescribes a recognition
threshold and measurement attribute for financial statement recognition and
measurement of tax positions taken or expected to be taken on a company’s tax
return. FIN 48 also provides guidance on derecognition, classification,
interest, penalties, accounting in interim periods, disclosure and transition.
The evaluation of a tax position in accordance with this interpretation is a
two-step process. The first step is to determine if it is more likely than not
that a tax position will be sustained upon examination, based on the merits of
the position, and should therefore be recognized. The second step is to measure
a tax position that meets the more likely than not recognition threshold to
determine the amount of income tax benefit to recognize in the financial
statements.





Of the total amount
of unrecognized income tax benefits, $92 million would favorably affect
FirstEnergy’s effective tax rate, if recognized in 2008. The majority of items
that would not affect the 2008 effective tax rate would be purchase accounting
adjustments to goodwill, if recognized in 2008. Upon completion of the federal
tax examinations for tax years 2004 to 2006 in the third quarter of 2008,
FirstEnergy recognized approximately $45 million in tax benefits, including
$5 million that favorably affected FirstEnergy’s effective tax rate. A
majority of the tax benefits recognized in the third quarter of 2008 adjusted
goodwill as a purchase accounting adjustment ($20 million) and accumulated
deferred income taxes for temporary tax items ($15 million). During the
first nine months of 2007, there were no material changes to FirstEnergy’s
unrecognized tax benefits. As of September 30, 2008, FirstEnergy expects
that it is reasonably possible that approximately $151 million of the
unrecognized benefits may be resolved within the next twelve months, of which
$54 million to $147 million, if recognized, would affect FirstEnergy’s
effective tax rate. The potential decrease in the amount of unrecognized tax
benefits is primarily associated with issues related to the capitalization of
certain costs capital gains and losses recognized on the disposition of assets
and various other tax items.





120








FIN 48 also requires
companies to recognize interest expense or income related to uncertain tax
positions. That amount is computed by applying the applicable statutory interest
rate to the difference between the tax position recognized in accordance with
FIN 48 and the amount previously taken or expected to be taken on the tax
return. FirstEnergy includes net interest and penalties in the provision for
income taxes, consistent with its policy prior to implementing FIN 48. The
reversal of accrued interest associated with the $45 million in recognized tax
benefits favorably affected FirstEnergy’s effective tax rate by $12 million
in the third quarter and first nine months of 2008 and an interest receivable of
$4 million was removed from the accrued interest for FIN 48 items. The net
amount of interest accrued as of September 30, 2008 was $56 million,
as compared to $53 million as of December 31, 2007.





FirstEnergy has tax
returns that are under review at the audit or appeals level by the IRS and state
tax authorities. All state jurisdictions are open from 2001-2007. The IRS began
reviewing returns for the years 2001-2003 in July 2004 and several items are
under appeal. The federal audits for the years 2004-2006 were completed in the
third quarter of 2008 and several items are under appeal. The IRS began auditing
the year 2007 in February 2007 and the year 2008 in February 2008 under its
Compliance Assurance Process program. Neither audit is expected to close before
December 2008. Management believes that adequate reserves have been recognized
and final settlement of these audits is not expected to have a material adverse
effect on FirstEnergy’s financial condition or results of
operations.





11.  COMMITMENTS,
GUARANTEES AND CONTINGENCIES





(A)    GUARANTEES
AND OTHER ASSURANCES





As part of normal
business activities, FirstEnergy enters into various agreements on behalf of its
subsidiaries to provide financial or performance assurances to third parties.
These agreements include contract guarantees, surety bonds and LOCs. As of
September 30, 2008, outstanding guarantees and other assurances aggregated
approximately $4.2 billion, consisting of parental guarantees -
$0.9 billion, subsidiaries’ guarantees - $2.7 billion, surety bonds -
$0.1 billion and LOCs - $0.5 billion.





FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved in
energy commodity activities principally to facilitate or hedge normal physical
transactions involving electricity, gas, emission allowances and coal.
FirstEnergy also provides guarantees to various providers of credit support for
the financing or refinancing by subsidiaries of costs related to the acquisition
of property, plant and equipment. These agreements legally obligate FirstEnergy
to fulfill the obligations of those subsidiaries directly involved in energy and
energy-related transactions or financing where the law might otherwise limit the
counterparties' claims. If demands of a counterparty were to exceed the ability
of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables
the counterparty's legal claim to be satisfied by other FirstEnergy assets. The
likelihood is remote that such parental guarantees of $0.4 billion
(included in the $0.9 billion discussed above) as of September 30,
2008 would increase amounts otherwise payable by FirstEnergy to meet its
obligations incurred in connection with financings and ongoing energy and
energy-related activities.





While these types of
guarantees are normally parental commitments for the future payment of
subsidiary obligations, subsequent to the occurrence of a credit rating
downgrade or “material adverse event,” the immediate posting of cash collateral,
provision of an LOC or accelerated payments may be required of the subsidiary.
As of September 30, 2008, FirstEnergy's maximum exposure under these
collateral provisions was $573 million, consisting of $64 million due to
“material adverse event” contractual clauses and $509 million due to a below
investment grade credit rating. Additionally, stress case conditions of a credit
rating downgrade or “material adverse event” and hypothetical adverse price
movements in the underlying commodity markets would increase this amount to $648
million, consisting of $58 million due to “material adverse event” contractual
clauses and $590 million due to a below investment grade credit
rating.





FES, through
potential participation in utility sponsored competitive power procurement
processes (including those of affiliates) or through forward hedging
transactions and as a consequence of future power price movements, could be
required to post significantly higher collateral to support its power
transactions.


Most of
FirstEnergy's surety bonds are backed by various indemnities common within the
insurance industry. Surety bonds and related guarantees of $94 million
provide additional assurance to outside parties that contractual and statutory
obligations will be met in a number of areas including construction contracts,
environmental commitments and various retail transactions.





In July 2007,
FGCO completed a sale and leaseback transaction for its 93.825% undivided
interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably
guaranteed all of FGCO’s obligations under each of the leases (see
Note 15). The related lessor notes and pass through certificates are not
guaranteed by FES or FGCO, but the notes are secured by, among other things,
each lessor trust’s undivided interest in Unit 1, rights and interests under the
applicable lease and rights and interests under other related agreements,
including FES’ lease guaranty.





121








On October 8, 2008,
to enhance their liquidity position in the face of the turbulent credit and bond
markets, FirstEnergy and its subsidiaries, FES and FGCO entered into a $300
million secured term loan facility with Credit Suisse. Under the facility, FGCO
is the borrower and FES and FirstEnergy are guarantors. Generally, the facility
is available to FGCO until October 7, 2009, with a minimum borrowing amount
of $100 million and maturity 30 days from the date of the borrowing. Once
repaid, borrowings may not be re-borrowed.





In early October
2008, FirstEnergy took steps to further enhance its liquidity position by
negotiating with the banks that have issued irrevocable direct pay LOCs in
support of its outstanding variable interest rate PCRBs to extend the respective
reimbursement obligations of the applicable FirstEnergy subsidiary obligors in
the event that such LOCs are drawn upon. FirstEnergy’s subsidiaries currently
have approximately $2.1 billion variable interest rate PCRBs outstanding (FES -
$1.9 billion, OE - $156 million, Met-Ed - $29 million and Penelec -
$45 million). The LOCs supporting these PCRBs may be drawn upon to pay the
purchase price to bondholders that have exercised the right to tender their
PCRBs for mandatory purchase. As a result of these negotiations, a total of
approximately $902 million of LOCs that previously required reimbursement within
30 days or less of a draw under the applicable LOC have now been modified to
extend the reimbursement obligations to six months or June 2009, as
applicable.





(B)
            ENVIRONMENTAL
      MATTERS





Various federal,
state and local authorities regulate FirstEnergy with regard to air and water
quality and other environmental matters. The effects of compliance on
FirstEnergy with regard to environmental matters could have a material adverse
effect on FirstEnergy's earnings and competitive position to the extent that it
competes with companies that are not subject to such regulations and, therefore,
do not bear the risk of costs associated with compliance, or failure to comply,
with such regulations. FirstEnergy estimates capital expenditures for
environmental compliance of approximately $1.4 billion for the period
2008-2012.





FirstEnergy accrues
environmental liabilities only when it concludes that it is probable that it has
an obligation for such costs and can reasonably estimate the amount of such
costs. Unasserted claims are reflected in FirstEnergy’s determination of
environmental liabilities and are accrued in the period that they become both
probable and reasonably estimable.





Clean Air Act Compliance





FirstEnergy is
required to meet federally-approved SO2 emissions
regulations. Violations of such regulations can result in the shutdown of the
generating unit involved and/or civil or criminal penalties of up to $32,500 for
each day the unit is in violation. The EPA has an interim enforcement policy for
SO2
regulations in Ohio that allows for compliance based on a 30-day averaging
period. FirstEnergy believes it is currently in compliance with this policy, but
cannot predict what action the EPA may take in the future with respect to the
interim enforcement policy.





The EPA Region 5
issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June
15, 2006, alleging violations to various sections of the CAA. FirstEnergy has
disputed those alleged violations based on its CAA permit, the Ohio SIP and
other information provided to the EPA at an August 2006 meeting with the EPA.
The EPA has several enforcement options (administrative compliance order,
administrative penalty order, and/or judicial, civil or criminal action) and has
indicated that such option may depend on the time needed to achieve and
demonstrate compliance with the rules alleged to have been violated. On
June 5, 2007, the EPA requested another meeting to discuss “an appropriate
compliance program” and a disagreement regarding emission limits applicable to
the common stack for Bay Shore Units 2, 3 and 4.





FirstEnergy complies
with SO2 reduction
requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NOX reductions
required by the 1990 Amendments are being achieved through combustion controls
and the generation of more electricity at lower-emitting plants. In September
1998, the EPA finalized regulations requiring additional NOX reductions
at FirstEnergy's facilities. The EPA's NOX Transport
Rule imposes uniform reductions of NOX emissions
(an approximate 85% reduction in utility plant NOX emissions
from projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NOX emissions
are contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NOX budgets
established under SIPs through combustion controls and post-combustion controls,
including Selective Catalytic Reduction and SNCR systems, and/or using emission
allowances.





122








In 1999 and 2000,
the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn
based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR
Litigation) and filed similar complaints involving 44 other U.S. power plants.
This case, along with seven other similar cases, is referred to as the NSR
cases.  OE’s and Penn’s settlement with the EPA, the DOJ and three
states (Connecticut, New Jersey and New York) that resolved all issues related
to the Sammis NSR litigation was approved by the Court on July 11, 2005. This
settlement agreement, in the form of a consent decree, requires reductions of
NOX
and SO2 emissions
at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the
installation of pollution control devices and provides for stipulated penalties
for failure to install and operate such pollution controls in accordance with
that agreement. Capital expenditures necessary to complete requirements of the
Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion
for 2008-2012 ($650 million of which is expected to be spent during 2008,
with the largest portion of the remaining $650 million expected to be spent
in 2009). This amount is included in the estimated capital expenditures for
environmental compliance referenced above. On September 8, 2008, the
Environmental Enforcement Section of the DOJ sent a letter to OE regarding its
view that the company was not in compliance with the Sammis NSR Litigation
consent decree because the installation of an SNCR at Eastlake Unit 5 was not
completed by December 31, 2006. However, the DOJ acknowledged that
stipulated penalties could not apply under the terms of the Sammis NSR
Litigation consent decree because Eastlake Unit 5 was idled on December 31,
2006 pending installation of the SNCR and advised that it had exercised its
discretion not to seek any other penalties for this alleged non-compliance. OE
disputed the DOJ's interpretation of the consent decree in a letter dated
September 22, 2008. Although the Eastlake Unit 5 issue is no longer active, OE
filed a dispute resolution petition on October 23, 2008, with the United
States District Court for the Southern District of Ohio, due to potential
impacts on its compliance decisions with respect to Burger Units 4 and 5. Under
the Sammis NSR Litigation consent decree, an election to repower by
December 31, 2012, install flue gas desulfurization (FGD) by December 31,
2010, or permanently shut down those units by December 31, 2010, is due no
later than December 31, 2008. Although FirstEnergy will meet the
December 31, 2008 deadline for making an election, one potential compliance
option, should FGD be elected, would be to idle Burger Units 4 and 5 on
December 31, 2010 pending completion of the FGD installation. Thus, OE is
seeking a determination by the Court whether this approach is indeed in
compliance with the terms of the Sammis NSR Litigation consent decree. The Court
has scheduled a hearing on OE’s dispute resolution petition for
November 17, 2008. The outcome of this dispute resolution process could
have an impact on the option FirstEnergy ultimately elects with respect to
Burger Units 4 and 5.





On April 2,
2007, the United States Supreme Court ruled that changes in annual emissions (in
tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must
be used to determine whether an emissions increase triggers NSR. Subsequently,
on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize
changes in the hourly emission rate (in kilograms/hour) to determine whether an
emissions increase triggers NSR.   The EPA has not yet issued a
final regulation. FGCO’s future cost of compliance with those regulations may be
substantial and will depend on how they are ultimately implemented.





On May 22, 2007,
FirstEnergy and FGCO received a notice letter, required 60 days prior to the
filing of a citizen suit under the federal CAA, alleging violations of air
pollution laws at the Bruce Mansfield Plant, including opacity limitations.
Prior to the receipt of this notice, the Plant was subject to a Consent Order
and Agreement with the Pennsylvania Department of Environmental Protection
concerning opacity emissions under which efforts to achieve compliance with the
applicable laws will continue. On October 18, 2007, PennFuture filed a
complaint, joined by three of its members, in the United States District Court
for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed
a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the
Court denied the motion to dismiss, but also ruled that monetary damages could
not be recovered under the public nuisance claim. In July 2008, three additional
complaints were filed against FGCO in the United States District Court for the
Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant
air emissions. In addition to seeking damages, two of the complaints seek to
enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible,
prudent and proper manner”, one being a complaint filed on behalf of twenty-one
individuals and the other being a class action complaint, seeking certification
as a class action with the eight named plaintiffs as the class representatives.
On October 14, 2008, the Court granted FGCO’s motion to consolidate
discovery for all four complaints pending against the Bruce Mansfield Plant.
FGCO believes the claims are without merit and intends to defend itself against
the allegations made in these complaints.





On December 18,
2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations
at the Portland Generation Station against Reliant (the current owner and
operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in
1999), GPU, Inc. and Met-Ed.  Specifically, New Jersey alleges that
"modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without
preconstruction NSR or permitting under the CAA's prevention of significant
deterioration program, and seeks injunctive relief, penalties, attorney fees and
mitigation of the harm caused by excess emissions. On March 14, 2008,
Met-Ed filed a motion to dismiss the citizen suit claims against it and a
stipulation in which the parties agreed that GPU, Inc. should be dismissed from
this case. On March 26, 2008, GPU, Inc. was dismissed by the United States
District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe
Energy is disputed.  By letter dated October 1, 2008, New Jersey
informed the Court of its intent to file an amended complaint. Met-Ed is unable
to predict the outcome of this matter.





123








On June 11, 2008,
the EPA issued a Notice and Finding of Violation to MEW alleging that
"modifications" at the Homer City Power Station occurred since 1988 to the
present without preconstruction NSR or permitting under the CAA's prevention of
significant deterioration program. MEW is seeking indemnification from Penelec,
the co-owner (along with New York State Electric and Gas Company) and operator
of the Homer City Power Station prior to its sale in 1999.  The scope
of Penelec’s indemnity obligation to and from MEW is
disputed.  Penelec is unable to predict the outcome of this
matter.





On May 16, 2008,
FGCO received a request from the EPA for information pursuant to Section 114(a)
of the CAA for certain operating and maintenance information regarding the
Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA
to determine whether these generating sources are complying with the NSR
provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an
ACO modifying that request and setting forth a schedule for FGCO’s response.
FGCO complied with the modified schedule and otherwise intends to fully comply
with the ACO, but, at this time, is unable to predict the outcome of this
matter.





On August 18, 2008,
FirstEnergy received a request from the EPA for information pursuant to Section
114(a) of the CAA for certain operating and maintenance information regarding
the Avon Lake and Niles generating plants, as well as a copy of a nearly
identical request directed to the current owner, Reliant Energy, to allow the
EPA to determine whether these generating sources are complying with the NSR
provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s
information request, but, at this time, is unable to predict the outcome of this
matter.





National Ambient Air Quality
Standards





In March 2005,
the EPA finalized the CAIR covering a total of 28 states (including Michigan,
New Jersey, Ohio and Pennsylvania) and the District of Columbia based on
proposed findings that air emissions from 28 eastern states and the District of
Columbia significantly contribute to non-attainment of the NAAQS for fine
particles and/or the "8-hour" ozone NAAQS in other states. CAIR would have
required reductions of NOX and
SO2
emissions in two phases (Phase I in 2009 for NOX, 2010 for
SO2
and Phase II in 2015 for both NOX and
SO2),
ultimately capping SO2 emissions
in affected states to just 2.5 million tons annually and NOX emissions
to just 1.3 million tons annually. CAIR was challenged in the United States
Court of Appeals for the District of Columbia and on July 11, 2008, the Court
vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from
the ground up.” The Court ruling also vacated the CAIR regional cap and trade
requirements for SO2 and
NOX,
which is currently not expected to, but may, materially impair the value of
emissions allowances obtained for future compliance. On September 24, 2008, the
EPA, utility, mining and certain environmental advocacy organizations petitioned
the Court for a rehearing to reconsider its ruling vacating CAIR.  On
October 21, 2008, the Court ordered the parties who appealed CAIR to file
responses to the rehearing petitions by November 5, 2008 and directed them to
address (1) whether any party is seeking vacatur of CAIR and (2) whether the
Court should stay its vacatur of CAIR until EPA promulgates a revised rule. The
future cost of compliance with these regulations may be substantial and will
depend on the Court’s ruling on rehearing, as well as the action taken by the
EPA or Congress in response to the Court’s ruling.





Mercury Emissions





In December 2000,
the EPA announced it would proceed with the development of regulations regarding
hazardous air pollutants from electric power plants, identifying mercury as the
hazardous air pollutant of greatest concern. In March 2005, the EPA finalized
the CAMR, which provides a cap-and-trade program to reduce mercury emissions
from coal-fired power plants in two phases; initially, capping national mercury
emissions at 38 tons by 2010 (as a "co-benefit" from implementation of
SO2
and NOX emission
caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states
and environmental groups appealed the CAMR to the United States Court of Appeals
for the District of Columbia. On February 8, 2008, the Court vacated the
CAMR, ruling that the EPA failed to take the necessary steps to “de-list”
coal-fired power plants from its hazardous air pollutant program and, therefore,
could not promulgate a cap-and-trade program. The EPA petitioned for rehearing
by the entire Court, which denied the petition on May 20, 2008.  On
October 17, 2008, the EPA (and an industry group) petitioned the United
States Supreme Court for review of the Court’s ruling vacating CAMR. The Supreme
Court could grant the EPA’s petition and alter some or all of the lower Court’s
decision, or the EPA could take regulatory action to promulgate new mercury
emission standards for coal-fired power plants. FGCO’s future cost of compliance
with mercury regulations may be substantial and will depend on the action taken
by the EPA and on how they are ultimately implemented.





Pennsylvania has
submitted a new mercury rule for EPA approval that does not provide a
cap-and-trade approach as in the CAMR, but rather follows a command-and-control
approach imposing emission limits on individual sources. It is anticipated that
compliance with these regulations, if approved by the EPA and implemented, would
not require the addition of mercury controls at the Bruce Mansfield Plant,
FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at
all.





124








Climate Change





In December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol, to address global warming by reducing the amount of man-made
GHG emitted by developed countries by 2012. The United States signed the Kyoto
Protocol in 1998 but it was never submitted for ratification by the United
States Senate. However, the Bush administration has committed the United States
to a voluntary climate change strategy to reduce domestic GHG intensity – the
ratio of emissions to economic output – by 18% through 2012. Also, in an
April 16, 2008 speech, President Bush set a policy goal of stopping the
growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In
addition, the EPACT established a Committee on Climate Change Technology to
coordinate federal climate change activities and promote the development and
deployment of GHG reducing technologies.





There are a number
of initiatives to reduce GHG emissions under consideration at the federal, state
and international level.  At the international level, efforts to reach
a new global agreement to reduce GHG emissions post-2012 have begun with the
Bali Roadmap, which outlines a two-year process designed to lead to an agreement
in 2009. At the federal level, members of Congress have introduced several bills
seeking to reduce emissions of GHG in the United States, and the Senate
Environment and Public Works Committee has passed one such bill. State
activities, primarily the northeastern states participating in the Regional
Greenhouse Gas Initiative and western states led by California, have coordinated
efforts to develop regional strategies to control emissions of certain
GHGs.





On April 2, 2007,
the United States Supreme Court found that the EPA has the authority to regulate
CO2
emissions from automobiles as “air pollutants” under the CAA. Although this
decision did not address CO2 emissions
from electric generating plants, the EPA has similar authority under the CAA to
regulate “air pollutants” from those and other facilities. On July 11,
2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting
input from the public on the effects of climate change and the potential
ramifications of regulation of CO2 under the
CAA.





FirstEnergy cannot
currently estimate the financial impact of climate change policies, although
potential legislative or regulatory programs restricting CO2 emissions
could require significant capital and other expenditures. The CO2 emissions
per KWH of electricity generated by FirstEnergy is lower than many regional
competitors due to its diversified generation sources, which include low or
non-CO2 emitting
gas-fired and nuclear generators.





Clean Water Act





Various water
quality regulations, the majority of which are the result of the federal Clean
Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio,
New Jersey and Pennsylvania have water quality standards applicable to
FirstEnergy's operations. As provided in the Clean Water Act, authority to grant
federal National Pollutant Discharge Elimination System water discharge permits
can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such
authority.





On September 7,
2004, the EPA established new performance standards under Section 316(b) of the
Clean Water Act for reducing impacts on fish and shellfish from cooling water
intake structures at certain existing large electric generating plants. The
regulations call for reductions in impingement mortality (when aquatic organisms
are pinned against screens or other parts of a cooling water intake system) and
entrainment (which occurs when aquatic life is drawn into a facility's cooling
water system). On January 26, 2007, the United States Court of Appeals for the
Second Circuit remanded portions of the rulemaking dealing with impingement
mortality and entrainment back to the EPA for further rulemaking and eliminated
the restoration option from the EPA’s regulations. On July 9, 2007, the EPA
suspended this rule, noting that until further rulemaking occurs, permitting
authorities should continue the existing practice of applying their best
professional judgment to minimize impacts on fish and shellfish from cooling
water intake structures. On April 14, 2008, the Supreme Court of the United
States granted a petition for a writ of certiorari to review one significant
aspect of the Second Circuit Court’s opinion which is whether
Section 316(b) of the Clean Water Act authorizes the EPA to compare costs
with benefits in determining the best technology available for minimizing
adverse environmental impact at cooling water intake structures.  Oral
argument before the Supreme Court is scheduled for December 2, 2008. FirstEnergy
is studying various control options and their costs and effectiveness. Depending
on the results of such studies, the outcome of the Supreme Court’s review of the
Second Circuit’s decision, the EPA’s further rulemaking and any action taken by
the states exercising best professional judgment, the future costs of compliance
with these standards may require material capital expenditures.





Regulation of Hazardous
Waste





As a result of the
Resource Conservation and Recovery Act of 1976, as amended, and the Toxic
Substances Control Act of 1976, federal and state hazardous waste regulations
have been promulgated. Certain fossil-fuel combustion waste products, such as
coal ash, were exempted from hazardous waste disposal requirements pending the
EPA's evaluation of the need for future regulation. The EPA subsequently
determined that regulation of coal ash as a hazardous waste is unnecessary. In
April 2000, the EPA announced that it will develop national standards regulating
disposal of coal ash under its authority to regulate non-hazardous
waste.





125








Under NRC
regulations, FirstEnergy must ensure that adequate funds will be available to
decommission its nuclear facilities.  As of September 30, 2008,
FirstEnergy had approximately $1.9 billion invested in external trusts to be
used for the decommissioning and environmental remediation of Davis-Besse,
Beaver Valley, Perry and TMI-2. As part of the application to the NRC to
transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005,
FirstEnergy agreed to contribute another $80 million to these trusts by 2010.
Consistent with NRC guidance, utilizing a “real” rate of return on these funds
of approximately 2% over inflation, these trusts are expected to exceed the
minimum decommissioning funding requirements set by the NRC. Conservatively,
these estimates do not include any rate of return that the trusts may earn over
the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1
as it relates to the timing of the decommissioning of TMI-2) seeks for these
facilities.





The Utilities have
been named as PRPs at waste disposal sites, which may require cleanup under the
Comprehensive Environmental Response, Compensation, and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site may be liable on a
joint and several basis. Therefore, environmental liabilities that are
considered probable have been recognized on the Consolidated Balance Sheet as of
September 30, 2008, based on estimates of the total costs of cleanup, the
Utilities' proportionate responsibility for such costs and the financial ability
of other unaffiliated entities to pay. Total liabilities of approximately
$94 million (JCP&L - $68 million, TE - $1 million, CEI -
$1 million and FirstEnergy Corp. - $24 million) have been accrued
through September 30, 2008. Included in the total for JCP&L are accrued
liabilities of approximately $57 million for environmental remediation of
former manufactured gas plants in New Jersey, which are being recovered by
JCP&L through a non-bypassable SBC.





(C)    OTHER LEGAL
PROCEEDINGS





Power Outages and Related
Litigation





In July 1999, the
Mid-Atlantic States experienced a severe heat wave, which resulted in power
outages throughout the service territories of many electric utilities, including
JCP&L's territory. In an investigation into the causes of the outages and
the reliability of the transmission and distribution systems of all four of New
Jersey’s electric utilities, the NJBPU concluded that there was not a prima
facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or
improper service to its customers. Two class action lawsuits (subsequently
consolidated into a single proceeding) were filed in New Jersey Superior Court
in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory.





In August 2002, the
trial Court granted partial summary judgment to JCP&L and dismissed the
plaintiffs' claims for consumer fraud, common law fraud, negligent
misrepresentation, and strict product liability. In November 2003, the trial
Court granted JCP&L's motion to decertify the class and denied plaintiffs'
motion to permit into evidence their class-wide damage model indicating damages
in excess of $50 million. These class decertification and damage rulings were
appealed to the Appellate Division. The Appellate Division issued a decision in
July 2004, affirming the decertification of the originally certified class, but
remanding for certification of a class limited to those customers directly
impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a
common incident involving the failure of the bushings of two large transformers
in the Red Bank substation resulting in planned and unplanned outages in the
area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify
the class based on a very limited number of class members who incurred damages
and also filed a motion for summary judgment on the remaining plaintiffs’ claims
for negligence, breach of contract and punitive damages. In July 2006, the New
Jersey Superior Court dismissed the punitive damage claim and again decertified
the class based on the fact that a vast majority of the class members did not
suffer damages and those that did would be more appropriately addressed in
individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate
Division which, in March 2007, reversed the decertification of the Red Bank
class and remanded this matter back to the Trial Court to allow plaintiffs
sufficient time to establish a damage model or individual proof of damages.
JCP&L filed a petition for allowance of an appeal of the Appellate Division
ruling to the New Jersey Supreme Court which was denied in May
2007.  Proceedings are continuing in the Superior Court and a case
management conference with the presiding Judge was held on June 13,
2008.  At that conference, the plaintiffs stated their intent to drop
their efforts to create a class-wide damage model and, instead of dismissing the
class action, expressed their desire for a bifurcated trial on liability and
damages. The judge directed the plaintiffs to indicate, on or before
August 22, 2008, how they intend to proceed under this scenario.
Thereafter, the judge expects to hold another pretrial conference to address
plaintiffs' proposed procedure.JCP&L has received
the plaintiffs’ proposed plan of action, and intends to file its objection to
the proposed plan, and also file a renewed motion to decertify the class.
JCP&L is defending this action but is unable to predict the outcome. No
liability has been accrued as of September 30, 2008.





126





Nuclear
Plant Matters





On May 14, 2007, the
Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply
to an April 2, 2007 NRC request for information about two reports prepared by
expert witnesses for an insurance arbitration (the insurance claim was
subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse.
The NRC indicated that this information was needed for the NRC “to determine
whether an Order or other action should be taken pursuant to 10 CFR 2.202, to
provide reasonable assurance that FENOC will continue to operate its licensed
facilities in accordance with the terms of its licenses and the Commission’s
regulations.” FENOC was directed to submit the information to the NRC within 30
days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that
it accepts full responsibility for the mistakes and omissions leading up to the
damage to the reactor vessel head and that it remains committed to operating
Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC
submitted a supplemental response clarifying certain aspects of the DFI response
to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a
confirmatory order imposing these commitments. FENOC must inform the NRC’s
Office of Enforcement after it completes the key commitments embodied in the
NRC’s order. FENOC has conducted the employee training required by the
confirmatory order and a consultant has performed follow-up reviews to ensure
the effectiveness of that training.  The NRC continues to monitor
FENOC’s compliance with all the commitments made in the confirmatory
order.





In August 2007,
FENOC submitted an application to the NRC to renew the operating licenses for
the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The
NRC is required by statute to provide an opportunity for members of the public
to request a hearing on the application. No members of the public, however,
requested a hearing on the Beaver Valley license renewal application. On
September 24, 2008, the NRC issued a draft supplemental Environmental
Impact Statement for Beaver Valley. FENOC will continue to work with the
NRC Staff as it completes its environmental and technical reviews of the license
renewal application, and expects to obtain renewed licenses for the Beaver
Valley Power Station in 2009. If renewed licenses are issued by the NRC, the
Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for
Units 1 and 2, respectively.





Other Legal Matters





There are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to FirstEnergy's normal business operations pending against FirstEnergy
and its subsidiaries. The other potentially material items not otherwise
discussed above are described below.





On August 22, 2005,
a class action complaint was filed against OE in Jefferson County, Ohio Common
Pleas Court, seeking compensatory and punitive damages to be determined at trial
based on claims of negligence and eight other tort counts alleging damages from
W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking
injunctive relief to eliminate harmful emissions and repair property damage and
the institution of a medical monitoring program for class members. On
April 5, 2007, the Court rejected the plaintiffs’ request to certify this
case as a class action and, accordingly, did not appoint the plaintiffs as class
representatives or their counsel as class counsel. On July 30, 2007,
plaintiffs’ counsel voluntarily withdrew their request for reconsideration of
the April 5, 2007 Court order denying class certification and the Court
heard oral argument on the plaintiffs’ motion to amend their complaint, which OE
opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to
amend their complaint. The plaintiffs have appealed the Court’s denial of the
motion for certification as a class action and motion to amend their complaint
and oral argument was held on November 5, 2008.





JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
panel decided not to hear testimony on damages and closed the proceedings. On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district Court granted a union motion to dismiss, as premature,
a JCP&L appeal of the award filed on October 18, 2005. A final order
identifying the individual damage amounts was issued on October 31, 2007.
The award appeal process was initiated. The union filed a motion with the
federal Court to confirm the award and JCP&L filed its answer and
counterclaim to vacate the award on December 31, 2007. JCP&L and the
union filed briefs in June and July of 2008 and oral arguments were held in the
fall. The Court has yet to render its decision. JCP&L recognized a liability
for the potential $16 million award in 2005.





The union employees
at the Bruce Mansfield Plant have been working without a labor contract since
February 15, 2008. The parties are continuing to bargain with the
assistance of a federal mediator. FirstEnergy has a strike mitigation plan ready
in the event of a strike.





FirstEnergy accrues
legal liabilities only when it concludes that it is probable that it has an
obligation for such costs and can reasonably estimate the amount of such costs.
If it were ultimately determined that FirstEnergy or its subsidiaries have legal
liability or are otherwise made subject to liability based on the above matters,
it could have a material adverse effect on FirstEnergy's or its subsidiaries'
financial condition, results of operations and cash flows.





127





12.  REGULATORY
MATTERS





(A)    RELIABILITY
INITIATIVES





In late 2003 and
early 2004, a series of letters, reports and recommendations were issued from
various entities, including governmental, industry and ad hoc reliability
entities (the PUCO, the FERC, the NERC and the U.S. – Canada Power System Outage
Task Force) regarding enhancements to regional reliability. The proposed
enhancements were divided into two groups:  enhancements that were to
be completed in 2004; and enhancements that were to be completed after
2004.  In 2004, FirstEnergy completed all of the enhancements that
were recommended for completion in 2004. FirstEnergy is also proceeding with the
implementation of the recommendations that were to be completed subsequent to
2004 and will continue to periodically assess the FERC-ordered Reliability Study
recommendations for forecasted 2009 system conditions, recognizing revised load
forecasts and other changing system conditions which may impact the
recommendations. Thus far, implementation of the recommendations has not
required, nor is expected to require, substantial investment in new or material
upgrades to existing equipment. The FERC or other applicable government agencies
and reliability coordinators may, however, take a different view as to
recommended enhancements or may recommend additional enhancements in the future
that could require additional material expenditures.





As a result of
outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU
performed a review of JCP&L’s service reliability. On June 9, 2004, the
NJBPU approved a stipulation that addresses a third-party consultant’s
recommendations on appropriate courses of action necessary to ensure system-wide
reliability. The stipulation incorporates the consultant’s focused audit of, and
recommendations regarding, JCP&L’s Planning and Operations and Maintenance
programs and practices. On June 1, 2005, the consultant completed his work and
issued his final report to the NJBPU. On July 14, 2006, JCP&L filed a
comprehensive response to the consultant’s report with the NJBPU. JCP&L will
complete the remaining substantive work described in the stipulation in
2008.  JCP&L continues to file compliance reports with the NJBPU
reflecting JCP&L’s activities associated with implementing the
stipulation.





In 2005, Congress
amended the Federal Power Act to provide for federally-enforceable mandatory
reliability standards. The mandatory reliability standards apply to the bulk
power system and impose certain operating, record-keeping and reporting
requirements on the Utilities and ATSI. The NERC is charged with establishing
and enforcing these reliability standards, although it has delegated day-to-day
implementation and enforcement of its responsibilities to eight regional
entities, including ReliabilityFirst
Corporation.  All of FirstEnergy’s facilities are located within the
ReliabilityFirst
region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes,
and otherwise monitors and manages its companies in response to the ongoing
development, implementation and enforcement of the reliability
standards.





FirstEnergy believes
that it is in compliance with all currently-effective and enforceable
reliability standards.  Nevertheless, it is clear that the NERC,
ReliabilityFirst and
the FERC will continue to refine existing reliability standards as well as to
develop and adopt new reliability standards. The financial impact of complying
with new or amended standards cannot be determined at this time. However, the
2005 amendments to the Federal Power Act provide that all prudent costs incurred
to comply with the new reliability standards be recovered in rates. Still, any
future inability on FirstEnergy’s part to comply with the reliability standards
for its bulk power system could result in the imposition of financial penalties
and thus have a material adverse effect on its financial condition, results of
operations and cash flows.





In April 2007,
ReliabilityFirst
performed a routine compliance audit of FirstEnergy’s bulk-power system within
the Midwest ISO region and found it to be in full compliance with all audited
reliability standards.  Similarly, ReliabilityFirst scheduled a compliance
audit of FirstEnergy’s bulk-power system within the PJM region in October 2008.
FirstEnergy currently does not expect any material adverse financial impact as a
result of these audits.





(B)   
OHIO





On January 4,
2006, the PUCO issued an order authorizing the Ohio Companies to recover certain
increased fuel costs through a fuel rider and to defer certain other increased
fuel costs to be incurred from January 1, 2006 through December 31,
2008, including interest on the deferred balances. The order also provided for
recovery of the deferred costs over a twenty-five-year period through
distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that
the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio
Companies “to collect deferred increased fuel costs through future distribution
rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred
distribution-related expenses” and remanded the matter to the PUCO for further
consideration. On September 10, 2007 the Ohio Companies filed an
application with the PUCO that requested the implementation of two
generation-related fuel cost riders to collect the increased fuel costs that
were previously authorized to be deferred. On January 9, 2008 the PUCO
approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel
costs to be incurred in 2008 commencing January 1, 2008 through
December 31, 2008, which is expected to be approximately $189 million.
In addition, the PUCO ordered the Ohio Companies to file a separate application
for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel
costs. On February 8, 2008, the Ohio Companies filed an application
proposing to recover $226 million of deferred fuel costs and carrying
charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the
deferred fuel costs is addressed in the Ohio Companies’ comprehensive ESP
filing, as described below. If the recovery of the deferred fuel costs is not
resolved in the ESP, or in the event the MRO is implemented, recovery of the
deferred fuel costs will be resolved in the proceeding that was instituted with
the PUCO on February 8, 2008, as referenced above.





128








On June 7, 2007, the
Ohio Companies filed an application for an increase in electric distribution
rates with the PUCO and, on August 6, 2007, updated their filing to support
a distribution rate increase of $332 million. On December 4, 2007, the
PUCO Staff issued its Staff Reports containing the results of its investigation
into the distribution rate request. In its reports, the PUCO Staff recommended a
distribution rate increase in the range of $161 million to $180 million,
with $108 million to $127 million for distribution revenue increases and
$53 million for recovery of costs deferred under prior cases. Evidentiary
hearings began on January 29, 2008 and continued through February 25, 2008.
During the evidentiary hearings and filing of briefs, the PUCO Staff decreased
their recommended revenue increase to a range of $117 million to
$135 million. Additionally, in testimony submitted on February 11,
2008, the PUCO Staff adopted a position regarding interest deferred for
RCP-related deferrals, line extension deferrals and transition tax deferrals
that, if upheld by the PUCO, would result in the write-off of approximately
$58 million of interest costs deferred through September 30, 2008
($0.12 per share of common stock). The Ohio Companies’ electric distribution
rate request is addressed in their comprehensive ESP filing, as described
below.





On May 1, 2008,
Governor Strickland signed SB221, which became effective on July 31, 2008.
The bill requires all utilities to file an ESP with the PUCO. A utility also may
file an MRO in which it would have to prove the following objective market
criteria:





·
            the utility or
      its transmission service affiliate belongs to a FERC approved RTO, or
      there is comparable and nondiscriminatory access to the electric
      transmission grid;





·
            the RTO has a
      market-monitor function and the ability to mitigate market power or the
      utility’s market conduct, or a similar market monitoring function exists
      with the ability to identify and monitor market conditions and conduct;
      and





·
            a published
      source of information is available publicly or through subscription that
      identifies pricing information for traded electricity products, both on-
      and off-peak, scheduled for delivery two years into the
      future.





On July 31, 2008,
the Ohio Companies filed with the PUCO a comprehensive ESP and MRO. The MRO
outlines a CBP that would be implemented if the ESP is not approved by the PUCO.
Under SB221, a PUCO ruling on the ESP filing is required within 150 days and an
MRO decision is required within 90 days. The ESP proposes to phase in new
generation rates for customers beginning in 2009 for up to a three-year period
and would resolve the Ohio Companies’ collection of fuel costs deferred in 2006
and 2007, and the distribution rate request described above. Major provisions of
the ESP include:





·
            a phase-in of
      new generation rates for up to a three-year period, whereby customers
      would receive a 10% phase-in credit; related costs (expected to
      approximate $429 million in 2009, $488 million in 2010 and
      $553 million in 2011) would be deferred for future collection over a
      period not to exceed 10 years;





·
            a reconcilable
      rider to recover fuel transportation cost surcharges in excess of $30
      million in 2009, $20 million in 2010 and $10 million in
      2011;





·
            generation
      rate adjustments to recover any increase in fuel costs in 2011 over fuel
      costs incurred in 2010 for FES’ generation assets used to support the
      ESP;





·
            generation
      rate adjustments to recover the costs of complying with new requirements
      for certain renewable energy resources, new taxes and new environmental
      laws or new interpretations of existing laws that take effect after
      January 1, 2008 and exceed $50 million during the plan
      period;





·
            an RCP fuel
      rider to recover the 2006 and 2007 deferred fuel costs and carrying
      charges (described above) over a period not to exceed 25
      years;





·
            the resolution
      of outstanding issues pending in the Ohio Companies’ distribution rate
      case (described above), including annual electric distribution rate
      increases of $75 million for OE, $34.5 million for CEI and $40.5 million
      for TE. The new distribution rates would be effective January 1, 2009, for
      OE and TE and May 1, 2009 for CEI, with a commitment to maintain
      distribution rates through 2013. CEI also would be authorized to defer
      $25 million in distribution-related costs incurred from January 1,
      2009, through April 30, 2009;





·
            an adjustable
      delivery service improvement rider, effective January 1, 2009, through
      December 31, 2013, to ensure the Ohio Companies maintain and improve
      customer standards for service and
reliability;





·
            the waiver of
      RTC charges for CEI’s customers as of January 1, 2009, which would
      result in CEI’s write-off of approximately $485 million of estimated
      unrecoverable transition costs ($1.01 per share of common
      stock);





129








·
            the continued
      recovery of transmission costs, including MISO, ancillary services and
      congestion charges, through an annually adjusted transmission rider; a
      separate rider will be established to recover costs incurred annually
      between May 1st
      and September 30th
      for capacity purchases required to meet FERC, NERC, MISO and other
      applicable standards for planning reserve margin requirements in excess of
      amounts provided by FES as described in the ESP (the separate application
      for the recovery of these costs was filed on October 17,
      2008);





·
            a deferred
      transmission cost recovery rider effective January 1, 2009, through
      December 31, 2010 to recover transmission costs deferred by the Ohio
      Companies in 2005 and accumulated carrying charges through
      December 31, 2008; a deferred distribution cost recovery rider
      effective January 1, 2011, to recover distribution costs deferred
      under the RCP, CEI’s additional $25 million of cost deferrals in
      2009, line extension deferrals and transition tax
    deferrals;





·
            the deferral
      of annual storm damage expenses in excess of $13.9 million, certain line
      extension costs, as well as depreciation, property tax obligations and
      post in-service carrying charges on energy delivery capital investments
      for reliability and system efficiency placed in service after December 31,
      2008. Effective January 1, 2014, a rider will be established to
      collect the deferred balance and associated carrying charges over a
      10-year period; and





·
            a commitment
      by the Ohio Companies to invest in aggregate at least $1 billion in
      capital improvements in their energy delivery systems through 2013 and
      fund $25 million for energy efficiency programs and $25 million
      for economic development and job retention programs through
      2013.





Evidentiary hearings
in the ESP case concluded on October 31, 2008 and no further hearings are
scheduled. The parties are required to submit initial briefs by November 21,
2008, with all reply briefs due by December 12, 2008.





The Ohio Companies’
MRO filing outlines a CBP for providing retail generation supply if the ESP is
not approved by the PUCO or is changed and not accepted by the Ohio Companies.
The CBP would use a “slice-of-system” approach where suppliers bid on tranches
(approximately 100 MW) of the Ohio Companies’ total customer load. If the Ohio
Companies proceed with the MRO option, successful bidders (including affiliates)
would be required to post independent credit requirements and could be subject
to significant collateral calls depending upon power price movement. On
September 16, 2008, the PUCO staff filed testimony and evidentiary hearings
were held. The PUCO failed to act on October 29, 2008 as required under the
statute.  The Ohio Companies are unable to predict the outcome of this
proceeding.





The Ohio Companies
included an interim pricing proposal as part of their ESP filing, if additional
time is necessary for final PUCO approval of either the ESP or MRO. FES will be
required to obtain FERC authorization to sell electric capacity or energy to the
Ohio Companies under the ESP or MRO, unless a waiver is obtained (see FERC
Matters).





(C)  
 PENNSYLVANIA





Met-Ed and Penelec
purchase a portion of their PLR and default service requirements from FES
through a fixed-price partial requirements wholesale power sales agreement. The
agreement allows Met-Ed and Penelec to sell the output of NUG energy to the
market and requires FES to provide energy at fixed prices to replace any NUG
energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and
default service obligations. The fixed price under the agreement is expected to
remain below wholesale market prices during the term of the agreement. If Met-Ed
and Penelec were to replace the entire FES supply at current market power prices
without corresponding regulatory authorization to increase their generation
prices to customers, each company would likely incur a significant increase in
operating expenses and experience a material deterioration in credit quality
metrics. Under such a scenario, each company's credit profile would no longer be
expected to support an investment grade rating for their fixed income
securities. Based on the PPUC’s January 11, 2007 order described below, if
FES ultimately determines to terminate, reduce, or significantly modify the
agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps
in 2010, timely regulatory relief is not likely to be granted by the PPUC. See
FERC Matters below for a description of the Third Restated Partial Requirements
Agreement, executed by the parties on October 31, 2008, that limits
the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the
event of a third party supplier default, the increased costs to Met-Ed and
Penelec could be material.


Met-Ed and Penelec
made a comprehensive transition rate filing with the PPUC on April 10, 2006
to address a number of transmission, distribution and supply issues. If Met-Ed's
and Penelec's preferred approach involving accounting deferrals had been
approved, annual revenues would have increased by $216 million and
$157 million, respectively. That filing included, among other things, a
request to charge customers for an increasing amount of market-priced power
procured through a CBP as the amount of supply provided under the then existing
FES agreement was to be phased out. Met-Ed and Penelec also requested approval
of a January 12, 2005 petition for the deferral of transmission-related
costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested
recovery of annual transmission and related costs incurred on or after
January 1, 2007, plus the amortized portion of 2006 costs over a ten-year
period, along with applicable carrying charges, through an adjustable rider.
Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG
stranded costs were also included in the filing. On May 4, 2006, the PPUC
consolidated the remand of the FirstEnergy and GPU merger proceeding, related to
the quantification and allocation of merger savings, with the comprehensive
transition rate filing case.





130





The PPUC entered its
opinion and order in the comprehensive rate filing proceeding on
January 11, 2007. The order approved the recovery of transmission costs,
including the transmission-related deferral for January 1, 2006 through
January 10, 2007, and determined that no merger savings from prior years
should be considered in determining customers’ rates. The request for increases
in generation supply rates was denied as were the requested changes to NUG
expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased
Met-Ed’s and Penelec’s distribution rates by $80 million and
$19 million, respectively. These decreases were offset by the increases
allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request
for recovery of Saxton decommissioning costs was granted and, in January 2007,
Met-Ed and Penelec recognized income of $15 million and $12 million,
respectively, to establish regulatory assets for those previously expensed
decommissioning costs. Overall rates increased by 5.0% for Met-Ed
($59 million) and 4.5% for Penelec ($50 million).





On March 30, 2007,
MEIUG and PICA filed a Petition for Review with the Commonwealth Court of
Pennsylvania asking the Court to review the PPUC’s determination on transmission
(including congestion) and the transmission deferral. Met-Ed and Penelec filed a
Petition for Review on April 13, 2007 on the issues of consolidated tax savings
and the requested generation rate increase. The OCA filed its Petition for
Review on April 13, 2007, on the issues of transmission (including
congestion) and recovery of universal service costs from only the residential
rate class. From June through October 2007, initial responsive and reply briefs
were filed by various parties. The Commonwealth
Court issued its decision on November 7, 2008, which affirmed the PPUC's
January 11, 2007 order in all respects, including the deferral and recovery
of transmission and congestion related costs.





On May 22, 2008, the
PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the
period June 1, 2008, through May 31, 2009. Various intervenors filed
complaints against Met-Ed’s and Penelec’s TSC filings.  In addition,
the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC,
while at the same time allowing the company to implement the rider June 1,
2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to
consolidate the complaints against Met-Ed with its investigation and a
litigation schedule was adopted with hearings for both companies scheduled to
begin in January 2009. The TSCs include a component for under-recovery of actual
transmission costs incurred during the prior period (Met-Ed - $144 million
and Penelec - $4 million) and future transmission cost projections for June 2008
through May 2009 (Met-Ed - $258 million and Penelec - $92 million).
Met-Ed received approval from the PPUC of a transition approach that would
recover past under-recovered costs plus carrying charges through the new TSC
over thirty-one months and defer a portion of the projected costs
($92 million) plus carrying charges for recovery through future TSCs by
December 31, 2010.





On February 1, 2007,
the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of
proposed legislation that, according to the Governor, is designed to reduce
energy costs, promote energy independence and stimulate the economy. Elements of
the EIS include the installation of smart meters, funding for solar panels on
residences and small businesses, conservation and demand reduction programs to
meet energy growth, a requirement that electric distribution companies acquire
power that results in the “lowest reasonable rate on a long-term basis,” the
utilization of micro-grids and a three year phase-in of rate increases. On
July 17, 2007 the Governor signed into law two pieces of energy
legislation. The first amended the Alternative Energy Portfolio Standards Act of
2004 to, among other things, increase the percentage of solar energy that must
be supplied at the conclusion of an electric distribution company’s transition
period. The second law allows electric distribution companies, at their sole
discretion, to enter into long term contracts with large customers and to build
or acquire interests in electric generation facilities specifically to supply
long-term contracts with such customers. A special legislative session on energy
was convened in mid-September 2007 to consider other aspects of the EIS. The
Pennsylvania House and Senate on March 11, 2008 and December 12, 2007,
respectively, passed different versions of bills to fund the Governor’s EIS
proposal. As part of the 2008 state budget negotiations, the Alternative Energy
Investment Act was enacted creating a $650 million alternative energy fund to
increase the development and use of alternative and renewable energy, improve
energy efficiency and reduce energy consumption.  On October 8, 2008,
House Bill 2200 as amended, was voted out of the full Senate and adopted by the
House. On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200
into law which becomes effective on November 14, 2008 as Act 129 of
2008.  The bill addresses issues such as: energy efficiency and peak
load reduction; generation procurement; time-of-use rates; smart meters and
alternative energy.  Act 129 requires utilities to file with the PPUC
an energy efficiency and peak load reduction plan by July 1, 2009 and a
smart meter procurement and installation plan by August 14, 2009.





Major provisions of
the legislation include:




·
              power acquired
      by utilities to serve customers after rate caps expire will be procured
      through a competitive procurement process that must include a mix of
      long-term and short-term contracts and spot market
    purchases;
 
 ·
              the
      competitive procurement process must be approved by the PPUC and may
      include auctions, request for proposals, and/or bilateral
      agreements;
 
 ·
              utilities must
      provide for the installation of smart meter technology within 15
      years;
 
 ·
              a minimum
      reduction in peak demand of 4.5% by May 31,
  2013;












131








·
            minimum
      reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31,
      2013, respectively; and





·
            an expanded
      definition of alternative energy to include additional types of
      hydroelectric and biomass
facilities.





The current
legislative session ends on November 30, 2008, and any pending legislation
addressing rate mitigation and the expiration of rate caps not enacted by that
time must be re-introduced in order to be considered in the next legislative
session which begins in January 2009.  While the form and impact of
such legislation is uncertain, several legislators and the Governor have
indicated their intent to address these issues next year.





On September 25,
2008, Met-Ed and Penelec filed for Commission approval of a Voluntary Prepayment
Plan that would provide an opportunity for residential and small commercial
customers to pre-pay an amount, which would earn interest at 7.5%, on their
monthly electric bills in 2009 and 2010, to be used to reduce electric rates in
2011 and 2012. Met-Ed and Penelec also intend to file a generation procurement
plan for 2011 and beyond with the PPUC later this year or early next year.
Met-Ed and Penelec requested that the PPUC approve the Plan by mid-December 2008
and are currently awaiting a decision.





(D)    NEW
JERSEY





JCP&L is
permitted to defer for future collection from customers the amounts by which its
costs of supplying BGS to non-shopping customers and costs incurred under NUG
agreements exceed amounts collected through BGS and NUGC rates and market sales
of NUG energy and capacity. As of September 30, 2008, the accumulated
deferred cost balance totaled approximately $210 million.





In accordance with
an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7,
2004 supporting continuation of the current level and duration of the funding of
TMI-2 decommissioning costs by New Jersey customers without a reduction,
termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study. This study resulted in an updated
total decommissioning cost estimate of $729 million (in 2003 dollars)
compared to the estimated $528 million (in 2003 dollars) from the prior
1995 decommissioning study. The DRA filed comments on February 28, 2005
requesting that decommissioning funding be suspended. On March 18, 2005,
JCP&L filed a response to those comments. JCP&L responded to additional
NJBPU staff discovery requests in May and November 2007 and also submitted
comments in the proceeding in November 2007. A schedule for further NJBPU
proceedings has not yet been set.





On August 1, 2005,
the NJBPU established a proceeding to determine whether additional ratepayer
protections are required at the state level in light of the repeal of the PUHCA
pursuant to the EPACT. The NJBPU approved regulations effective October 2,
2006 that prevent a holding company that owns a gas or electric public utility
from investing more than 25% of the combined assets of its utility and
utility-related subsidiaries into businesses unrelated to the utility industry.
These regulations are not expected to materially impact FirstEnergy or
JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional
draft proposal on March 31, 2006 addressing various issues including access
to books and records, ring-fencing, cross subsidization, corporate governance
and related matters. With the approval of the NJBPU Staff, the affected
utilities jointly submitted an alternative proposal on June 1, 2006. The
NJBPU Staff circulated revised drafts of the proposal to interested stakeholders
in November 2006 and again in February 2007. On February 1, 2008, the NJBPU
accepted proposed rules for publication in the New Jersey Register on
March 17, 2008. A public hearing on these proposed rules was held on
April 23, 2008 and comments from interested parties were submitted by May
19, 2008.





New Jersey statutes
require that the state periodically undertake a planning process, known as the
EMP, to address energy related issues including energy security, economic
growth, and environmental impact. The EMP is to be developed with involvement of
the Governor’s Office and the Governor’s Office of Economic Growth, and is to be
prepared by a Master Plan Committee, which is chaired by the NJBPU President and
includes representatives of several State departments. In October 2006, the
current EMP process was initiated through the creation of a number of working
groups to obtain input from a broad range of interested stakeholders including
utilities, environmental groups, customer groups, and major customers. In
addition, public stakeholder meetings were held in 2006, 2007 and the first half
of 2008.





On April 17, 2008, a
draft EMP was released for public comment. The final EMP was issued on October
22, 2008 and establishes five major goals:





·
            maximize
      energy efficiency to achieve a 20% reduction in energy consumption by
      2020;





·
            reduce peak
      demand for electricity by 5,700 MW by
2020;





·
            meet 30% of
      the state’s electricity needs with renewable energy by
    2020;





132








·
            examine smart
      grid technology and develop additional cogeneration and other generation
      resources consistent with the state’s greenhouse gas targets;
      and





·
            invest in
      innovative clean energy technologies and businesses to stimulate the
      industry’s growth in New Jersey.





The final EMP will
be followed by appropriate legislation and regulation as necessary. At this
time, FirstEnergy cannot predict the outcome of this process nor determine the
impact, if any, such legislation or regulation may have on its operations or
those of JCP&L.





(E)   
FERC MATTERS





Transmission Service between MISO and
PJM





On November 18,
2004, the FERC issued an order eliminating the through and out rate for
transmission service between the MISO and PJM regions. The FERC’s intent was to
eliminate multiple transmission charges for a single transaction between the
MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission
owners within MISO and PJM to submit compliance filings containing a rate
mechanism to recover lost transmission revenues created by elimination of this
charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a
16-month transition period. The FERC issued orders in 2005 setting the SECA for
hearing. The presiding judge issued an initial decision on August 10, 2006,
rejecting the compliance filings made by MISO, PJM, and the transmission owners,
and directing new compliance filings. This decision is subject to review and
approval by the FERC. Briefs addressing the initial decision were filed on
September 11, 2006 and October 20, 2006. A final order could be issued by
the FERC by year-end 2008.  In the meantime, FirstEnergy affiliates
have been negotiating and entering into settlement agreements with other parties
in the docket to mitigate the risk of lower transmission revenue collection
associated with an adverse order.  On September 26, 2008, the MISO and
PJM transmission owners filed a motion requesting that the FERC approve the
pending settlements and act on the initial decision.





PJM Transmission Rate
Design





On January 31, 2005,
certain PJM transmission owners made filings with the FERC pursuant to a
settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
Penelec were parties to that proceeding and joined in two of the filings. In the
first filing, the settling transmission owners submitted a filing justifying
continuation of their existing rate design within the PJM RTO. Hearings were
held and numerous parties appeared and litigated various issues concerning PJM
rate design; notably AEP, which proposed to create a "postage stamp", or average
rate for all high voltage transmission facilities across PJM and a zonal
transmission rate for facilities below 345 kV. This proposal would have the
effect of shifting recovery of the costs of high voltage transmission lines to
other transmission zones, including those where JCP&L, Met-Ed, and Penelec
serve load. On April 19, 2007, the FERC issued an order finding that the PJM
transmission owners’ existing “license plate” or zonal rate design was just and
reasonable and ordered that the current license plate rates for existing
transmission facilities be retained. On the issue of rates for new transmission
facilities, the FERC directed that costs for new transmission facilities that
are rated at 500 kV or higher are to be collected from all transmission zones
throughout the PJM footprint by means of a postage-stamp rate. Costs for new
transmission facilities that are rated at less than 500 kV, however, are to be
allocated on a “beneficiary pays” basis. The FERC found that PJM’s current
beneficiary-pays cost allocation methodology is not sufficiently detailed and,
in a related order that also was issued on April 19, 2007, directed that
hearings be held for the purpose of establishing a just and reasonable cost
allocation methodology for inclusion in PJM’s tariff.





On May 18, 2007,
certain parties filed for rehearing of the FERC’s April 19, 2007 order. On
January 31, 2008, the requests for rehearing were denied. The FERC’s orders on
PJM rate design will prevent the allocation of a portion of the revenue
requirement of existing transmission facilities of other utilities to JCP&L,
Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new
500 kV and above transmission facilities on a PJM-wide basis will reduce the
costs of future transmission to be recovered from the JCP&L, Met-Ed and
Penelec zones. A partial settlement agreement addressing the “beneficiary pays”
methodology for below 500 kV facilities, but excluding the issue of allocating
new facilities costs to merchant transmission entities, was filed on September
14, 2007. The agreement was supported by the FERC’s Trial Staff, and was
certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued
an order conditionally approving the settlement subject to the submission of a
compliance filing.  The compliance filing was submitted on
August 29, 2008, and the FERC issued an order accepting the compliance
filing on October 15, 2008.  The remaining merchant transmission cost
allocation issues were the subject of a hearing at the FERC in May
2008.  An initial decision was issued by the Presiding Judge on
September 18, 2008.  PJM and FERC trial staff each filed a Brief on
Exceptions to the initial decision on October 20, 2008.  Briefs
Opposing Exceptions are due on November 10, 2008. On February 11, 2008, AEP
appealed the FERC’s April 19, 2007 and January 31, 2008 orders to the federal
Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the
PUCO and Dayton Power & Light have also appealed these orders to the Seventh
Circuit Court of Appeals. The appeals of these parties and others have been
consolidated for argument in the Seventh Circuit.





133





Post
Transition Period Rate Design





The FERC had
directed MISO, PJM, and the respective transmission owners to make filings on or
before August 1, 2007 to reevaluate transmission rate design within MISO, and
between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the
vast majority of transmission owners, including FirstEnergy affiliates, which
proposed to retain the existing transmission rate design. These filings were
approved by the FERC on January 31, 2008. As a result of the FERC’s approval,
the rates charged to FirstEnergy’s load-serving affiliates for transmission
service over existing transmission facilities in MISO and PJM are unchanged. In
a related filing, MISO and MISO transmission owners requested that the current
MISO pricing for new transmission facilities that spreads 20% of the cost of new
345 kV and higher transmission facilities across the entire MISO footprint
(known as the RECB methodology) be retained.





On September 17, 2007, AEP filed a
complaint under Sections 206 and 306 of the Federal Power Act seeking to have
the entire transmission rate design and cost allocation methods used by MISO and
PJM declared unjust, unreasonable, and unduly discriminatory, and to have the
FERC fix a uniform regional transmission rate design and cost allocation method
for the entire MISO and PJM “Super Region” that recovers the average cost of new
and existing transmission facilities operated at voltages of 345 kV and above
from all transmission customers. Lower voltage facilities would continue to be
recovered in the local utility transmission rate zone through a license plate
rate. AEP requested a refund effective October 1, 2007, or alternatively,
February 1, 2008. On January 31, 2008, the FERC issued an order denying the
complaint. The effect of this order is to prevent the shift of significant costs
to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP is pending
before the FERC.





MISO Ancillary Services Market and
Balancing Area Consolidation





MISO made a filing
on September 14, 2007 to establish an ASM for regulation, spinning and
supplemental reserves, to consolidate the existing 24 balancing areas within the
MISO footprint, and to establish MISO as the NERC registered balancing authority
for the region. These markets would permit generators to sell, and load-serving
entities to purchase, their operating reserve requirements in a competitive
market. FirstEnergy supports the proposal to establish markets for Ancillary
Services and consolidate existing balancing areas. On February 25, 2008, the
FERC issued an order approving the ASM subject to certain compliance filings.
Numerous parties filed requests for rehearing on March 26, 2008. On
June 23, 2008, the FERC issued an order granting in part and denying in
part rehearing.





On February 29,
2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor
ASM and Consolidated Balancing Authority Initiative Verification plan and status
and Real-Time Operations ASM Reversion plan. FERC action on this compliance
filing remains pending. On March 26, 2008, MISO submitted a tariff filing in
compliance with the FERC’s 30-day directives in the February 25 order. Numerous
parties submitted comments and protests on April 16, 2008. The FERC issued an
order accepting the revisions pending further compliance on June 23, 2008. On
April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s
60-day directives in the February 25 order. FERC action on this compliance
filing remains pending. On May 23, 2008, MISO submitted its amended Balancing
Authority Agreement. On July 21, 2008, the FERC issued an order
conditionally accepting the amended Balancing Authority Agreement and requiring
a further compliance filing. On August 19, 2008, MISO submitted its compliance
filing to the FERC. On July 25, 2008, MISO submitted another Readiness
Certification.  The FERC has not yet acted on this
submission.  MISO announced on August 26, 2008 that the startup
of its market is postponed indefinitely.  MISO commits to make a
filing giving at least sixty days notice of the new effective date. The latest
announced effective date for market startup is January 6, 2009.





Interconnection
Agreement with AMP-Ohio





On May 29, 2008, TE
filed with the FERC a proposed Notice of Cancellation effective midnight
December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio
protested this filing. TE also filed a Petition for Declaratory Order seeking a
FERC ruling, in the alternative if cancellation is not accepted, of TE's right
to file for an increase in rates effective January 1, 2009, for power
provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a
pleading agreeing that TE may seek an increase in rates, but arguing that any
increase is limited to the cost of generation owned by TE
affiliates.  On August 18, 2008, the FERC issued an order that
suspended the cancellation of the Agreement for five months, to become effective
on June 1, 2009, and established expedited hearing procedures on issues raised
in the filing and TE’s Petition for Declaratory Order.   On
October 14, 2008, the parties filed a settlement agreement and mutual notice of
cancellation of the Interconnection Agreement effective midnight December 31,
2008.  Upon acceptance by the FERC, this filing will terminate the
litigation and the Interconnection Agreement, among other effects.





Duquesne’s
Request to Withdraw from PJM





On November 8, 2007,
Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and
to join MISO. In its filing, Duquesne asked the FERC to be relieved of certain
capacity payment obligations to PJM for capacity auctions conducted prior to its
departure from PJM, but covering service for planning periods through
May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is
to avoid paying future obligations created by PJM’s forward capacity market. On
January 17, 2008, the FERC conditionally approved Duquesne’s request to
exit PJM. Among other conditions, the FERC obligated Duquesne zone load-serving
entities to pay their PJM capacity obligations through May 31,
2011.





134





FirstEnergy desires
to continue to use its Duquesne zone generation resources to serve load in PJM.
On April 18, 2008, the FERC issued its Order on Motion for Emergency
Clarification on whether Duquesne-zone generators could participate in PJM’s May
2008 auction for the 2011-2012 planning year. In the order, the FERC ruled
that although the status of the Duquesne-zone generators will change to
“External Resource” upon Duquesne’s exit from PJM, these generators could
contract with PJM for the transmission reservations necessary to participate in
the May 2008 auction. FirstEnergy has complied with the FERC’s order by
obtaining executed transmission service agreements for firm point-to-point
transmission service for the 2011-2012 delivery year and, as such, FirstEnergy
satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM
auction.





The FERC also
directed MISO and PJM to resolve the substantive and procedural issues
associated with Duquesne’s transition into MISO. As directed, PJM filed thirteen
load-serving entity Capacity Payment Agreements and a Capacity Portability
Agreement with the FERC. The Capacity Payment Agreements addressed Duquesne Zone
load-serving entity obligations through May 31, 2011 with regards to RPM
Capacity while the Capacity Portability Agreement addressed operational issues
associated with the portability of such capacity. On September 30, 2008, the
FERC approved both agreements, subject to conditions, taking notice of many
operational and procedural issues brought forth by FirstEnergy and other market
participants.





Several issues
surrounding Duquesne’s transition into MISO continue to be contested at the
FERC. Specifically, Duquesne’s obligation to pay for transmission expansion
costs allocated to the Duquesne zone when they were a member of PJM, and other
issues in which market participants wish to be held harmless by Duquesne’s
transition. FirstEnergy filed for rehearing on these issues on October 3, 2008.
Duquesne’s transition into MISO is also contingent upon the start of MISO’s
ancillary services market and consolidation of its balancing authorities,
currently scheduled for January 6, 2009.





Complaint
against PJM RPM Auction





On May 30,
2008, a group of PJM load-serving entities, state commissions, consumer
advocates, and trade associations (referred to collectively as the RPM Buyers)
filed a complaint at the FERC against PJM alleging that three of the
four transitional RPM auctions yielded prices that are unjust and
unreasonable under the Federal Power Act. Most of the parties comprising
the RPM Buyers group were parties to the settlement approved by the FERC that
established the RPM. In the complaint, the RPM Buyers request that the
total projected payments to RPM sellers for the three auctions at issue be
materially reduced. On July 11, 2008, PJM filed its answer to the
complaint, in which it denied the allegation that the rates are unjust and
unreasonable. Also on that date, FirstEnergy filed a motion to
intervene.





On September 19,
2008, the FERC denied the RPM Buyers complaint. However, the FERC did grant the
RPM Buyers request for a technical conference to review aspects of the RPM. The
FERC also ordered PJM to file on or before December 15, 2008, a report on
its progress on contemplating adjustments to the RPM as suggested by the Brattle
Group in its report reviewing the RPM. The technical conference will take place
in February, 2009. On October 20, 2008, the RPM Buyers filed a request for
rehearing of the FERC’s September 19, 2008 order.





MISO
Resource Adequacy Proposal





MISO made a filing
on December 28, 2007 that would create an enforceable planning reserve
requirement in the MISO tariff for load-serving entities such as the Ohio
Companies, Penn Power, and FES. This requirement is proposed to become effective
for the planning year beginning June 1, 2009. The filing would permit MISO to
establish the reserve margin requirement for load-serving entities based upon a
one day loss of load in ten years standard, unless the state utility regulatory
agency establishes a different planning reserve for load-serving entities in its
state. FirstEnergy believes the proposal promotes a mechanism that will result
in commitments from both load-serving entities and resources, including both
generation and demand side resources that are necessary for reliable resource
adequacy and planning in the MISO footprint. Comments on the filing were filed
on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy
proposal on March 26, 2008, requiring MISO to submit to further compliance
filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27,
2008, MISO submitted a compliance filing to address issues associated with
planning reserve margins. On June 17, 2008, various parties submitted comments
and protests to MISO’s compliance filing. FirstEnergy submitted comments
identifying specific issues that must be clarified and addressed. On
June 25, 2008, MISO submitted a second compliance filing establishing the
enforcement mechanism for the reserve margin requirement which establishes
deficiency payments for load-serving entities that do not meet the resource
adequacy requirements. Numerous parties, including FirstEnergy, protested this
filing.   On October 20, 2008, the FERC issued three orders
essentially permitting the MISO Resource Adequacy program to proceed with some
modifications.  First, the FERC accepted MISO's financial settlement
approach for enforcement of Resource Adequacy subject to a compliance filing
modifying the cost of new entry penalty. Second, the FERC conditionally accepted
MISO's compliance filing on the qualifications for purchase power agreements to
be capacity resources, load forecasting, loss of load expectation, and planning
reserve zones. Additional compliance filings were directed on accreditation of
load modifying resources and price responsive demand. Finally, the FERC largely
denied rehearing of its March 26 order with the exception of issues related to
behind the meter resources and certain ministerial matters. Issuance of these
orders is not expected to delay the June 1, 2009 start date for MISO Resource
Adequacy.





135








Organized
Wholesale Power Markets





The FERC issued a
final rule on October 17, 2008, amending its regulations to “improve the
operation of organized wholesale electric markets in the areas of: (1) demand
response and market pricing during periods of operating reserve shortage; (2)
long-term power contracting; (3) market-monitoring policies; and (4) the
responsiveness of RTOs and ISOs to their customers and other stakeholders.” The
RTOs and ISOs were directed to submit amendments to their respective tariffs to
address these market operation improvements.  The final rule directs
RTOs to adopt market rules permitting prices to increase during periods of
supply shortages and to permit enhanced participation by demand response
resources.  It also codifies and defines for the first time the roles
and duties of independent market monitors within RTOs.  Finally, it
adopts requirements for enhanced access by stakeholders to RTO boards of
directors.  RTOs are directed to make compliance filings six months
from the effective date of the final rule.  The final rule is not
expected to have any material effect on FirstEnergy's operations within MISO and
PJM.





FES
Sales to Affiliates





On October 24, 2008,
FES, on its own behalf and on behalf of its generation-controlling subsidiaries,
filed an application with the FERC seeking a waiver of the affiliate sales
restrictions between FES and the Ohio Companies. The purpose of the waiver is to
ensure thatFESwill be able to continue supplying
a material portion of the electric load requirements of the Ohio Companies in
January 2009 pursuant to either an ESP or MRO as filed with the
PUCO. FES previously obtained a similar waiver for electricity sales
to its affiliates in New Jersey, New York, and Pennsylvania.  A ruling
by the FERC is expected the week of December 15, 2008.





On October 31, 2008,
FES executed a Third Restated Partial Requirements Agreement with
Met-Ed, Penelec, and The Waverly Power and Light Company (Waverly)
effective November 1, 2008.  The Third Restated Partial Requirements
Agreement limits the amount of capacity and energy required to be supplied by
FES in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply
requirements. Met-Ed, Penelec, and Waverly have committed resources in
place for the balance of their expected power supply during 2009 and
2010.  Under the Third Restated Partial Requirements Agreement,
Met-Ed, Penelec, and Waverly are responsible for obtaining additional power
supply requirements created by the default or failure of supply of their
committed resources. Prices for the power provided by FES were not changed in
the Third Restated Partial Requirements Agreement.




13. 
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS





SFAS 141(R) – “Business
Combinations”





In December 2007,
the FASB issued SFAS 141(R), which: (i) requires the acquiring entity in a
business combination to recognize all assets acquired and liabilities assumed in
the transaction; (ii) establishes the acquisition-date fair value as the
measurement objective for all assets acquired and liabilities assumed; and (iii)
requires the acquirer to disclose to investors and other users all of the
information they need to evaluate and understand the nature and financial effect
of the business combination. The Standard includes both core principles and
pertinent application guidance, eliminating the need for numerous EITF issues
and other interpretative guidance. SFAS 141(R) will affect business combinations
entered into by FirstEnergy that close after January 1, 2009. In addition,
the Standard also affects the accounting for changes in deferred tax valuation
allowances and income tax uncertainties made after January 1, 2009, that
were established as part of a business combination prior to the implementation
of this Standard. Under SFAS 141(R), adjustments to the acquired entity’s
deferred tax assets and uncertain tax position balances occurring outside the
measurement period will be recorded as a component of income tax expense, rather
than goodwill.The
impact of FirstEnergy’s application of this Standard in periods after
implementation will be dependent upon acquisitions at that time.





SFAS
160 - “Non-controlling Interests in Consolidated Financial Statements – an
Amendment of ARB No. 51”





In December 2007,
the FASB issued SFAS 160 that establishes accounting and reporting standards for
the noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an
ownership interest in the consolidated entity that should be reported as equity
in the consolidated financial statements. This Statement is effective for fiscal
years, and interim periods within those fiscal years, beginning on or after
December 15, 2008. Early adoption is prohibited. The Statement is not
expected to have a material impact on FirstEnergy’s financial
statements.





136








SFAS
      161 - “Disclosures about Derivative Instruments and Hedging Activities –
      an Amendment of FASB Statement No.
133”





In March 2008, the
FASB issued SFAS 161 that enhances the current disclosure framework for
derivative instruments and hedging activities. The Statement requires that
objectives for using derivative instruments be disclosed in terms of underlying
risk and accounting designation. The FASB believes that additional required
disclosure of the fair values of derivative instruments and their gains and
losses in a tabular format will provide a more complete picture of the location
in an entity’s financial statements of both the derivative positions existing at
period end and the effect of using derivatives during the reporting period.
Disclosing information about credit-risk-related contingent features is designed
to provide information on the potential effect on an entity’s liquidity from
using derivatives. This Statement also requires cross-referencing within the
footnotes to help users of financial statements locate important information
about derivative instruments. The Statement is effective for reporting periods
beginning after November 15, 2008. FirstEnergy expects this Standard to
increase its disclosure requirements for derivative instruments and hedging
activities.





14.  SEGMENT
INFORMATION





FirstEnergy has
three reportable operating segments: energy delivery services, competitive
energy services and Ohio transitional generation services. The assets and
revenues for all other business operations are below the quantifiable threshold
for operating segments for separate disclosure as “reportable operating
segments.”





The energy delivery
services segment designs, constructs, operates and maintains FirstEnergy's
regulated transmission and distribution systems and is responsible for the
regulated generation commodity operations of FirstEnergy’s Pennsylvania and New
Jersey electric utility subsidiaries. Its revenues are primarily derived from
the delivery of electricity, cost recovery of regulatory assets, and default
service electric generation sales to non-shopping customers in its Pennsylvania
and New Jersey franchise areas. Its results reflect the commodity costs of
securing electric generation from FES under partial requirements purchased power
agreements and from non-affiliated power suppliers as well as the net PJM
transmission expenses related to the delivery of that generation
load.





The competitive
energy services segment supplies electric power to its electric utility
affiliates, provides competitive electricity sales primarily in Ohio,
Pennsylvania, Maryland and Michigan, owns or leases and operates FirstEnergy’s
generating facilities and purchases electricity to meet its sales obligations.
The segment's net income is primarily derived from the affiliated company PSA
sales and the non-affiliated electric generation sales revenues less the related
costs of electricity generation, including purchased power and net transmission
(including congestion) and ancillary costs charged by PJM and MISO to deliver
electricity to the segment’s customers. The segment’s internal revenues
represent the affiliated company PSA sales.





The Ohio
transitional generation services segment represents the regulated generation
commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its
revenues are primarily derived from electric generation sales to non-shopping
customers under the PLR obligations of the Ohio Companies. Its results reflect
the purchase of electricity from the competitive energy services segment through
full-requirements PSA arrangements, the deferral and amortization of certain
fuel costs authorized for recovery by the energy delivery services segment and
the net MISO transmission revenues and expenses related to the delivery of
generation load. This segment’s total assets consist of accounts receivable for
generation revenues from retail customers.





137






Segment
      Financial InformationOhioEnergy
              
              
              Competitive
              
              
              TransitionalDelivery
              
              
              Energy
              
              
              Generation
              
              
              
              
              
              ReconcilingThree
      Months Ended
              
              Services
              
              
              Services
              
              
              Services
              
              
              Other
              
              
              Adjustments
              
              
              Consolidated(In
      millions)September 30,
      2008External
      revenues
              
              $
              2,657
              
              
              $
              460
              
              
              $
              813
              
              
              $
              5
              
              
              $
              (31
              )
              
              $
              3,904Internal
      revenues
              
              
              -
              
              
              
              786
              
              
              
              -
              
              
              
              -
              
              
              
              (786
              )
              
              
              -Total
      revenues
              
              
              2,657
              
              
              
              1,246
              
              
              
              813
              
              
              
              5
              
              
              
              (817
              )
              
              
              3,904Depreciation
      and amortization
              
              
              286
              
              
              
              67
              
              
              
              46
              
              
              
              1
              
              
              
              1
              
              
              
              401Investment
      income
              
              
              48
              
              
              
              13
              
              
              
              1
              
              
              
              -
              
              
              
              (22
              )
              
              
              40Net interest
      charges
              
              
              101
              
              
              
              31
              
              
              
              1
              
              
              
              -
              
              
              
              44
              
              
              
              177Income
      taxes
              
              
              188
              
              
              
              109
              
              
              
              14
              
              
              
              (46
              )
              
              
              (27
              )
              
              
              238Net
      income
              
              
              283
              
              
              
              164
              
              
              
              19
              
              
              
              48
              
              
              
              (43
              )
              
              
              471Total
      assets
              
              
              23,088
              
              
              
              9,360
              
              
              
              270
              
              
              
              457
              
              
              
              387
              
              
              
              33,562Total
      goodwill
              
              
              5,559
              
              
              
              24
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              5,583Property
      additions
              
              
              170
              
              
              
              285
              
              
              
              -
              
              
              
              85
              
              
              
              20
              
              
              
              560September 30,
      2007External
      revenues
              
              $
              2,520
              
              
              $
              370
              
              
              $
              723
              
              
              $
              9
              
              
              $
              19
              
              
              $
              3,641Internal
      revenues
              
              
              -
              
              
              
              806
              
              
              
              -
              
              
              
              -
              
              
              
              (806
              )
              
              
              -Total
      revenues
              
              
              2,520
              
              
              
              1,176
              
              
              
              723
              
              
              
              9
              
              
              
              (787
              )
              
              
              3,641Depreciation
      and amortization
              
              
              299
              
              
              
              51
              
              
              
              (16
              )
              
              
              1
              
              
              
              8
              
              
              
              343Investment
      income
              
              
              58
              
              
              
              5
              
              
              
              -
              
              
              
              1
              
              
              
              (34
              )
              
              
              30Net interest
      charges
              
              
              117
              
              
              
              39
              
              
              
              -
              
              
              
              1
              
              
              
              37
              
              
              
              194Income
      taxes
              
              
              175
              
              
              
              99
              
              
              
              11
              
              
              
              (2
              )
              
              
              (10
              )
              
              
              273Net
      income
              
              
              269
              
              
              
              148
              
              
              
              16
              
              
              
              6
              
              
              
              (26
              )
              
              
              413Total
      assets
              
              
              23,308
              
              
              
              7,182
              
              
              
              268
              
              
              
              232
              
              
              
              663
              
              
              
              31,653Total
      goodwill
              
              
              5,585
              
              
              
              24
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              5,609Property
      additions
              
              
              209
              
              
              
              199
              
              
              
              -
              
              
              
              3
              
              
              
              19
              
              
              
              430Nine
      Months EndedSeptember 30,
      2008External
      revenues
              
              $
              7,051
              
              
              $
              1,164
              
              
              $
              2,203
              
              
              $
              65
              
              
              $
              (57
              )
              
              $
              10,426Internal
      revenues
              
              
              -
              
              
              
              2,266
              
              
              
              -
              
              
              
              -
              
              
              
              (2,266
              )
              
              
              -Total
      revenues
              
              
              7,051
              
              
              
              3,430
              
              
              
              2,203
              
              
              
              65
              
              
              
              (2,323
              )
              
              
              10,426Depreciation
      and amortization
              
              
              782
              
              
              
              179
              
              
              
              61
              
              
              
              2
              
              
              
              10
              
              
              
              1,034Investment
      income
              
              
              133
              
              
              
              (1
              )
              
              
              1
              
              
              
              6
              
              
              
              (66
              )
              
              
              73Net interest
      charges
              
              
              303
              
              
              
              86
              
              
              
              1
              
              
              
              -
              
              
              
              133
              
              
              
              523Income
      taxes
              
              
              436
              
              
              
              212
              
              
              
              42
              
              
              
              (33
              )
              
              
              (72
              )
              
              
              585Net
      income
              
              
              655
              
              
              
              317
              
              
              
              62
              
              
              
              96
              
              
              
              (120
              )
              
              
              1,010Total
      assets
              
              
              23,088
              
              
              
              9,360
              
              
              
              270
              
              
              
              457
              
              
              
              387
              
              
              
              33,562Total
      goodwill
              
              
              5,559
              
              
              
              24
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              5,583Property
      additions
              
              
              621
              
              
              
              1,430
              
              
              
              -
              
              
              
              106
              
              
              
              20
              
              
              
              2,177September 30,
      2007External
      revenues
              
              $
              6,655
              
              
              $
              1,089
              
              
              $
              1,968
              
              
              $
              29
              
              
              $
              (18
              )
              
              $
              9,723Internal
      revenues
              
              
              -
              
              
              
              2,210
              
              
              
              -
              
              
              
              -
              
              
              
              (2,210
              )
              
              
              -Total
      revenues
              
              
              6,655
              
              
              
              3,299
              
              
              
              1,968
              
              
              
              29
              
              
              
              (2,228
              )
              
              
              9,723Depreciation
      and amortization
              
              
              767
              
              
              
              153
              
              
              
              (80
              )
              
              
              3
              
              
              
              20
              
              
              
              863Investment
      income
              
              
              190
              
              
              
              13
              
              
              
              1
              
              
              
              1
              
              
              
              (112
              )
              
              
              93Net interest
      charges
              
              
              340
              
              
              
              131
              
              
              
              1
              
              
              
              3
              
              
              
              97
              
              
              
              572Income
      taxes
              
              
              464
              
              
              
              259
              
              
              
              46
              
              
              
              -
              
              
              
              (74
              )
              
              
              695Net
      income
              
              
              695
              
              
              
              388
              
              
              
              69
              
              
              
              13
              
              
              
              (124
              )
              
              
              1,041Total
      assets
              
              
              23,308
              
              
              
              7,182
              
              
              
              268
              
              
              
              232
              
              
              
              663
              
              
              
              31,653Total
      goodwill
              
              
              5,585
              
              
              
              24
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              5,609Property
      additions
              
              
              609
              
              
              
              462
              
              
              
              -
              
              
              
              6
              
              
              
              50
              
              
              
              1,127


Reconciling
adjustments to segment operating results from internal management reporting to
consolidated external financial reporting primarily consist of interest expense
related to holding company debt, corporate support services revenues and
expenses and elimination of intersegment transactions.





138








15.  SUPPLEMENTAL
GUARANTOR INFORMATION





On July 13, 2007,
FGCO completed a sale and leaseback transaction for its 93.825% undivided
interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably
guaranteed all of FGCO’s obligations under each of the leases. The related
lessor notes and pass through certificates are not guaranteed by FES or FGCO,
but the notes are secured by, among other things, each lessor trust’s undivided
interest in Unit 1, rights and interests under the applicable lease and rights
and interests under other related agreements, including FES’ lease guaranty.
This transaction is classified as an operating lease under GAAP for FES and
FirstEnergy and a financing for FGCO.





The consolidating
statements of income for the three-month and nine-month periods ended
September 30, 2008 and 2007, consolidating balance sheets as of
September 30, 2008 and December 31, 2007 and condensed consolidating
statements of cash flows for the nine months ended September 30, 2008 and
2007 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented
below. Investments in wholly owned subsidiaries are accounted for by FES using
the equity method. Results of operations for FGCO and NGC are, therefore,
reflected in FES’ investment accounts and earnings as if operating lease
treatment was achieved. The principal elimination entries eliminate investments
in subsidiaries and intercompany balances and transactions and reflect operating
lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and
leaseback transaction.





139





FIRSTENERGY
      SOLUTIONS CORP.CONSOLIDATING
      STATEMENTS OF INCOME(Unaudited)For
      the Three Months Ended September 30, 2008
              
              FES
              
              
              FGCO
              
              
              NGC
              
              
              Eliminations
              
              
              Consolidated(In
      thousands)REVENUES
              
              $
              1,222,783
              
              
              $
              574,394
              
              
              $
              267,017
              
              
              $
              (822,590
              )
              
              $
              1,241,604EXPENSES:Fuel
              
              
              8,177
              
              
              
              307,646
              
              
              
              34,123
              
              
              
              -
              
              
              
              349,946Purchased
      power from non-affiliates
              
              
              221,493
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              221,493Purchased
      power from affiliates
              
              
              815,243
              
              
              
              7,347
              
              
              
              15,821
              
              
              
              (822,590
              )
              
              
              15,821Other
      operating expenses
              
              
              35,596
              
              
              
              110,701
              
              
              
              120,697
              
              
              
              12,190
              
              
              
              279,184Provision for
      depreciation
              
              
              1,978
              
              
              
              33,432
              
              
              
              30,559
              
              
              
              (1,336
              )
              
              
              64,633General
      taxes
              
              
              4,829
              
              
              
              10,768
              
              
              
              6,139
              
              
              
              -
              
              
              
              21,736Total
      expenses
              
              
              1,087,316
              
              
              
              469,894
              
              
              
              207,339
              
              
              
              (811,736
              )
              
              
              952,813-
              
              
              
              -
              
              
              
              -
              
              
              
              -OPERATING
      INCOME
              
              
              135,467
              
              
              
              104,500
              
              
              
              59,678
              
              
              
              (10,854
              )
              
              
              288,791OTHER
      INCOME (EXPENSE):Miscellaneous
      income (expense), includingnet income
      from equity investees
              
              
              102,777
              
              
              
              (515
              )
              
              
              13,287
              
              
              
              (97,122
              )
              
              
              18,427Interest
      expense - affiliates
              
              
              (120
              )
              
              
              (4,963
              )
              
              
              (2,932
              )
              
              
              -
              
              
              
              (8,015
              )Interest
      expense - other
              
              
              (8,464
              )
              
              
              (23,447
              )
              
              
              (17,183
              )
              
              
              16,325
              
              
              
              (32,769
              )Capitalized
      interest
              
              
              41
              
              
              
              11,376
              
              
              
              978
              
              
              
              -
              
              
              
              12,395Total other
      income (expense)
              
              
              94,234
              
              
              
              (17,549
              )
              
              
              (5,850
              )
              
              
              (80,797
              )
              
              
              (9,962
              )INCOME
      BEFORE INCOME TAXES
              
              
              229,701
              
              
              
              86,951
              
              
              
              53,828
              
              
              
              (91,651
              )
              
              
              278,829INCOME
      TAXES
              
              
              44,046
              
              
              
              31,863
              
              
              
              14,995
              
              
              
              2,270
              
              
              
              93,174NET
      INCOME
              
              $
              185,655
              
              
              $
              55,088
              
              
              $
              38,833
              
              
              $
              (93,921
              )
              
              $
              185,655
  140
   FIRSTENERGY
      SOLUTIONS CORP.CONSOLIDATING
      STATEMENTS OF INCOME(Unaudited)For
      the Three Months Ended September 30, 2007
              
              FES
              
              
              FGCO
              
              
              NGC
              
              
              Eliminations
              
              
              Consolidated(In
      thousands)REVENUES
              
              $
              1,180,449
              
              
              $
              496,204
              
              
              $
              280,072
              
              
              $
              (785,817
              )
              
              $
              1,170,908EXPENSES:Fuel
              
              
              10,944
              
              
              
              261,759
              
              
              
              29,083
              
              
              
              -
              
              
              
              301,786Purchased
      power from non-affiliates
              
              
              228,755
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              228,755Purchased
      power from affiliates
              
              
              774,873
              
              
              
              57,927
              
              
              
              15,525
              
              
              
              (785,817
              )
              
              
              62,508Other
      operating expenses
              
              
              41,828
              
              
              
              75,985
              
              
              
              117,220
              
              
              
              -
              
              
              
              235,033Provision for
      depreciation
              
              
              650
              
              
              
              24,669
              
              
              
              23,181
              
              
              
              -
              
              
              
              48,500General
      taxes
              
              
              5,406
              
              
              
              11,788
              
              
              
              5,048
              
              
              
              -
              
              
              
              22,242Total
      expenses
              
              
              1,062,456
              
              
              
              432,128
              
              
              
              190,057
              
              
              
              (785,817
              )
              
              
              898,824OPERATING
      INCOME
              
              
              117,993
              
              
              
              64,076
              
              
              
              90,015
              
              
              
              -
              
              
              
              272,084OTHER
      INCOME (EXPENSE):Miscellaneous
      income, includingnet income
      from equity investees
              
              
              82,870
              
              
              
              2,375
              
              
              
              3,935
              
              
              
              (76,525
              )
              
              
              12,655Interest
      expense - affiliates
              
              
              (676
              )
              
              
              (4,769
              )
              
              
              (4,196
              )
              
              
              -
              
              
              
              (9,641
              )Interest
      expense - other
              
              
              (808
              )
              
              
              (21,274
              )
              
              
              (9,712
              )
              
              
              -
              
              
              
              (31,794
              )Capitalized
      interest
              
              
              9
              
              
              
              3,889
              
              
              
              1,233
              
              
              
              -
              
              
              
              5,131Total other
      income (expense)
              
              
              81,395
              
              
              
              (19,779
              )
              
              
              (8,740
              )
              
              
              (76,525
              )
              
              
              (23,649
              )INCOME
      BEFORE INCOME TAXES
              
              
              199,388
              
              
              
              44,297
              
              
              
              81,275
              
              
              
              (76,525
              )
              
              
              248,435INCOME
      TAXES
              
              
              44,624
              
              
              
              19,850
              
              
              
              29,197
              
              
              
              -
              
              
              
              93,671NET
      INCOME
              
              $
              154,764
              
              
              $
              24,447
              
              
              $
              52,078
              
              
              $
              (76,525
              )
              
              $
              154,764
  141
   FIRSTENERGY
      SOLUTIONS CORP.CONSOLIDATING
      STATEMENTS OF INCOME(Unaudited)For
      the Nine Months Ended September 30, 2008
              
              FES
              
              
              FGCO
              
              
              NGC
              
              
              Eliminations
              
              
              Consolidated(In
      thousands)REVENUES
              
              $
              3,387,258
              
              
              $
              1,707,320
              
              
              $
              879,729
              
              
              $
              (2,562,309
              )
              
              $
              3,411,998EXPENSES:Fuel
              
              
              13,920
              
              
              
              876,077
              
              
              
              92,188
              
              
              
              -
              
              
              
              982,185Purchased
      power from non-affiliates
              
              
              648,556
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              648,556Purchased
      power from affiliates
              
              
              2,549,892
              
              
              
              12,417
              
              
              
              75,834
              
              
              
              (2,562,309
              )
              
              
              75,834Other
      operating expenses
              
              
              103,034
              
              
              
              342,041
              
              
              
              381,826
              
              
              
              36,567
              
              
              
              863,468Provision for
      depreciation
              
              
              3,885
              
              
              
              90,058
              
              
              
              80,646
              
              
              
              (4,054
              )
              
              
              170,535General
      taxes
              
              
              14,971
              
              
              
              33,842
              
              
              
              15,915
              
              
              
              -
              
              
              
              64,728Total
      expenses
              
              
              3,334,258
              
              
              
              1,354,435
              
              
              
              646,409
              
              
              
              (2,529,796
              )
              
              
              2,805,306OPERATING
      INCOME
              
              
              53,000
              
              
              
              352,885
              
              
              
              233,320
              
              
              
              (32,513
              )
              
              
              606,692OTHER
      INCOME (EXPENSE):Miscellaneous
      income (expense), includingnet income
      from equity investees
              
              
              323,092
              
              
              
              (1,234
              )
              
              
              (2,699
              )
              
              
              (305,710
              )
              
              
              13,449Interest
      expense - affiliates
              
              
              (252
              )
              
              
              (18,172
              )
              
              
              (7,529
              )
              
              
              -
              
              
              
              (25,953
              )Interest
      expense - other
              
              
              (19,105
              )
              
              
              (73,112
              )
              
              
              (38,833
              )
              
              
              49,241
              
              
              
              (81,809
              )Capitalized
      interest
              
              
              90
              
              
              
              27,460
              
              
              
              2,049
              
              
              
              -
              
              
              
              29,599Total other
      income (expense)
              
              
              303,825
              
              
              
              (65,058
              )
              
              
              (47,012
              )
              
              
              (256,469
              )
              
              
              (64,714
              )INCOME
      BEFORE INCOME TAXES
              
              
              356,825
              
              
              
              287,827
              
              
              
              186,308
              
              
              
              (288,982
              )
              
              
              541,978INCOME
      TAXES
              
              
              13,092
              
              
              
              109,615
              
              
              
              68,597
              
              
              
              6,941
              
              
              
              198,245NET
      INCOME
              
              $
              343,733
              
              
              $
              178,212
              
              
              $
              117,711
              
              
              $
              (295,923
              )
              
              $
              343,733
  142
    FIRSTENERGY
      SOLUTIONS CORP.CONSOLIDATING
      STATEMENTS OF INCOME(Unaudited)For
      the Nine Months Ended September 30, 2007
              
              FES
              
              
              FGCO
              
              
              NGC
              
              
              Eliminations
              
              
              Consolidated(In
      thousands)REVENUES
              
              $
              3,274,694
              
              
              $
              1,501,112
              
              
              $
              793,255
              
              
              $
              (2,311,129
              )
              
              $
              3,257,932EXPENSES:Fuel
              
              
              20,824
              
              
              
              698,643
              
              
              
              84,734
              
              
              
              -
              
              
              
              804,201Purchased
      power from non-affiliates
              
              
              577,831
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              577,831Purchased
      power from affiliates
              
              
              2,290,305
              
              
              
              176,654
              
              
              
              53,746
              
              
              
              (2,311,129
              )
              
              
              209,576Other
      operating expenses
              
              
              123,596
              
              
              
              240,774
              
              
              
              367,404
              
              
              
              -
              
              
              
              731,774Provision for
      depreciation
              
              
              1,572
              
              
              
              74,844
              
              
              
              68,614
              
              
              
              -
              
              
              
              145,030General
      taxes
              
              
              15,942
              
              
              
              31,406
              
              
              
              17,522
              
              
              
              -
              
              
              
              64,870Total
      expenses
              
              
              3,030,070
              
              
              
              1,222,321
              
              
              
              592,020
              
              
              
              (2,311,129
              )
              
              
              2,533,282OPERATING
      INCOME
              
              
              244,624
              
              
              
              278,791
              
              
              
              201,235
              
              
              
              -
              
              
              
              724,650OTHER
      INCOME (EXPENSE):Miscellaneous
      income, includingnet income
      from equity investees
              
              
              271,599
              
              
              
              2,669
              
              
              
              13,350
              
              
              
              (239,862
              )
              
              
              47,756Interest
      expense - affiliates
              
              
              (676
              )
              
              
              (47,090
              )
              
              
              (14,138
              )
              
              
              -
              
              
              
              (61,904
              )Interest
      expense - other
              
              
              (7,966
              )
              
              
              (34,150
              )
              
              
              (28,729
              )
              
              
              -
              
              
              
              (70,845
              )Capitalized
      interest
              
              
              20
              
              
              
              9,044
              
              
              
              3,699
              
              
              
              -
              
              
              
              12,763Total other
      income (expense)
              
              
              262,977
              
              
              
              (69,527
              )
              
              
              (25,818
              )
              
              
              (239,862
              )
              
              
              (72,230
              )INCOME
      BEFORE INCOME TAXES
              
              
              507,601
              
              
              
              209,264
              
              
              
              175,417
              
              
              
              (239,862
              )
              
              
              652,420INCOME
      TAXES
              
              
              98,917
              
              
              
              82,031
              
              
              
              62,788
              
              
              
              -
              
              
              
              243,736NET
      INCOME
              
              $
              408,684
              
              
              $
              127,233
              
              
              $
              112,629
              
              
              $
              (239,862
              )
              
              $
              408,684
  143
   FIRSTENERGY
      SOLUTIONS CORP.CONSOLIDATING
      BALANCE SHEETS(Unaudited)As
      of September 30, 2008
              
              FES
              
              
              FGCO
              
              
              NGC
              
              
              Eliminations
              
              
              Consolidated(In
      thousands)ASSETSCURRENT
      ASSETS:Cash and cash
      equivalents
              
              $
              2
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              2Receivables-Customers
              
              
              137,126
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              137,126Associated
      companies
              
              
              267,777
              
              
              
              195,005
              
              
              
              100,481
              
              
              
              (299,484
              )
              
              
              263,779Other
              
              
              910
              
              
              
              1,595
              
              
              
              20,419
              
              
              
              -
              
              
              
              22,924Notes
      receivable from associated companies
              
              
              118,526
              
              
              
              38,400
              
              
              
              -
              
              
              
              -
              
              
              
              156,926Materials and
      supplies, at average cost
              
              
              3,519
              
              
              
              288,623
              
              
              
              205,134
              
              
              
              -
              
              
              
              497,276Prepayments
      and other
              
              
              64,585
              
              
              
              84,138
              
              
              
              30,807
              
              
              
              -
              
              
              
              179,530592,445
              
              
              
              607,761
              
              
              
              356,841
              
              
              
              (299,484
              )
              
              
              1,257,563PROPERTY,
      PLANT AND EQUIPMENT:In
      service
              
              
              108,733
              
              
              
              5,413,310
              
              
              
              4,704,478
              
              
              
              (391,859
              )
              
              
              9,834,662Less -
      Accumulated provision for depreciation
              
              
              10,990
              
              
              
              2,712,638
              
              
              
              1,658,863
              
              
              
              (170,774
              )
              
              
              4,211,71797,743
              
              
              
              2,700,672
              
              
              
              3,045,615
              
              
              
              (221,085
              )
              
              
              5,622,945Construction
      work in progress
              
              
              2,827
              
              
              
              1,225,381
              
              
              
              157,444
              
              
              
              -
              
              
              
              1,385,652100,570
              
              
              
              3,926,053
              
              
              
              3,203,059
              
              
              
              (221,085
              )
              
              
              7,008,597OTHER
      PROPERTY AND INVESTMENTS:Nuclear plant
      decommissioning trusts
              
              
              -
              
              
              
              -
              
              
              
              1,145,384
              
              
              
              -
              
              
              
              1,145,384Long-term
      notes receivable from associated companies
              
              
              -
              
              
              
              -
              
              
              
              62,900
              
              
              
              -
              
              
              
              62,900Investment in
      associated companies
              
              
              3,581,979
              
              
              
              -
              
              
              
              -
              
              
              
              (3,581,979
              )
              
              
              -Other
              
              
              2,124
              
              
              
              38,247
              
              
              
              202
              
              
              
              -
              
              
              
              40,5733,584,103
              
              
              
              38,247
              
              
              
              1,208,486
              
              
              
              (3,581,979
              )
              
              
              1,248,857DEFERRED
      CHARGES AND OTHER ASSETS:Accumulated
      deferred income taxes
              
              
              9,655
              
              
              
              471,718
              
              
              
              -
              
              
              
              (251,032
              )
              
              
              230,341Lease
      assignment receivable from associated companies
              
              
              -
              
              
              
              71,356
              
              
              
              -
              
              
              
              -
              
              
              
              71,356Goodwill
              
              
              24,248
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              24,248Property
      taxes
              
              
              -
              
              
              
              25,007
              
              
              
              22,767
              
              
              
              -
              
              
              
              47,774Pension
      assets
              
              
              3,208
              
              
              
              11,556
              
              
              
              -
              
              
              
              -
              
              
              
              14,764Unamortized
      sale and leaseback costs
              
              
              -
              
              
              
              8,445
              
              
              
              -
              
              
              
              48,920
              
              
              
              57,365Other
              
              
              18,343
              
              
              
              59,511
              
              
              
              18,717
              
              
              
              (46,869
              )
              
              
              49,70255,454
              
              
              
              647,593
              
              
              
              41,484
              
              
              
              (248,981
              )
              
              
              495,550$
              4,332,572
              
              
              $
              5,219,654
              
              
              $
              4,809,870
              
              
              $
              (4,351,529
              )
              
              $
              10,010,567LIABILITIES
      AND CAPITALIZATIONCURRENT
      LIABILITIES:Currently
      payable long-term debt
              
              $
              4,679
              
              
              $
              873,562
              
              
              $
              1,077,289
              
              
              $
              (17,315
              )
              
              $
              1,938,215Short-term
      borrowings-Associated
      companies
              
              
              -
              
              
              
              147,108
              
              
              
              164,642
              
              
              
              -
              
              
              
              311,750Other
              
              
              1,000,000
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              1,000,000Accounts
      payable-Associated
      companies
              
              
              276,155
              
              
              
              202,678
              
              
              
              158,215
              
              
              
              (275,601
              )
              
              
              361,447Other
              
              
              36,724
              
              
              
              126,449
              
              
              
              -
              
              
              
              -
              
              
              
              163,173Accrued
      taxes
              
              
              4,109
              
              
              
              88,826
              
              
              
              17,661
              
              
              
              (29,877
              )
              
              
              80,719Other
              
              
              36,491
              
              
              
              116,637
              
              
              
              26,777
              
              
              
              38,009
              
              
              
              217,9141,358,158
              
              
              
              1,555,260
              
              
              
              1,444,584
              
              
              
              (284,784
              )
              
              
              4,073,218CAPITALIZATION:Common
      stockholder's equity
              
              
              2,916,934
              
              
              
              1,813,911
              
              
              
              1,755,054
              
              
              
              (3,568,965
              )
              
              
              2,916,934Long-term debt
      and other long-term obligations
              
              
              40,333
              
              
              
              1,364,207
              
              
              
              451,365
              
              
              
              (1,296,982
              )
              
              
              558,9232,957,267
              
              
              
              3,178,118
              
              
              
              2,206,419
              
              
              
              (4,865,947
              )
              
              
              3,475,857NONCURRENT
      LIABILITIES:Deferred gain
      on sale and leaseback transaction
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              1,035,013
              
              
              
              1,035,013Accumulated
      deferred income taxes
              
              
              -
              
              
              
              -
              
              
              
              235,811
              
              
              
              (235,811
              )
              
              
              -Accumulated
      deferred investment tax credits
              
              
              -
              
              
              
              40,209
              
              
              
              23,759
              
              
              
              -
              
              
              
              63,968Asset
      retirement obligations
              
              
              -
              
              
              
              24,148
              
              
              
              825,327
              
              
              
              -
              
              
              
              849,475Retirement
      benefits
              
              
              9,745
              
              
              
              57,822
              
              
              
              -
              
              
              
              -
              
              
              
              67,567Property
      taxes
              
              
              -
              
              
              
              25,328
              
              
              
              22,767
              
              
              
              -
              
              
              
              48,095Lease market
      valuation liability
              
              
              -
              
              
              
              319,129
              
              
              
              -
              
              
              
              -
              
              
              
              319,129Other
              
              
              7,402
              
              
              
              19,640
              
              
              
              51,203
              
              
              
              -
              
              
              
              78,24517,147
              
              
              
              486,276
              
              
              
              1,158,867
              
              
              
              799,202
              
              
              
              2,461,492$
              4,332,572
              
              
              $
              5,219,654
              
              
              $
              4,809,870
              
              
              $
              (4,351,529
              )
              
              $
              10,010,567
  144
  
 FIRSTENERGY
      SOLUTIONS CORP.CONSOLIDATING
      BALANCE SHEETS(Unaudited)As
      of December 31, 2007
                
                FES
                
                
                FGCO
                
                
                NGC
                
                
                Eliminations
                
                
                Consolidated(In
      thousands)ASSETSCURRENT
      ASSETS:Cash and cash
      equivalents
                
                $
                2
                
                
                $
                -
                
                
                $
                -
                
                
                $
                -
                
                
                $
                2Receivables-Customers
                
                
                133,846
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                133,846Associated
      companies
                
                
                327,715
                
                
                
                237,202
                
                
                
                98,238
                
                
                
                (286,656
                )
                
                
                376,499Other
                
                
                2,845
                
                
                
                978
                
                
                
                -
                
                
                
                -
                
                
                
                3,823Notes
      receivable from associated companies
                
                
                23,772
                
                
                
                -
                
                
                
                69,012
                
                
                
                -
                
                
                
                92,784Materials and
      supplies, at average cost
                
                
                195
                
                
                
                215,986
                
                
                
                210,834
                
                
                
                -
                
                
                
                427,015Prepayments
      and other
                
                
                67,981
                
                
                
                21,605
                
                
                
                2,754
                
                
                
                -
                
                
                
                92,340556,356
                
                
                
                475,771
                
                
                
                380,838
                
                
                
                (286,656
                )
                
                
                1,126,309PROPERTY,
      PLANT AND EQUIPMENT:In
      service
                
                
                25,513
                
                
                
                5,065,373
                
                
                
                3,595,964
                
                
                
                (392,082
                )
                
                
                8,294,768Less -
      Accumulated provision for depreciation
                
                
                7,503
                
                
                
                2,553,554
                
                
                
                1,497,712
                
                
                
                (166,756
                )
                
                
                3,892,01318,010
                
                
                
                2,511,819
                
                
                
                2,098,252
                
                
                
                (225,326
                )
                
                
                4,402,755Construction
      work in progress
                
                
                1,176
                
                
                
                571,672
                
                
                
                188,853
                
                
                
                -
                
                
                
                761,70119,186
                
                
                
                3,083,491
                
                
                
                2,287,105
                
                
                
                (225,326
                )
                
                
                5,164,456OTHER
      PROPERTY AND INVESTMENTS:Nuclear plant
      decommissioning trusts
                
                
                -
                
                
                
                -
                
                
                
                1,332,913
                
                
                
                -
                
                
                
                1,332,913Long-term
      notes receivable from associated companies
                
                
                -
                
                
                
                -
                
                
                
                62,900
                
                
                
                -
                
                
                
                62,900Investment in
      associated companies
                
                
                2,516,838
                
                
                
                -
                
                
                
                -
                
                
                
                (2,516,838
                )
                
                
                -Other
                
                
                2,732
                
                
                
                37,071
                
                
                
                201
                
                
                
                -
                
                
                
                40,0042,519,570
                
                
                
                37,071
                
                
                
                1,396,014
                
                
                
                (2,516,838
                )
                
                
                1,435,817DEFERRED
      CHARGES AND OTHER ASSETS:Accumulated
      deferred income taxes
                
                
                16,978
                
                
                
                522,216
                
                
                
                -
                
                
                
                (262,271
                )
                
                
                276,923Lease
      assignment receivable from associated companies
                
                
                -
                
                
                
                215,258
                
                
                
                -
                
                
                
                -
                
                
                
                215,258Goodwill
                
                
                24,248
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                24,248Property
      taxes
                
                
                -
                
                
                
                25,007
                
                
                
                22,767
                
                
                
                -
                
                
                
                47,774Pension
      asset
                
                
                3,217
                
                
                
                13,506
                
                
                
                -
                
                
                
                -
                
                
                
                16,723Unamortized
      sale and leaseback costs
                
                
                -
                
                
                
                27,597
                
                
                
                -
                
                
                
                43,206
                
                
                
                70,803Other
                
                
                22,956
                
                
                
                52,971
                
                
                
                6,159
                
                
                
                (38,133
                )
                
                
                43,95367,399
                
                
                
                856,555
                
                
                
                28,926
                
                
                
                (257,198
                )
                
                
                695,682$
                3,162,511
                
                
                $
                4,452,888
                
                
                $
                4,092,883
                
                
                $
                (3,286,018
                )
                
                $
                8,422,264LIABILITIES
      AND CAPITALIZATIONCURRENT
      LIABILITIES:Currently
      payable long-term debt
                
                $
                -
                
                
                $
                596,827
                
                
                $
                861,265
                
                
                $
                (16,896
                )
                
                $
                1,441,196Short-term
      borrowings-Associated
      companies
                
                
                -
                
                
                
                238,786
                
                
                
                25,278
                
                
                
                -
                
                
                
                264,064Other
                
                
                300,000
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                300,000Accounts
      payable-Associated
      companies
                
                
                287,029
                
                
                
                175,965
                
                
                
                268,926
                
                
                
                (286,656
                )
                
                
                445,264Other
                
                
                56,194
                
                
                
                120,927
                
                
                
                -
                
                
                
                -
                
                
                
                177,121Accrued
      taxes
                
                
                18,831
                
                
                
                125,227
                
                
                
                28,229
                
                
                
                (836
                )
                
                
                171,451Other
                
                
                57,705
                
                
                
                131,404
                
                
                
                11,972
                
                
                
                36,725
                
                
                
                237,806719,759
                
                
                
                1,389,136
                
                
                
                1,195,670
                
                
                
                (267,663
                )
                
                
                3,036,902CAPITALIZATION:Common
      stockholder's equity
                
                
                2,414,231
                
                
                
                951,542
                
                
                
                1,562,069
                
                
                
                (2,513,611
                )
                
                
                2,414,231Long-term debt
      and other long-term obligations
                
                
                -
                
                
                
                1,597,028
                
                
                
                242,400
                
                
                
                (1,305,716
                )
                
                
                533,7122,414,231
                
                
                
                2,548,570
                
                
                
                1,804,469
                
                
                
                (3,819,327
                )
                
                
                2,947,943NONCURRENT
      LIABILITIES:Deferred gain
      on sale and leaseback transaction
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                1,060,119
                
                
                
                1,060,119Accumulated
      deferred income taxes
                
                
                -
                
                
                
                -
                
                
                
                259,147
                
                
                
                (259,147
                )
                
                
                -Accumulated
      deferred investment tax credits
                
                
                -
                
                
                
                36,054
                
                
                
                25,062
                
                
                
                -
                
                
                
                61,116Asset
      retirement obligations
                
                
                -
                
                
                
                24,346
                
                
                
                785,768
                
                
                
                -
                
                
                
                810,114Retirement
      benefits
                
                
                8,721
                
                
                
                54,415
                
                
                
                -
                
                
                
                -
                
                
                
                63,136Property
      taxes
                
                
                -
                
                
                
                25,328
                
                
                
                22,767
                
                
                
                -
                
                
                
                48,095Lease market
      valuation liability
                
                
                -
                
                
                
                353,210
                
                
                
                -
                
                
                
                -
                
                
                
                353,210Other
                
                
                19,800
                
                
                
                21,829
                
                
                
                -
                
                
                
                -
                
                
                
                41,62928,521
                
                
                
                515,182
                
                
                
                1,092,744
                
                
                
                800,972
                
                
                
                2,437,419$
                3,162,511
                
                
                $
                4,452,888
                
                
                $
                4,092,883
                
                
                $
                (3,286,018
                )
                
                $
                8,422,264
  145
   FIRSTENERGY
      SOLUTIONS CORP.CONDENSED
      CONSOLIDATING STATEMENTS OF CASH FLOWS(Unaudited)For
      the Nine Months Ended September 30, 2008
                
                FES
                
                
                FGCO
                
                
                NGC
                
                
                Eliminations
                
                
                Consolidated(In
      thousands)NET
      CASH PROVIDED FROM OPERATING ACTIVITIES:
                
                $
                47,463
                
                
                $
                267,933
                
                
                $
                247,054
                
                
                $
                (8,317
                )
                
                $
                554,133CASH
      FLOWS FROM FINANCING ACTIVITIES:New
      Financing-Long-term
      debt
                
                
                -
                
                
                
                328,325
                
                
                
                209,050
                
                
                
                -
                
                
                
                537,375Equity
      contribution from parent
                
                
                280,000
                
                
                
                675,000
                
                
                
                175,000
                
                
                
                (850,000
                )
                
                
                280,000Short-term
      borrowings, net
                
                
                700,000
                
                
                
                -
                
                
                
                139,363
                
                
                
                (91,677
                )
                
                
                747,686Redemptions
      and Repayments-Long-term
      debt
                
                
                (1,777
                )
                
                
                (286,776
                )
                
                
                (180,666
                )
                
                
                8,317
                
                
                
                (460,902
                )Short-term
      borrowings, net
                
                
                -
                
                
                
                (91,677
                )
                
                
                -
                
                
                
                91,677
                
                
                
                -Common stock
      dividend payment
                
                
                (43,000
                )
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                (43,000
                )Net cash
      provided from financing activities
                
                
                935,223
                
                
                
                624,872
                
                
                
                342,747
                
                
                
                (841,683
                )
                
                
                1,061,159CASH
      FLOWS FROM INVESTING ACTIVITIES:Property
      additions
                
                
                (38,481
                )
                
                
                (778,329
                )
                
                
                (600,395
                )
                
                
                -
                
                
                
                (1,417,205
                )Proceeds from
      asset sales
                
                
                -
                
                
                
                15,218
                
                
                
                -
                
                
                
                -
                
                
                
                15,218Sales of
      investment securities held in trusts
                
                
                -
                
                
                
                -
                
                
                
                596,291
                
                
                
                -
                
                
                
                596,291Purchases of
      investment securities held in trusts
                
                
                -
                
                
                
                -
                
                
                
                (624,899
                )
                
                
                -
                
                
                
                (624,899
                )Loan
      repayments from (loans to) associated companies, net
                
                
                (94,755
                )
                
                
                (38,399
                )
                
                
                69,012
                
                
                
                -
                
                
                
                (64,142
                )Investment in
      subsidiary
                
                
                (850,000
                )
                
                
                -
                
                
                
                -
                
                
                
                850,000
                
                
                
                -Restricted
      funds for debt redemption
                
                
                -
                
                
                
                (52,090
                )
                
                
                (29,550
                )
                
                
                -
                
                
                
                (81,640
                )Other
                
                
                550
                
                
                
                (39,205
                )
                
                
                (260
                )
                
                
                -
                
                
                
                (38,915
                )Net cash used
      for investing activities
                
                
                (982,686
                )
                
                
                (892,805
                )
                
                
                (589,801
                )
                
                
                850,000
                
                
                
                (1,615,292
                )Net change in
      cash and cash equivalents
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Cash and cash
      equivalents at beginning of period
                
                
                2
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                2Cash and cash
      equivalents at end of period
                
                $
                2
                
                
                $
                -
                
                
                $
                -
                
                
                $
                -
                
                
                $
                2
  146
   FIRSTENERGY
      SOLUTIONS CORP.CONDENSED
      CONSOLIDATING STATEMENTS OF CASH FLOWS(Unaudited)For
      the Nine Months Ended September 30, 2007
                
                FES
                
                
                FGCO
                
                
                NGC
                
                
                Eliminations
                
                
                Consolidated(In
      thousands)NET
      CASH PROVIDED FROM (USED FOR)OPERATING
      ACTIVITIES
                
                $
                (7,937
                )
                
                $
                350,927
                
                
                $
                179,037
                
                
                $
                -
                
                
                $
                522,027CASH
      FLOWS FROM FINANCING ACTIVITIES:New
      Financing-Long-term
      debt
                
                
                -
                
                
                
                1,328,919
                
                
                
                -
                
                
                
                (1,328,919
                )
                
                
                -Equity
      contribution from parent
                
                
                700,000
                
                
                
                700,000
                
                
                
                -
                
                
                
                (700,000
                )
                
                
                700,000Short-term
      borrowings, net
                
                
                223,942
                
                
                
                -
                
                
                
                13,128
                
                
                
                (237,070
                )
                
                
                -Redemptions
      and Repayments-Common
      stock
                
                
                (600,000
                )
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                (600,000
                )Long-term
      debt
                
                
                -
                
                
                
                (795,019
                )
                
                
                (315,155
                )
                
                
                -
                
                
                
                (1,110,174
                )Short-term
      borrowings, net
                
                
                -
                
                
                
                (1,022,197
                )
                
                
                -
                
                
                
                237,070
                
                
                
                (785,127
                )Common stock
      dividend payment
                
                
                (67,000
                )
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                (67,000
                )Net cash
      provided from (used for) financing activities
                
                
                256,942
                
                
                
                211,703
                
                
                
                (302,027
                )
                
                
                (2,028,919
                )
                
                
                (1,862,301
                )CASH
      FLOWS FROM INVESTING ACTIVITIES:Property
      additions
                
                
                (10,119
                )
                
                
                (332,499
                )
                
                
                (140,289
                )
                
                
                -
                
                
                
                (482,907
                )Proceeds from
      asset sales
                
                
                -
                
                
                
                12,990
                
                
                
                -
                
                
                
                -
                
                
                
                12,990Proceeds from
      sale and leaseback transaction
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                1,328,919
                
                
                
                1,328,919Sales of
      investment securities held in trusts
                
                
                -
                
                
                
                -
                
                
                
                521,535
                
                
                
                -
                
                
                
                521,535Purchases of
      investment securities held in trusts
                
                
                -
                
                
                
                -
                
                
                
                (552,779
                )
                
                
                -
                
                
                
                (552,779
                )Loan
      repayments from (loans to) associated companies, net
                
                
                460,023
                
                
                
                (242,612
                )
                
                
                292,896
                
                
                
                -
                
                
                
                510,307Investment in
      subsidiary
                
                
                (700,000
                )
                
                
                -
                
                
                
                
                
                
                
                700,000
                
                
                
                -Other
                
                
                1,091
                
                
                
                (509
                )
                
                
                1,627
                
                
                
                -
                
                
                
                2,209Net cash
      provided from (used for) investing activities
                
                
                (249,005
                )
                
                
                (562,630
                )
                
                
                122,990
                
                
                
                2,028,919
                
                
                
                1,340,274Net change in
      cash and cash equivalents
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Cash and cash
      equivalents at beginning of period
                
                
                2
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                2Cash and cash
      equivalents at end of period
                
                $
                2
                
                
                $
                -
                
                
                $
                -
                
                
                $
                -
                
                
                $
                2





147





ITEM
3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK





See “Management’s
Discussion and Analysis of Financial Condition and Results of Operations –
Market Risk Information” in Item 2 above.





ITEM
4.  CONTROLS AND PROCEDURES





(a)  EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY





FirstEnergy’s chief
executive officer and chief financial officer have reviewed and evaluated the
registrant's disclosure controls and procedures. The term disclosure controls
and procedures means controls and other procedures of a registrant that are
designed to ensure that information required to be disclosed by the registrant
in the reports that it files or submits under the Securities Exchange Act of
1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported,
within the time periods specified in the Securities and Exchange Commission's
rules and forms. Disclosure controls and procedures include, without limitation,
controls and procedures designed to ensure that information required to be
disclosed by an issuer in the reports that it files or submits under that Act is
accumulated and communicated to the registrant's management, including its
principal executive and principal financial officers, or persons performing
similar functions, as appropriate to allow timely decisions regarding required
disclosure. Based on that evaluation, those officers have concluded that the
registrant's disclosure controls and procedures are effective and were designed
to bring to their attention material information relating to the registrant and
its consolidated subsidiaries by others within those entities.





(b) 
CHANGES IN INTERNAL CONTROLS





During the quarter
ended September 30, 2008, there were no changes in FirstEnergy’s internal
control over financial reporting that have materially affected, or are
reasonably likely to materially affect, the registrant’s internal control over
financial reporting.





ITEM
4T. CONTROLS AND PROCEDURES – FES, OE, CEI, TE, JCP&L, MET-ED AND
PENELEC





(a) 
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES





Each registrant's
chief executive officer and chief financial officer have reviewed and evaluated
such registrant's disclosure controls and procedures. The term disclosure
controls and procedures means controls and other procedures of a registrant that
are designed to ensure that information required to be disclosed by the
registrant in the reports that it files or submits under the Securities Exchange
Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and
reported, within the time periods specified in the Securities and Exchange
Commission's rules and forms. Disclosure controls and procedures include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by an issuer in the reports that it files or submits
under that Act is accumulated and communicated to the registrant's management,
including its principal executive and principal financial officers, or persons
performing similar functions, as appropriate to allow timely decisions regarding
required disclosure. Based on that evaluation, those officers have concluded
that such registrant's disclosure controls and procedures are effective and were
designed to bring to their attention material information relating to such
registrant and its consolidated subsidiaries by others within those
entities.





(b) 
CHANGES IN INTERNAL CONTROLS





During the quarter
ended September 30, 2008, there were no changes in the registrants' internal
control over financial reporting that have materially affected, or are
reasonably likely to materially affect, the registrants' internal control over
financial reporting.





148








PART II. OTHER
INFORMATION








ITEM
1.     LEGAL PROCEEDINGS





Information required
for Part II, Item 1 is incorporated by reference to the discussions in
Notes 10 and 11 of the Consolidated Financial Statements in Part I, Item 1
of this Form 10-Q.





ITEM
1A.  RISK FACTORS





FirstEnergy’s Annual
Report on Form 10-K for the year ended December 31, 2007, and Quarterly
Report on Form 10-Q for the quarter ended June 30, 2008, include a detailed
discussion of its risk factors. The information presented below updates
certain of those risk factors and should be read in conjunction with the risk
factors and information disclosed in FirstEnergy’s prior SEC
filings.





FirstEnergy
relies on access to the credit and capital markets to finance a portion of its
working capital requirements and to support its liquidity needs. Access to these
markets may be adversely affected by factors beyond FirstEnergy’s control,
including turmoil in the financial services industry, volatility in securities
trading markets and general economic downturns. In particular, recent
disruptions in the variable-rate demand bond markets could require utilization
of a significant portion of the sources of liquidity currently available to
FirstEnergy and its subsidiaries.





FirstEnergy relies
upon access to the credit and capital markets as a source of liquidity for the
portion of its working capital requirements not provided by cash from operations
and to comply with various regulatory requirements. Market disruptions such as
those currently being experienced in the United States and abroad may increase
FirstEnergy’s cost of borrowing or adversely affect its ability to access
sources of liquidity upon which it relies to finance operations and satisfy
obligations as they become due. These disruptions may include turmoil in the
financial services industry, including substantial uncertainty surrounding
particular lending institutions and counterparties with whom FirstEnergy
does business, unprecedented volatility in the markets where FirstEnergy’s
outstanding securities trade, and general economic downturns in the areas where
FirstEnergy does business. If FirstEnergy is unable to access credit at
competitive rates, or if its short-term or long-term borrowing costs
dramatically increase, FirstEnergy’s ability to finance its operations, meet its
short-term obligations and implement its operating strategy could be adversely
affected.





ITEM
2.     UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF
PROCEEDS





(c)   FirstEnergy





The
table below includes information on a monthly basis regarding purchases made by
FirstEnergy of its common stock.





PeriodJuly
      1-31,
            
            August
      1-31,
            
            September
      1-30,
            
            Third2008
            
            2008
            
            2008
            
            QuarterTotal Number
      of Shares Purchased (a)
            
            52,166
            
            32,187
            
            208,772
            
            293,125Average Price
      Paid per Share
            
            $81.63
            
            $71.63
            
            $72.09
            
            $73.74Total Number
      of Shares PurchasedAs Part of Publicly Announced
      Plansor ProgramsMaximum Number
      (or Approximate Dollar
            
            -
            
            -
            
            -
            
            -Value) of Shares that May Yet
      BePurchased Under the Plans or
      Programs
            
            -
            
            -
            
            -
            
            -





(a)
            Share amounts
      reflect purchases on the open market to satisfy FirstEnergy's obligations
      to deliver common stock under its 2007 Incentive Compensation Plan,
      Deferred Compensation Plan for Outside Directors, Executive Deferred
      Compensation Plan, Savings Plan and Stock Investment Plan. In addition,
      such amounts reflect shares tendered by employees to pay the exercise
      price or withholding taxes upon exercise of stock options granted under
      the 2007 Incentive Compensation Plan and the Executive Deferred
      Compensation Plan, and shares purchased as part of publicly announced
      plans.



















149





ITEM
6.     EXHIBITS





Exhibit
              NumberFirstEnergy10.1
            $U.S.
      300,000,000 Credit Agreement, dated as of October 8, 2008, among
      FirstEnergy Generation Corp., as Borrower, FirstEnergy Corp. and
      FirstEnergy Solutions Corp., as Guarantors, Credit Suisse and the other
      Banks parties thereto from time to time, as Banks, and Credit Suisse, as
      Administrative Agent12
            Fixed charge
      ratios15
            Letter from
      independent registered public accounting firm31.1
            Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-14(a)31.2
            Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-14(a)32
            Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350FES4.1
            Open-End
      Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June
      19, 2008, of FirstEnergy Generation Corp. to The Bank of New York Trust
      Company, N.A., as Trustee10.1
            $U.S.
      300,000,000 Credit Agreement, dated as of October 8, 2008, among
      FirstEnergy Generation Corp., as Borrower, FirstEnergy Corp. and
      FirstEnergy Solutions Corp., as Guarantors, Credit Suisse and the other
      Banks parties thereto from time to time, as Banks, and Credit Suisse, as
      Administrative Agent10.2
            Third Restated
      Partial Requirements Agreement dated November 1,
  200831.1
            Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-14(a)31.2
            Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-14(a)32
            Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350OE4.1
            Fourteenth
      Supplemental Indenture, dated as of October 1, 2008, to Ohio Edison
      Company’s General Mortgage Indenture and Deed of Trust dated as of January
      1, 1998  (incorporated by reference to October 22, 2008
      Form 8-K, Exhibit 4.1)12
            Fixed charge
      ratios15
            Letter from
      independent registered public accounting firm31.1
            Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-14(a)31.2
            Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-14(a)32
            Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350CEI12
            Fixed charge
      ratios15
            Letter from
      independent registered public accounting firm31.1
            Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-14(a)31.2
            Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-14(a)32
            Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350TE12
            Fixed charge
      ratios15
            Letter from
      independent registered public accounting firm31.1
            Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-14(a)31.2
            Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-14(a)32
            Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350JCP&L12
            Fixed charge
      ratios15
            Letter from
      independent registered public accounting firm31.1
            Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-14(a)31.2
            Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-14(a)32
            Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350Met-Ed10.2
            Third Restated
      Partial Requirements Agreement dated November 1,
  200812
            Fixed charge
      ratios15
            Letter from
      independent registered public accounting firm31.1
            Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-14(a)31.2
            Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-14(a)32
            Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350Penelec10.2
            Third Restated
      Partial Requirements Agreement dated November 1,
  200812
            Fixed charge
      ratios15
            Letter from
      independent registered public accounting firm31.1
            Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-14(a)31.2
            Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-14(a)32
            Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350





Pursuant to
reporting requirements of respective financings, FirstEnergy, OE, CEI, TE,
JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an
exhibit to this Form 10-Q. Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of
Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor
Penelec have filed as an exhibit 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% of its respective total assets, but
each hereby agrees to furnish to the SEC on request any such
documents.





150





SIGNATURES











Pursuant to the
requirements of the Securities Exchange Act of 1934, each Registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly
authorized.








November 7,
2008

















FIRSTENERGY
      CORP.RegistrantFIRSTENERGY SOLUTIONS
      CORP.RegistrantOHIO EDISON
      COMPANYRegistrantTHE
      CLEVELAND ELECTRICILLUMINATING
      COMPANYRegistrantTHE TOLEDO EDISON
      COMPANYRegistrantMETROPOLITAN EDISON
      COMPANYRegistrantPENNSYLVANIA ELECTRIC
      COMPANYRegistrant











/s/  Harvey
      L. WagnerHarvey L.
      WagnerVice
      President, Controllerand Chief
      Accounting Officer











JERSEY CENTRAL POWER
      & LIGHT COMPANYRegistrant/s/  Paulette
      R. ChatmanPaulette R.
      ChatmanController(Principal
      Accounting Officer)









151