**THE TOLEDO
EDISON COMPANY**
 
 **2006 ANNUAL
REPORT TO STOCKHOLDERS**
 
 
 
 The Toledo Edison
Company is a wholly owned electric utility operating subsidiary of FirstEnergy
Corp. It engages in the distribution and sale of electric energy in an area of
approximately 2,300 square miles in northwestern Ohio. The area it serves has a
population of approximately 0.8 million.
 
 
 
 
 
 
 
 **Contents**
    **Page**Glossary of
      Terms
    i-iiReport of
      Independent Registered Public Accounting Firm
    1Selected
      Financial Data
    2Management's
      Discussion and Analysis
    3-19Consolidated
      Statements of Income
    20Consolidated
      Balance Sheets
    21Consolidated
      Statements of Capitalization
    22Consolidated
      Statements of Common Stockholder's Equity
    23Consolidated
      Statements of Preferred Stock
    23Consolidated
      Statements of Cash Flows
    24Consolidated
      Statements of Taxes
    25Notes to
      Consolidated Financial Statements
    26-45
 
 
 **GLOSSARY
OF TERMS**
   The following
abbreviations and acronyms are used in this report to identify The Toledo Edison
Company and its affiliates:
 
 ATSI
    American
      Transmission Systems, Inc., owns and operates transmission
      facilitiesCEI
    The Cleveland
      Electric Illuminating Company, an affiliated Ohio electric
      utilityCenterior
    Centerior
      Energy Corporation, former parent of CEI and TE, which merged with OE to
      form
      FirstEnergy on
      November 8, 1997CFC
    Centerior
      Funding Corporation, a wholly owned finance subsidiary of
    CEICompanies
    OE, CEI, TE,
      Penn, JCP&L, Met-Ed and PenelecFENOC
    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 companyJCP&L
    Jersey Central
      Power & Light Company, an affiliated New Jersey electric
      utilityMet-Ed
    Metropolitan
      Edison Company, an affiliated Pennsylvania electric
  utilityNGC
    FirstEnergy
      Nuclear Generation Corp., owns nuclear generating
    facilitiesOE
    Ohio Edison
      Company, an affiliated Ohio electric utilityOhio
      Companies
    CEI, OE and
      TEPenelec
    Pennsylvania
      Electric Company, an affiliated Pennsylvania electric
    utilityPenn
    Pennsylvania
      Power Company, an affiliated Pennsylvania electric
  utilityTE
    The Toledo
      Edison CompanyThe following
      abbreviations and acronyms are used to identify frequently used terms in
      this report:AOCL
    Accumulated
      Other Comprehensive LossARO
    Asset
      Retirement ObligationCAT
    Commercial
      Activity TaxCBP
    Competitive
      Bid ProcessECAR
    East Central
      Area Reliability CoordinationEPACT
    Energy Policy
      Act of 2005ERO
    Electric
      Reliability OrganizationFASB
    Financial
      Accounting Standards BoardFERC
    Federal Energy
      Regulatory CommissionFIN
    FASB
      InterpretationFIN
      46R
    FIN 46
      (revised December 2003), "Consolidation of Variable Interest
      Entities"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"Fitch
    Fitch Ratings,
      Ltd.FMB
    First Mortgage
      BondsFSP
    FASB Staff
      PositionFSP SFAS 115-1
      SFAS
      124-1
    FSP SFAS 115-1
      and SFAS 124-1, "The Meaning of Other-Than-Temporary
      Impairment and
      its Application to Certain Investments"GAAP
    Accounting
      Principles Generally Accepted in the United StatesKWH
    Kilowatt-hoursLOC
    Letter of
      CreditMISO
    Midwest
      Independent Transmission System Operator, Inc.Moody's
    Moody's
      Investors ServiceMSG
    Market Support
      GenerationNERC
    North American
      Electric Reliability CorporationNOPR
    Notice of
      Proposed RulemakingOCC
    Office of the
      Ohio Consumers' CounselOCI
    Other
      Comprehensive IncomeOPEB
    Other
      Post-Employment BenefitsPJM
    PJM
      Interconnection LLCPLR
    Provider of
      Last ResortPPUC
    Pennsylvania
      Public Utility CommissionPRP
    Potentially
      Responsible PartyPSA
    Power Supply
      AgreementsPUCO
    Public
      Utilities Commission of OhioPUHCA
    Public Utility
      Holding Company Act of 1935RCP
    Rate Certainty
      Plan
  
 i
 
 **GLOSSARY
OF TERMS, Cont'd.**
   RSP
    Rate
      Stabilization PlanRTC
    Regulatory
      Transition ChargeS&P
    Standard &
      Poor's Ratings ServiceSEC
    United States
      Securities and Exchange CommissionSFAS
    Statement of
      Financial Accounting StandardsSFAS
      71
    SFAS No. 71,
      "Accounting for the Effects of Certain Types of
  Regulation"SFAS
      87
    SFAS No. 87,
      "Employers' Accounting for Pensions"SFAS
      101
    SFAS No. 101,
      "Accounting for Discontinuation of Application of SFAS
  71"SFAS
      106
    SFAS No. 106,
      "Employers' Accounting for Postretirement Benefits Other Than
      Pensions"SFAS
      107
    SFAS No. 107,
      "Disclosures about Fair Value of Financial Instruments"SFAS
      115
    SFAS No. 115,
      "Accounting for Certain Investments in Debt and Equity
      Securities"SFAS
      142
    SFAS No. 142,
      "Goodwill and Other Intangible Assets"SFAS
      143
    SFAS No. 143,
      "Accounting for Asset Retirement Obligations"SFAS
      144
    SFAS No. 144,
      "Accounting for the Impairment or Disposal of Long-Lived
      Assets"SFAS
      157
    SFAS No. 157,
      "Fair Value Measurements"SFAS
      158
    SFAS No. 158,
      "Employers' Accounting for Defined Benefit Pensions and Other
      Postretirement
      Plans-an
      amendment of FASB Statements No. 87, 88, 106, and
  132(R)"SFAS
      159
    SFAS No. 159,
      "The Fair Value Option for Financial Assets and Financial Liabilities -
      Including an
      amendment of
      FASB Statements No. 115"VIE
    Variable
      Interest Entity
   
 **ii**
   **Report of
Independent Registered Public Accounting Firm**
 
 
 
 
 
 
 To the Stockholder
and Board of
 Directors of The
Toledo Edison Company:
 
 
 In our opinion, the
accompanying consolidated balance sheets and the related consolidated statements
of income, capitalization, common stockholder's equity, preferred stock and cash
flows present fairly, in all material respects, the financial position of The
Toledo Edison Company and its subsidiary at December 31, 2006 and 2005, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2006 in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
 
 Our audit was
conducted for the purpose of forming an opinion on the basic financial
statements taken as a whole. The Supplemental Consolidated Statements of Taxes
is presented for purposes of additional analysis and is not a required part of
the basic financial statements. Such information has been subjected to the
auditing procedures applied in the audit of the basic financial statements and,
in our opinion, is fairly stated in all material respects in relation to the
basic financial statements taken as a whole.
 
 As discussed in Note
3 to the consolidated financial statements, the Company changed the manner in
which it accounts for defined benefit pension and other postretirement benefit
plans as of December 31, 2006.
 
 
 
 
 PricewaterhouseCoopers
LLP
 Cleveland,
Ohio
 February 27,
2007
 
  1
  The following
selected financial data should be read in conjunction with, and is qualified in
its entirety by reference to, the sections entitled "Management's Discussion and
Analysis of Results of Operations and Financial Condition" and with our
consolidated financial statements and the "Notes to Consolidated Financial
Statements." Our Consolidated Statements of Income are not necessarily
indicative of future conditions or results of operations.
  **THE
      TOLEDO EDISON COMPANY****SELECTED
      FINANCIAL DATA****For
      the Years Ended December 31,**
    
    
    
    **2006**
    
    
    
    **2005**
    
    
    
    **2004**
    
    
    
    **2003**
    
    
    
    **2002*****(Dollars in thousands)*****GENERAL
      FINANCIAL INFORMATION:**Revenues
    $
    928,001
    
    
    
    
    $
    1,040,186
    
    
    
    
    $
    1,008,112
    
    
    
    
    $
    932,335
    
    
    
    
    $
    996,045Operating
      Income
    $
    150,521
    
    
    
    
    $
    132,266
    
    
    
    
    $
    125,821
    
    
    
    
    $
    35,660
    
    
    
    
    $
    36,699Net Income
      (Loss)
    $
    99,404
    
    
    
    
    $
    76,164
    
    
    
    
    $
    86,283
    
    
    
    
    $
    45,480
    
    
    
    
    $
    (5,142
    )Earnings
      (Loss) on Common Stock
    $
    89,995
    
    
    
    
    $
    68,369
    
    
    
    
    $
    77,439
    
    
    
    
    $
    36,642
    
    
    
    
    $
    (15,898
    )Total
      Assets
    $
    1,798,642
    
    
    
    
    $
    2,101,965
    
    
    
    
    $
    2,825,477
    
    
    
    
    $
    2,849,605
    
    
    
    
    $
    2,855,725**CAPITALIZATION
      AS OF DECEMBER 31:**Common
      Stockholder's Equity
    
    
    
    
    $
    481,415
    
    
    
    
    $
    863,426
    
    
    
    
    $
    835,327
    
    
    
    
    $
    749,521
    
    
    
    
    $
    681,195Preferred
      Stock Not Subject to MandatoryRedemption
    
    
    
    
    
    -
    
    
    
    
    
    96,000
    
    
    
    
    
    126,000
    
    
    
    
    
    126,000
    
    
    
    
    
    126,000Long-Term
      Debt
    
    
    
    
    
    358,281
    
    
    
    
    
    237,753
    
    
    
    
    
    300,299
    
    
    
    
    
    270,072
    
    
    
    
    
    557,265Total
      Capitalization
    
    
    
    
    $
    839,696
    
    
    
    
    $
    1,197,179
    
    
    
    
    $
    1,261,626
    
    
    
    
    $
    1,145,593
    
    
    
    
    $
    1,364,460**CAPITALIZATION
      RATIOS:**Common
      Stockholder's Equity
    
    
    
    
    
    57.3
    %
    
    
    
    
    72.1
    %
    
    
    
    
    66.2
    %
    
    
    
    
    65.4
    %
    
    
    
    
    49.9
    %Preferred
      Stock Not Subject to MandatoryRedemption
    
    
    
    
    
    -
    
    
    
    
    
    8.0
    
    
    
    
    
    10.0
    
    
    
    
    
    11.0
    
    
    
    
    
    9.2Long-Term
      Debt
    
    
    
    
    
    42.7
    
    
    
    
    
    19.9
    
    
    
    
    
    23.8
    
    
    
    
    
    23.6
    
    
    
    
    
    40.9Total
      Capitalization
    
    
    
    
    
    100.0
    %
    
    
    
    
    100.0
    %
    
    
    
    
    100.0
    %
    
    
    
    
    100.0
    %
    
    
    
    
    100.0
    %**DISTRIBUTION
      KWH DELIVERIES (Millions):**Residential
    
    
    
    
    
    2,430
    
    
    
    
    
    2,543
    
    
    
    
    
    2,316
    
    
    
    
    
    2,312
    
    
    
    
    
    2,427Commercial
    
    
    
    
    
    2,821
    
    
    
    
    
    2,937
    
    
    
    
    
    2,796
    
    
    
    
    
    2,771
    
    
    
    
    
    2,702Industrial
    
    
    
    
    
    5,139
    
    
    
    
    
    5,110
    
    
    
    
    
    5,006
    
    
    
    
    
    5,097
    
    
    
    
    
    5,280Other
    
    
    
    
    
    59
    
    
    
    
    
    64
    
    
    
    
    
    56
    
    
    
    
    
    69
    
    
    
    
    
    57Total
    
    
    
    
    
    10,449
    
    
    
    
    
    10,654
    
    
    
    
    
    10,174
    
    
    
    
    
    10,249
    
    
    
    
    
    10,466**CUSTOMERS
      SERVED:**Residential
    
    
    
    
    
    275,869
    
    
    
    
    
    275,226
    
    
    
    
    
    273,800
    
    
    
    
    
    270,258
    
    
    
    
    
    272,474Commercial
    
    
    
    
    
    37,675
    
    
    
    
    
    37,803
    
    
    
    
    
    36,710
    
    
    
    
    
    36,969
    
    
    
    
    
    32,037Industrial
    
    
    
    
    
    218
    
    
    
    
    
    224
    
    
    
    
    
    211
    
    
    
    
    
    215
    
    
    
    
    
    1,883Other
    
    
    
    
    
    588
    
    
    
    
    
    564
    
    
    
    
    
    504
    
    
    
    
    
    451
    
    
    
    
    
    468Total
    
    
    
    
    
    314,350
    
    
    
    
    
    313,817
    
    
    
    
    
    311,225
    
    
    
    
    
    307,893
    
    
    
    
    
    306,862**NUMBER
      OF EMPLOYEES**
    
    420
    
    
    
    
    
    431
    
    
    
    
    
    414
    
    
    
    
    
    446
    
    
    
    
    
    508
 
 
 
 
 2
   **THE TOLEDO
EDISON COMPANY**
 
 **MANAGEMENT'S
DISCUSSION AND**
 **ANALYSIS OF
RESULTS OF OPERATIONS**
 **AND
FINANCIAL CONDITION**
 
 
 ***Forward-Looking
Statements:*** *This discussion
includes forward-looking statements based on information currently available to
management. Such statements are subject to certain risks and uncertainties.
These statements typically contain, but are not limited to, the terms
"anticipate," "potential," "expect," "believe," "estimate" and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, replacement power
costs being higher than anticipated or inadequately hedged, the continued
ability to collect transition and other charges or to recover increased
transmission costs, maintenance costs being higher than anticipated, legislative
and regulatory changes (including revised environmental requirements), and the
legal and regulatory changes resulting from the implementation of the Energy
Policy Act of 2005 (including, but not limited to, the repeal of the Public
Utility Holding Company Act of 1935), the uncertainty of the timing and amounts
of the capital expenditures, adverse regulatory or legal decisions and outcomes
(including, but not limited to, the revocation of necessary licenses or
operating permits, fines or other enforcement actions and remedies) of
governmental investigations and oversight, including by the Securities and
Exchange Commission, the Nuclear Regulatory Commission and the Public Utilities
Commission of Ohio as disclosed in our Securities and Exchange Commission
filings, the timing and outcome of various proceedings before the Public
Utilities Commission of Ohio (including, but not limited to, the successful
resolution of the issues remanded to the Public Utilities Commission of Ohio by
the Ohio Supreme Court regarding the Rate Stabilization Plan), the continuing
availability and operation of generating units, the inability to accomplish or
realize anticipated benefits from strategic goals (including employee workforce
initiatives), the anticipated benefits from voluntary pension plan
contributions, the ability to improve electric commodity margins and to
experience growth in the distribution business, the ability to access the public
securities and other capital markets and the cost of such capital, the outcome,
cost and other effects of present and potential legal and administrative
proceedings and claims related to the August 14, 2003 regional power
outage, the risks and other factors discussed from time to time in our
Securities and Exchange Commission filings, and other similar factors. Also, a
credit rating should not be viewed as a recommendation to buy, sell or hold
securities and may be revised or withdrawn by a rating agency at any time. We
expressly disclaim any current intention to update any forward-looking
statements contained herein as a result of new information, future events, or
otherwise.*
 
 **Reclassifications**
 
 As discussed in
Note 1 to the
consolidated financial statements, certain prior year amounts have been
reclassified to conform to the current year presentation. These
reclassifications did not change previously reported earnings for 2005 and 2004.
All reclassifications have been evaluated and determined to be properly
reflected as reclassifications in the respective period as presented in the
Consolidated Balance Sheets and Statements of Cash Flows.
 
 **FirstEnergy
Intra-System Generation Asset Transfers**
   In 2005, the Ohio
Companies and Penn entered into certain agreements implementing a series of
intra-system generation asset transfers that were completed in the fourth
quarter of 2005. The asset transfers resulted in the respective undivided
ownership interests of the Ohio Companies and Penn in FirstEnergy's nuclear and
non-nuclear generation assets being owned by NGC and FGCO, respectively. The
generating plant interests transferred did not include our leasehold interests
in certain of the plants that are currently subject to sale and leaseback
arrangements with non-affiliates.
 
 On October 24,
2005, we completed the intra-system transfer of non-nuclear generation assets to
FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with
the Ohio Companies and Penn, leased, operated and maintained the non-nuclear
generation assets that it now owns. The asset transfers were consummated
pursuant to FGCO's purchase option under the Master Facility Lease.
 
 On December 16,
2005, we completed the intra-system transfer of our ownership interests in the
nuclear generation assets to NGC through a sale at net book value. FENOC
continues to operate and maintain the nuclear generation assets.
 
 These transactions
were undertaken pursuant to the Ohio Companies' and Penn's restructuring plans
that were approved by the PUCO and the PPUC, respectively, under applicable Ohio
and Pennsylvania electric utility restructuring legislation. Consistent with the
restructuring plans, generation assets that had been owned by the Ohio Companies
and Penn were required to be separated from the regulated delivery business of
those companies through transfer to a separate corporate entity. The
transactions essentially completed the divestitures contemplated by the
restructuring plans by transferring the ownership interests to NGC and FGCO
without impacting the operation of the plants.
  3
  
 The transfers affect
our comparative earnings results with reductions in both revenues and expenses.
Revenues are reduced due to the termination of certain arrangements with FES,
under which we previously sold our nuclear-generated KWH to FES and leased our
non-nuclear generation assets to FGCO, a subsidiary of FES. Our expenses are
lower due to the nuclear fuel and operating costs assumed by NGC as well as
depreciation and property tax expenses assumed by FGCO and NGC related to the
transferred generating assets. With respect to our retained leasehold interests
in the Bruce Mansfield Plant and Beaver Valley Unit 2, we have continued the
generation KWH sales arrangement with FES and our Beaver Valley Unit 2 leased
capacity sales arrangement with CEI, and continue to be obligated on the
applicable portion of expenses related to those interests. In addition, we
receive interest income on associated company notes receivable from the transfer
of our generation net assets. FES continues to provide our PLR requirements
under revised purchased power arrangements covering the three-year period
beginning January 1, 2006 (see Outlook - Regulatory Matters).
 
 The effects on our
results of operations in 2006 compared to 2005 from the generation asset
transfers are summarized in the following table:




**Intra-System
      Generation Asset Transfers-**
    
    
    
    **Increase****Income
      Statement Effects**
    
    
    
    **(Decrease)*****(In
      millions)***Revenues:Non-nuclear generating units rent
    
    
    (a
    )
    $
    (12
    )Nuclear-generated KWH sales
    
    
    (b
    )
    
    (131
    )Total - Revenues Effect
    
    
    
    
    
    (143
    )Expenses:Fuel costs - nuclear
    
    
    (c
    )
    
    (21
    )Nuclear operating costs
    
    
    (c
    )
    
    (101
    )Provision for depreciation
    
    
    (d
    )
    
    (29
    )General taxes
    
    
    (e
    )
    
    (6
    )Total - Expenses Effect
    
    
    
    
    
    (157
    )Operating
      Income Effect
    
    
    
    
    
    14Other Income
      (expense):Interest income from notes receivable
    
    
    (f
    )
    
    16Nuclear decommissioning trust earnings
    
    
    (g
    )
    
    (22
    )Interest expense
    
    
    (h
    )
    
    (16
    )Total - Other Income Effect
    
    
    
    
    
    10Income Before
      Income Taxes Effect
    
    
    
    
    
    24Income
      Taxes
    
    
    (i
    )
    
    10Net Income
      Effect
    
    
    
    
    $
    14(a) 
      Elimination of non-nuclear generation assets lease to
  FGCO.(b) 
      Reduction of nuclear-generated wholesale KWH sales to
  FES.(c) 
      Reduction of nuclear fuel and operating costs.(d) 
      Reduction of depreciation expense and asset retirement obligation
      accretion
      related to generation assets.(e) 
      Reduction of property tax expense on generation assets.(f)  
      Interest income on associated company notes receivable from the transfer
      of
      generation net assets.(g) Reduction
      of earnings on nuclear decommissioning trusts.(h) Reduction
      of interest expense on associated company money pool debt for
      working capital requirements and the elimination of interest on pollution
      control
      notes redeemed in conjunction with the nuclear asset
      transfers.(i) 
      Income tax effect of the above
adjustments.














Earnings on common
stock increased to $90 million in 2006 from $68 million in 2005. The
change in earnings reflected the effects of the generation asset transfer shown
in the table above. Excluding the impact of the asset transfer, earnings
increased $8 million primarily due to higher revenues and decreased
amortization of regulatory assets, partially offset by increased purchased power
costs.





Earnings on common
stock decreased to $68 million in 2005 from $77 million in 2004. This
decrease resulted primarily from higher nuclear and other operating costs,
partially offset by higher operating revenues, lower purchased power costs and
increased deferrals of new regulatory assets.





4





*Revenues*


Revenues decreased
by $112 million or 10.8% in 2006 from 2005, primarily due to the generation
asset transfer impact displayed in the table above. Excluding the effects of the
generation asset transfers, revenues increased $31 million primarily due to a
$145 million increase in retail generation sales revenues and a $35 million
reduction in customer shopping incentives, partially offset by a $135 million
decrease in distribution revenues and a $16 million decrease in non-affiliated
wholesale sales.





Wholesale revenues
from non-affiliates decreased in 2006 as a result of the December 2005 cessation
of the MSG sales arrangements under our transition plan. We had been required to
provide the MSG to non-affiliated alternative suppliers.





Revenues increased
by $32 million or 3.2% in 2005 from 2004. The higher revenues
resulted from increased retail generation revenues of $45 million,
partially offset by a $5 million decrease in distribution revenues, a
$4 million decrease in wholesale sales revenue and an increase in shopping
incentive credits of $4 million.





Changes in electric
generation KWH sales and revenues in 2006 and
2005 from the prior year are summarized in the following tables.





**Changes
      in Generation KWH Sales**
    
    **2006**
    
    **2005****Increase
      (Decrease)**Electric
      Generation:Retail
    
    
    13.2
    %
    
    4.2
    %Wholesale*
    
    
    (24.3
    )%
    
    2.3
    %**Net
      Change in Generation Sales**
    
    
    **(0.8**
    **)%**
    
    **3.1**
    **%**








**Change
      in Generation Revenues**
    
    **2006**
    
    **2005****Increase
      (Decrease)**
    
    ***(In
      millions)***Retail
      Generation:Residential
    
    $
    74
    
    $
    2Commercial
    
    
    48
    
    
    5Industrial
    
    
    23
    
    
    38Total Retail
      Generation
    
    
    145
    
    
    45Wholesale*
    
    
    (16
    )
    
    (4
    )**Net
      Increase in Generation Revenues**
    
    **$**
    **129**
    
    **$**
    **41**







* The 2006 amount
excludes impact of generation asset transfers related to nuclear-generated KWH
sales.





Retail generation
revenues increased in all customer sectors in 2006 compared to 2005 (as shown in
the table above) due to higher unit prices and increased KWH sales. The higher
unit prices for generation reflected the rate stabilization charge and the fuel
cost recovery rider, both of which became effective in the first quarter of 2006
under provisions of the RSP and RCP. The increase in generation KWH sales
(residential - 51.3%, commercial - 13.1% and industrial - 2.4%) primarily
resulted from decreased customer shopping. Generation services provided by
alternative suppliers as a percentage of total sales delivered in our franchise
area decreased by: residential - 32.5 percentage
points ,
commercial - 9.4 percentage points and
industrial - 1.7 percentage
points .
The decreased shopping resulted from certain alternative energy suppliers
exiting the northern Ohio market at the end of 2005.





Retail generation
revenues increased in all customer sectors in 2005 compared to 2004. Industrial
revenues increased as a result of higher unit prices and a slight increase in
KWH sales of 1.5%. Higher KWH sales to industrial customers were partially
offset by a slight increase in customer shopping. Generation services provided
to industrial customers by alternative suppliers as a percent of total
industrial sales delivered in our service area increased by 0.5 percentage
points during 2005. Higher residential and commercial revenues resulted from
increased KWH sales (6.0% and 11.1%, respectively), reflecting increased air
conditioning loads due to the warmer summer weather and higher unit prices. The
2005 increase in commercial KWH sales reflected a 2.9 percentage point reduction
in customer shopping, while the residential KWH sales increase was moderated by
a 2.0 percentage point increase in customer shopping.





5








Changes in
distribution KWH deliveries and revenues in 2006 and
2005 from the prior year are summarized in the following table.








**Changes in
      DistributionKWH
      Deliveries**
    ****
    ****
    **2006**
    ****
    ****
    **2005****Increase
      (Decrease)**Distribution
      Deliveries:Residential
    
    
    (4.4
    )%
    
    9.8
    %Commercial
    
    
    (4.0
    )%
    
    5.1
    %Industrial
    
    
    0.6
    %
    
    2.1
    %**Net
      Change in Distribution Deliveries**
    
    
    **(1.9**
    **)%**
    
    **4.7**
    **%**








**Changes
      in Distribution Revenues**
    
    **2006**
    
    **2005****Increase
      (Decrease)**
    
    ***(In
      millions)***Residential
    
    
    
    
    $
    (57
    )
    
    
    
    $
    15Commercial
    
    
    
    
    
    (60
    )
    
    
    
    
    4Industrial
    
    
    
    
    
    (18
    )
    
    
    
    
    (26
    )**Net
      Decrease in Distribution Revenues**
    
    
    
    
    $
    (135
    )
    
    
    
    **$**
    (7
    )





The distribution
revenue decreases for 2006 compared to the prior year shown in the table above
primarily reflected lower unit prices in all customer sectors and decreased KWH
deliveries to residential and commercial customers. The lower unit prices
resulted from the completion of the generation-related transition cost recovery
in 2005 under our transition plan, partially offset by increased transmission
rates to recover MISO costs beginning in the first quarter of 2006 (see Outlook
- Regulatory Matters). The lower KWH deliveries
to residential and commercial customers in 2006 reflected the impact of milder
weather in 2006 compared to 2005. KWH deliveries to
industrial customers increased in 2006 due to increased sales to automotive and
oil refinery customers.





The $7 million
decrease in distribution revenues in 2005 was due to lower
industrial revenues, partially offset by increases in residential and commercial
revenues. The impact from lower industrial unit prices more than offset higher
KWH sales in all customer classes.





*Expenses*




Total expenses
decreased by $130 million in 2006 and increased by $26 million in
2005, compared with the prior year. The 2006 decrease was principally due to the
generation asset transfer effects as shown in the table above. Excluding the
asset transfer effects, the following table presents changes from the prior year
by expense category:





**Expenses
      - Changes**
    
    **2006**
    
    **2005****Increase
      (Decrease)**
    
    ***(In
      millions)***Fuel
    
    $
    (2
    )
    $
    8Purchased
      power costs
    
    
    72
    
    
    (16
    )Nuclear
      operating costs
    
    
    1
    
    
    13Other
      operating costs
    
    
    (2
    )
    
    16Provision for
      depreciation
    
    
    -
    
    
    5Amortization
      of regulatory assets
    
    
    (46
    )
    
    17Deferral of
      new regulatory assets
    
    
    4
    
    
    (20
    )General
      taxes
    
    
    -
    
    
    3**Net
      increase in expenses**
    
    $
    27
    
    $
    26




Higher purchased
power costs in 2006 compared to 2005 primarily reflected an increase in KWH
purchased to meet the higher retail generation sales requirements and higher
unit prices under our power supply
agreement with FES (see Outlook - Regulatory Matters) .





Lower amortization
of regulatory assets in 2006 reflected the completion of generation-related
transition cost recovery under our transition plan, partially offset by the
amortization of deferred MISO costs that are being recovered in 2006. The
decrease in deferrals of new regulatory assets in 2006 primarily resulted from
the termination of shopping incentive deferrals in 2006 ($37 million) and lower
MISO transmission cost deferrals ($5 million), partially offset by deferred
distribution costs ($24 million) and incremental fuel costs ($16 million) that
began in 2006 under the RCP. The deferral of
interest on the unamortized shopping incentive balances continues under the
RCP.





6








Higher fuel costs in
2005 compared to 2004 resulted principally from increased fossil generation at
the Mansfield Plant. Purchased power costs decreased in 2005, compared with
2004, due to a 4.1% decrease in unit costs and a 1.1% decrease in KWH purchased.
Increased nuclear operating costs in 2005 were due to expenses associated with
the 74-day refueling outage at the Perry Plant and the 25-day refueling outage
at Beaver Valley Unit 2 in 2005 - there were no refueling outages in 2004.
Other operating costs increased in 2005, compared to 2004, primarily due to the
MISO Day 2 expenses that began April 1, 2005, partially offset by
lower vegetation management expenses and employee benefit costs.




Depreciation charges increased by $5 million in 2005 compared to 2004
primarily due to property additions and the amortization of leasehold
improvements. These increases were partially offset by lower depreciation on
electric plant as a result of the non-nuclear generation asset transfer on
October 24, 2005 and the effect of revised service life assumptions for
fossil-fired generating plants (for the 2005 period prior to the asset
transfer).





The increase in
charges for amortization of regulatory assets in 2005 compared to 2004 reflected
an increase in transition cost amortization. The higher deferrals of new
regulatory assets in 2005 compared to 2004 were primarily due to shopping
incentives ($4 million) and related interest ($3 million) in 2005 and
the deferral of $12 million of MISO expenses and related interest that
began in the second quarter of 2005.







*Other Income*





Excluding the asset
transfer effects shown above, other income decreased by $18 million primarily
because of higher interest expense on borrowings from associated companies and
fixed-rate securities and unamortized debt expense associated with the
redemption of pollution control notes in 2006.





Interest expense
decreased by $12 million in 2005 compared to 2004, reflecting redemptions and
refinancing activity. In 2005, we refinanced $45 million of pollution control
notes. An additional $91 million of pollution control notes were refinanced by
NGC as part of the nuclear generation asset transfer.





*Income
Taxes*





Excluding the
effects of the generation asset transfer, income taxes decreased $24 million in
2006 primarily due to the absence of approximately $18 million of income tax
charges from the implementation of Ohio tax legislation changes in the second
quarter of 2005.





Income taxes
increased $22 million in 2005 primarily due to Ohio deferred tax adjustments and
an increase in taxable income. On June 30, 2005, tax legislation was
enacted in the State of Ohio that created a new CAT tax, which is based on
qualifying "taxable gross receipts" and does not consider any expenses or costs
incurred to generate such receipts, except for items such as cash discounts,
returns and allowances, and bad debts. The CAT tax was effective July 1,
2005, and replaced the Ohio income-based franchise tax and the Ohio personal
property tax. The CAT tax is phased-in while the current income-based franchise
tax is phased-out over a five-year period at a rate of 20% annually, beginning
with the year ended 2005, and the personal property tax is phased-out over a
four-year period at a rate of approximately 25% annually, beginning with the
year ended 2005. During the phase-out period, the Ohio income-based franchise
tax will be computed consistent with the prior tax law, except that the tax
liability as computed was or will be multiplied by 80% in 2005; 60% in 2006; 40%
in 2007 and 20% in 2008, therefore eliminating the current income-based
franchise tax over a five-year period. As a result of the new tax structure, all
net deferred tax benefits that were not expected to reverse during the five-year
phase-in period were written-off as of June 30, 2005. The impact on income
taxes associated with the required adjustment to net deferred taxes for 2005 was
an additional tax expense of approximately $18 million, which was partially
offset by the initial phase-out of the Ohio income-based franchise tax, which
reduced income taxes by approximately $1 million in 2005.





*Preferred Stock
Dividend Requirements*





Higher
preferred stock dividend requirements in 2006 compared to 2005 were due to
$5 million of premiums paid in connection with the optional redemption of
preferred stock. In 2006 and 2005, we redeemed $96 million and
$30 million of preferred stock, respectively.





**Capital
Resources and Liquidity**





Our cash
requirements in 2006 for operating expenses and construction expenditures were
met with a combination of cash from operations, funds from the capital markets
and short-term credit arrangements. During 2007, we expect to meet our
contractual obligations primarily with cash from operations. Borrowing capacity
under our credit facilities is available to manage our working capital
requirements. In subsequent years, we expect to use a combination of cash from
operations and funds from the capital markets.





7











*Changes in Cash
Position*





As of
December 31, 2006, we had $22,000 of cash and cash equivalents, compared
with $15,000 as of December 31, 2005. The major changes in these balances are
summarized below.





*Cash Flows From
Operating Activities*





Net cash provided
from operating activities was $149 million in 2006, $156 million in
2005 and $183 million in 2004, summarized as follows:





**Operating
      Cash Flows**
    
    **2006**
    
    **2005**
    
    **2004*****(In
      millions)***Net
      income
    
    $
    99
    
    $
    76
    
    $
    86Net non-cash
      charges (credits)
    
    
    (1
    )
    
    135
    
    
    154Pension trust
      contribution*
    
    
    3
    
    
    (14
    )
    
    (8
    )Working
      capital and other
    
    
    48
    
    
    (41
    )
    
    (49
    )Net cash
      provided from operating activities
    
    $
    149
    
    $
    156
    
    $
    183





*
    Pension trust
      contributions in 2005 and 2004 are net of $6 million and $5 million of
      related current year cash income tax benefits, respectively. The $3
      million cash inflow in 2006 represents reduced income taxes paid in 2006
      relating to a January 2007 pension
contribution.





Net cash provided
from operating activities decreased $7 million in 2006 from 2005 as a
result of a $136 million decrease in net non-cash
charges, partially offset by a $23 million increase in net income, a $3
million tax benefit in 2006 relating to a January 2007 pension contribution, the
absence in 2006 of the pension trust contribution in 2005, and an
$89 million increase from changes in working capital and other. The changes
in net income and non-cash charges are described above under "Results of
Operations." The increase in cash provided from working capital was primarily
due to an $85 million decrease in cash outflows for accounts payable.





Net cash provided
from operating activities decreased $27 million in 2005 from 2004 as a
result of a $10 million decrease in net income, a $19 million decrease in
net non-cash charges (see "Results of Operations") and a $6 million
increase in after-tax voluntary pension trust contributions, partially offset by
an $8 million increase from changes in working capital and other. The
increase in cash provided from working capital and other was primarily due to
$38 million of funds received in 2005 for prepaid electric service (under
the three-year Energy for Education Program with the Ohio Schools Council),
partially offset by increased cash outflows for accounts payable of
$22 million.





*Cash Flows From
Financing Activities*





In 2006, 2005 and
2004, net cash used for financing activities of $248 million, $211 million
and $94 million, respectively, primarily reflected the new issues and
redemptions shown below:





**Securities
      Issued or Redeemed**
    
    **2006**
    
    **2005**
    
    **2004*****(In
      millions)******New
      Issues:***Unsecured Notes
    
    $
    297
    
    $
    -
    
    $
    -Pollution
      Control Notes
    
    
    -
    
    
    45
    
    
    104$
    297
    
    $
    45
    
    $
    104***Redemptions:***Common Stock
    
    $
    225
    
    $
    -
    
    $
    -Preferred
      Stock
    
    
    96
    
    
    30
    
    
    -Pollution
      Control Notes
    
    
    203
    
    
    136
    
    
    -Secured
      Notes
    
    
    -
    
    
    -
    
    
    261Other,
      principally redemption premiums
    
    
    5
    
    
    3
    
    
    1$
    529
    
    $
    169
    
    $
    262Short-term
      borrowings (repayments), net
    
    $
    63
    
    $
    (9
    )
    $
    74








8








Net cash used for
financing activities increased $37 million in 2006 from 2005, primarily
from a $36 million net increase in securities redemptions as shown above.
Net cash used for financing activities increased $117 million in 2005 from
2004. The increase primarily resulted from a net increase of $49 million of
net securities redemptions shown above and a $70 million increase in common
stock dividends to FirstEnergy in 2005.





We had
$101 million of cash and temporary investments (which include short-term
notes receivable from associated companies) and approximately $154 million
of short-term indebtedness as of December 31, 2006. We have authorization
from the PUCO to incur short-term debt of up to $500 million through the
bank facility and the utility money pool described below.





As of
December 31, 2006, we had the capability to issue $786 million of
additional FMB on the basis of property additions and retired bonds under the
terms of our mortgage indenture. Our issuance of FMB is also subject to a
provision of our senior note indenture 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) (i) supporting
pollution control notes or similar obligations, or (ii) as an extension, renewal
or replacement of previously outstanding secured debt. In addition, this
provision would permit us to incur additional secured debt not otherwise
permitted by a specified exception of up to $125 million. As a result of
our redeeming all remaining outstanding preferred stock in December 2006, our
applicable earnings coverage test is inoperative. In the event that we would
issue preferred stock in the future, the applicable earnings coverage test will
govern the amount of additional preferred stock that we may issue.





On August 24, 2006,
we, FirstEnergy, OE, Penn, CEI, JCP&L, Met-Ed, Penelec, FES and ATSI, as
Borrowers, entered into a new $2.75 billion five-year revolving credit
facility which replaced the prior $2 billion credit facility. Subject to specified
conditions, FirstEnergy may request an increase in the total commitments
available under the new facility up to a maximum of $3.25 billion. Commitments
under the new facility are available until August 24, 2011, unless the
lenders agree, at the request of the Borrowers, to two 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 sublimit,
as well as applicable regulatory and other limitations. Our borrowing limit
under the facility is $250 million subject to applicable regulatory
approval.





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 sublimit.





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 December 31, 2006, our debt to total
capitalization, as defined under the revolving credit facility, was
53%.





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





We have the ability to borrow from our regulated affiliates and FirstEnergy to
meet our short-term working capital requirements. FESC administers this money
pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries.
Companies receiving a loan under the money pool agreements must repay the
principal, 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
the pool and is based on the average cost of funds available through the pool.
The average interest rate for borrowings in 2006 was 5.22%.




Our access to
capital markets and costs of financing are dependent on the ratings of our
securities and the securities of FirstEnergy. The following table shows
securities ratings as of February 2, 2007. The ratings outlook from S&P
on all securities is stable. The ratings outlook from Moody's and Fitch on all
securities is positive.





**Ratings
      of Securities**
    
    **Securities**
    
    **S&P**
    
    **Moody's**
    
    **Fitch****FirstEnergy**
    
    Senior
      unsecured
    
    BBB-
    
    Baa3
    
    BBB**TE**
    
    Senior
      secured
    
    BBB
    
    Baa2
    
    BBBSenior
      unsecured
    
    BBB-
    
    Baa3
    
    BBB-








9








On
January 20, 2006, we redeemed all
1.2 million of our outstanding shares of Adjustable Rate Series B preferred
stock at $25.00 per share, plus accrued dividends to the date of
redemption.





On November 18,
2006, we issued $300 million of 6.15% senior unsecured notes due 2037. The
majority of the proceeds from this offering were used to repurchase $225 million
of our common stock from FirstEnergy. The remainder of the proceeds was used to
redeem $66 million of our preferred stock in December 2006.





In April and
December of 2006, pollution control notes totaling $203 million that were
formerly our obligations were refinanced and became obligations of FGCO and NGC.
The proceeds from the refinancings were used to repay a portion of our
associated company notes receivable from FGCO and NGC. Approximately
$59 million of remaining pollution control notes are subject to
transfer.





*Cash Flows From
Investing Activities*





Net cash provided
from investing activities increased to $99 million in 2006 from $55 million
in 2005. This change was primarily due to reductions of $28 million in net
activity for the nuclear decommissioning trust funds and $11 million in property
additions, both due to the generation asset transfers in the fourth quarter of
2005, and a net increase of $7 million from loan activity with associated
companies.





Net cash provided
from investing activities increased to $55 million in 2005 from a net use
of cash for investing activities of $91 million in 2004. This change was
primarily due to increased loan activity with associated companies. The
$552 million increase in collection of long-term notes receivable in 2005
included $429 million from NGC and $123 million from FGCO. The $123
million received from FGCO related to a balloon payment received in May 2005 for
the gas-fired combustion turbines sold in 2001. This increase in collection from
associated companies was partially offset by $409 million in loan payments to
the money pool, compared to $7 million in loan payments received from associated
companies in 2004.




Our capital spending for the period 2007-2011 is expected to be nearly
$325 million, of which approximately $64 million applies to 2007. The
capital spending is primarily for property additions supporting the distribution
of electricity. In addition, there is capital spending for the leasehold
interests in certain generating plants retained after the generation asset
transfers.





**Contractual
Obligations**





As of
December 31, 2006 , our estimated cash
payments under existing contractual obligations that we consider firm
obligations were as follows:





**2008-**
    
    **2010-****Contractual
      Obligations**
    
    **Total**
    
    **2007**
    
    **2009**
    
    **2011**
    
    **Thereafter*****(In
      millions)***Long-term debt(1)
    
    $
    389
    
    $
    30
    
    $
    -
    
    $
    -
    
    $
    359Short-term
      borrowings
    
    
    154
    
    
    154
    
    
    -
    
    
    -
    
    
    -Interest on
      long-term debt
    
    
    627
    
    
    23
    
    
    42
    
    
    42
    
    
    520Operating
      leases(2)
    
    
    781
    
    
    79
    
    
    149
    
    
    142
    
    
    411Pension
      funding(3)
    
    
    8
    
    
    8
    
    
    -
    
    
    -
    
    
    -Purchases(4)
    
    
    438
    
    
    35
    
    
    107
    
    
    119
    
    
    177Total
    
    $
    2,397
    
    $
    329
    
    $
    298
    
    $
    303
    
    $
    1,467





(1)
    Amounts
      reflected do not include interest on long-term
  debt.


(2)
    Operating
      lease payments are net of capital trust receipts of $250.8 million
      (see Note 5).


(3)
    We estimate
      that no further pension contributions will be required during the
      2008-2011 period to maintain our defined benefit pension plan's funding at
      a minimum required level as determined by government regulations. We are
      unable to estimate projected contributions beyond 2011. See Note 3 to the
      consolidated financial statements.


(4)
    Fuel and power
      purchases under contracts with fixed or minimum quantities and approximate
      timing.





10








**Off-Balance
Sheet Arrangements**





Obligations not
included on our Consolidated Balance Sheet primarily consist of sale and
leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley
Unit 2, which are
reflected in the operating lease payments above (see Note 5 - Leases). As
of December 31, 2006, the present value of these operating lease
commitments, net of trust investments, total $503 million.





**Interest
Rate Risk**





Our exposure to
fluctuations in market interest rates is reduced since a significant portion of
our debt has fixed interest rates. The table below presents principal amounts
and related weighted average interest rates by year of maturity for our
investment portfolio and debt obligations:





**Comparison
      of Carrying Value to Fair Value****There-**
    
    
    
    **Fair****Year
      of Maturity**
    
    **2007**
    
    **2008**
    
    **2009**
    
    **2010**
    
    **2011**
    
    **after**
    
    **Total**
    
    **Value*****(Dollars
      in millions)***AssetsInvestments
      Other Than Cash
      and Cash
      Equivalents-Fixed
      Income
    
    $
    9
    
    $
    15
    
    $
    12
    
    $
    19
    
    $
    21
    
    $
    291
    
    $
    367
    
    $
    395Average
      interest rate
    
    
    7.7
    %
    
    7.7
    %
    
    7.7
    %
    
    7.7
    %
    
    7.7
    %
    
    6.1
    %
    
    6.4
    %LiabilitiesLong-term
      Debt:Fixed
      rate
    
    $
    30
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    314
    
    $
    344
    
    $
    343Average
      interest rate
    
    
    7.1
    %
    
    
    
    
    
    
    
    
    
    
    
    
    
    6.1
    %
    
    6.2
    %Variable
      rate
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    45
    
    $
    45
    
    $
    45Average
      interest rate
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3.8
    %
    
    3.8
    %Short-term
      Borrowings
    
    $
    154
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    154
    
    $
    154Average
      interest rate
    
    
    5.4
    %
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5.4
    %





**Outlook**





Our industry
continues to transition to a more competitive environment and all of our
customers can select alternative energy suppliers. We continue to deliver power
to residential homes and businesses through our existing distribution system,
which remains regulated. Customer rates have been restructured into separate
components to support customer choice. We have a continuing responsibility to
provide power to those customers not choosing to receive power from an
alternative energy supplier subject to certain limits.





*Regulatory
Matters*





Regulatory assets
are costs which have been authorized by the PUCO and the FERC 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. All regulatory assets are
expected to be recovered under the provisions of our transition plan.





11








On October 21, 2003,
the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the
Ohio Companies accepted the RSP as modified and approved by the PUCO in an
August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to
establish generation service rates beginning January 1, 2006, in response to the
PUCO's concerns about price and supply uncertainty following the end of the Ohio
Companies' transition plan market development period. On May 3, 2006, the
Supreme Court of Ohio issued an opinion affirming the PUCO's order in all
respects, except it remanded back to the PUCO the matter of ensuring the
availability of sufficient means for customer participation in the marketplace.
The RSP contained a provision that permitted the Ohio Companies to withdraw and
terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio,
rejected all or part of the RSP. In such event, the Ohio Companies have 30 days
from the final order or decision to provide notice of termination. On July 20,
2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding
on Remand. In their Request, the Ohio Companies provided notice of termination
to those provisions of the RSP subject to termination, subject to being
withdrawn, and also set forth a framework for addressing the Supreme Court of
Ohio's findings on customer participation. If the PUCO approves a resolution to
the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio
Companies, the Ohio Companies' termination will be withdrawn and considered to
be null and void. On July 26, 2006, the PUCO issued an Entry directing the Ohio
Companies to file a plan in a new docket to address the Court's concern. The
Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial
comments were filed on January 12, 2007 and reply comments were filed on
January 29 , 2007.
I n
their reply comments the Ohio Companies described the highlights of a new tariff
offering they would be willing to make available to customers that would allow
customers to purchase renewable energy certificates associated with a renewable
generation source, subject to PUCO approval. No further
proceedings are scheduled at this time.





The Ohio Companies
filed an application and stipulation with the PUCO on September 9, 2005
seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the
Ohio Companies filed a supplemental stipulation with the PUCO, which constituted
an additional component of the RCP filed on September 9, 2005. Major provisions
of the RCP include:





Maintaining
      the existing level of our base distribution rates through December 31,
      2008;Deferring and
      capitalizing for future recovery (over a 25-year period) with carrying
      charges certain distribution costs to be incurred during the period
      January 1, 2006 through December 31, 2008, not to exceed
      $150 million in each of the three years;Adjusting the
      RTC and extended RTC recovery periods and rate levels so that full
      recovery of our authorized costs will occur as of December 31,
      2008;Reducing our
      deferred shopping incentive balances as of January 1, 2006 by up to
      $45 million by accelerating the application of our accumulated cost of
      removal regulatory liability; andRecovering
      increased fuel costs (compared to a 2002 baseline) of up to
      $75 million, $77 million, and $79 million, in 2006, 2007,
      and 2008, respectively, from all of OE's and our distribution and
      transmission customers through a fuel recovery mechanism. We may defer and
      capitalize (for recovery over a 25-year period) increased fuel costs above
      the amount collected through the fuel recovery
  mechanism.





The following table
provides our estimated net amortization of regulatory transition costs and
deferred shopping incentives (including associated carrying charges) for the
remaining years of the RCP:





**Period**
    
    **Amortization*****(In
      millions)***2007
    
    $
    932008
    
    
    119**Total
      Amortization**
    
    **$**
    212








12








On January 4, 2006,
the PUCO approved, with modifications, the Ohio Companies' RCP to supplement the
RSP to provide customers with more certain rate levels than otherwise available
under the RSP during the plan period. On January 10,
2006, the Ohio Companies filed a Motion for Clarification seeking clarity on a
number of issues. On January 25, 2006, the PUCO issued an Entry on
Rehearing granting in part, and denying in part, the Ohio Companies' previous
requests and clarifying issues referred to above. The PUCO granted the Ohio
Companies' requests to:





Recognize fuel
      and distribution deferrals commencing January 1,
  2006;Recognize
      distribution deferrals on a monthly basis prior to review by the PUCO
      Staff;Clarify that
      the types of distribution expenditures included in the Supplemental
      Stipulation may be deferred; andClarify that
      distribution expenditures do not have to be "accelerated" in order to be
      deferred.





The PUCO approved
the Ohio Companies' methodology for determining distribution deferral amounts,
but denied the Motion in that the PUCO Staff must verify the level of
distribution expenditures contained in current rates, as opposed to simply
accepting the amounts contained in the Ohio Companies' Motion. On
February 3, 2006, several other parties filed applications for rehearing,
which the PUCO denied on March 1, 2006. Two of these parties subsequently filed
notices of appeal with the Supreme Court of Ohio. The Ohio Supreme Court
scheduled this case for oral argument on February 27, 2007. On January 31, 2007,
the Ohio Companies filed a stipulation which, among other matters and subject to
PUCO approval, affirmed that the supplemental stipulation in the RCP would be
implemented. This stipulation was approved by the PUCO on February 14,
2007.





On December 30,
2004, the Ohio Companies filed with the PUCO two applications related to the
recovery of transmission and ancillary service related costs. The first
application sought recovery of these costs beginning January 1, 2006. The
Ohio Companies requested that these costs be recovered through a rider that
would be effective on January 1, 2006 and adjusted each July 1
thereafter. The parties reached a settlement agreement that was approved by the
PUCO on August 31, 2005. The incremental transmission and ancillary service
revenues recovered from January 1 through June 30, 2006 were
approximately $54 million. That amount included the recovery of a portion
of the 2005 deferred MISO expenses as described below. On April 27, 2006,
the Ohio Companies filed the annual update rider to determine revenues
($124 million) from July 2006 through June 2007. The filed rider went into
effect on July 1, 2006.





The second
application sought authority to defer costs associated with transmission and
ancillary service related costs incurred during the period October 1, 2003
through December 31, 2005. On May 18, 2005, the PUCO granted the
accounting authority for the Ohio Companies to defer incremental transmission
and ancillary service-related charges incurred as a participant in MISO, but
only for those costs incurred during the period December 30, 2004 through
December 31, 2005. Permission to defer costs incurred prior to
December 30, 2004 was denied. The PUCO also authorized the Ohio Companies
to accrue carrying charges on the deferred balances. On August 31, 2005,
the OCC appealed the PUCO's decision. On January 20,
2006, the OCC sought rehearing of the PUCO's approval of the recovery of
deferred costs through the rider during the period January 1, 2006 through
June 30, 2006. The PUCO denied the OCC's application on February 6,
2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio
Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate
this appeal with the deferral appeals discussed above and to postpone oral
arguments in the deferral appeal until after all briefs are filed in this most
recent appeal of the rider recovery mechanism. On March 20, 2006,
the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of the
Ohio Companies' case with a similar case involving Dayton Power & Light
Company. Oral arguments were heard on May 10, 2006. On November 29,
2006, the Ohio Supreme Court issued its opinion upholding the PUCO's
determination that the Ohio Companies may defer transmission and ancillary
service related costs incurred on and after December 30, 2004. The Ohio
Supreme Court also determined that the PUCO erred when it denied the OCC
intervention, but further ruled that such error did not prejudice OCC and,
therefore, the Ohio Supreme Court did not reverse or remand the PUCO on this
ground. The Ohio Supreme Court also determined that the OCC's appeal was not
premature. No party filed a motion for reconsideration with the Ohio Supreme
Court.





13








On November 1, 2005,
FES filed a power sales agreement for approval with the FERC. The power sales
agreement provided for FES to provide the PLR requirements of the Ohio Companies
at a price equal to the retail generation rates approved by the PUCO for a
period of three years beginning January 1, 2006. The Ohio Companies will be
relieved of their obligation to obtain PLR power requirements from FES if the
Ohio CBP results in a lower price for retail customers.





On December 29,
2005, the FERC issued an order setting the power sales agreement for hearing.
The order criticized the Ohio CBP, and required FES to submit additional
evidence in support of the reasonableness of the prices charged in the power
sales agreement. On July 14, 2006, the Chief Judge granted the joint motion of
FES and the Trial Staff to appoint a settlement judge in this proceeding and the
procedural schedule was suspended pending settlement discussions among the
parties. A settlement conference was held on September 5, 2006. FES, the Ohio
Companies and the PUCO, along with other
parties, reached an agreement to settle the case. The settlement was filed with
the FERC on October 17, 2006, and was unopposed by the remaining parties,
including the FERC Trial Staff. This settlement was accepted by the FERC on
December 8, 2006.





The terms of the
settlement provide for modification of the power supply agreement with FES.
Under the power supply agreement, separate rates are established for the Ohio
Companies' PLR requirements; special retail contract requirements, wholesale
contract requirements, and interruptible buy-through retail load requirements.
For their PLR and special retail contract requirements, the Ohio Companies will
pay FES no more than the lower of (i) the sum of the retail generation charge,
the rate stabilization charge, the fuel recovery mechanism charge, and FES'
actual incremental fuel costs for such sales; or (ii) the wholesale price cap.
Different wholesale price caps are imposed for PLR sales, special retail
contracts, and wholesale contracts. The wholesale price for interruptible
buy-through retail load requirements is limited to the actual spot price of
power obtained by FES to provide this power. FES billed the Ohio Companies for
the additional amount payable to FES for incremental fuel costs on power
supplied during 2006. The total power supply cost billed by FES was lower in
each case than the wholesale price caps specified in the settlement accepted by
the FERC.





On February 15,
2007, MISO filed documents with the FERC to establish a market-based,
competitive ancillary services market. MISO contends that the filing will
integrate operating reserves into MISO's existing day-ahead and real-time
settlements process, incorporate opportunity costs into these markets, address
scarcity pricing through the implementation of a demand curve methodology,
foster demand response in the provision of operating reserves, and provide for
various efficiencies and optimization with regard to generation dispatch. The
filing also proposes amendments to existing documents to provide for the
transfer of balancing functions from existing local balancing authorities to
MISO. MISO will then carry out this reliability function as the NERC-certified
balancing authority for the MISO region. MISO is targeting implementation for
the second or third quarter of 2008. The FERC has established March 23, 2007, as
the date for interested parties to submit comments addressing the filing. The
filing has not yet been fully evaluated to assess its impact on our operations.





On February 16,
2007, the FERC issued a final rule that revises its decade-old open access
transmission regulations and policies. The FERC explained that the final rule is
intended to strengthen non-discriminatory access to the transmission grid,
facilitate FERC enforcement, and provide for a more open and coordinated
transmission planning process. The final rule will not be effective until 60
days after publication in the Federal Register. The final rule has not yet been
fully evaluated to assess its impact on our operations.





See Note 8 to
the consolidated financial statements for further details and a complete
discussion of regulatory matters in Ohio.





*Environmental
Matters*





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





*Regulation of
Hazardous Waste-*





We have been named a
PRP 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 are liable on a joint and several basis.
Therefore, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of December 31, 2006, based
on estimates of the total costs of cleanup, our proportionate responsibility for
such costs and the financial ability of other unaffiliated entities to pay.
Included in Other Noncurrent Liabilities are accrued liabilities aggregating
approximately $2.7 million as of December 31, 2006.








14





See Note 12(B)
to the consolidated financial statements for further details and a complete
discussion of environmental matters.





*Other Legal
Proceedings*





*Power Outage and
Related Litigation-*





On August 14,
2003, various states and parts of southern Canada experienced widespread power
outages. The outages affected approximately 1.4 million customers in
FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force's
final report in April 2004 on the outages concluded, among other things, that
the problems leading to the outages began in FirstEnergy's Ohio service area. Specifically, the
final report concluded, among other things, that the initiation of the
August 14, 2003 power outages resulted from an alleged failure of both
FirstEnergy and ECAR to assess and understand perceived inadequacies within
FirstEnergy's system; inadequate situational awareness of the developing
conditions; and a perceived failure to adequately manage tree growth in certain
transmission rights of way. The Task Force also concluded that there was a
failure of the interconnected grid's reliability organizations (MISO and PJM) to
provide effective real-time diagnostic support. The final report is publicly
available through the Department of Energy's Web site (www.doe.gov). We believe
that the final report does not provide a complete and comprehensive picture of
the conditions that contributed to the August 14, 2003 power outages and
that it does not adequately address the underlying causes of the outages. We
remain convinced that the outages cannot be explained by events on any one
utility's system. The final report contained 46 "recommendations to prevent or
minimize the scope of future blackouts." Forty-five of those recommendations
related to broad industry or policy matters while one, including subparts,
related to activities the Task Force recommended be undertaken by FirstEnergy,
MISO, PJM, ECAR, and other parties to correct the causes of the August 14,
2003 power outages. FirstEnergy implemented several initiatives, both prior to
and since the August 14, 2003 power outages, which were independently
verified by NERC as complete in 2004 and were consistent with these and other
recommendations and collectively enhance the reliability of its electric system.
FirstEnergy's implementation of these recommendations in 2004 included
completion of the Task Force recommendations that were directed toward
FirstEnergy. 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.





FirstEnergy
companies also are defending five separate complaint cases before the PUCO
relating to the August 14, 2003 power outages. Two cases were originally
filed in Ohio State courts but were subsequently dismissed for lack of subject
matter jurisdiction and further appeals were unsuccessful. In these cases the
individual complainants "three in one case and four in the other"sought to
represent others as part of a class action. The PUCO dismissed the class
allegations, stating that its rules of practice do not provide for class action
complaints. Three other pending PUCO complaint cases were filed by various
insurance carriers either in their own name as subrogees or in the name of their
insured. In each of these three cases, the carrier seeks reimbursement from
various FirstEnergy companies (and, in one case, from PJM, MISO and American
Electric Power Company, Inc., as well) for claims paid to insureds for damages
allegedly arising as a result of the loss of power on August 14, 2003. The
listed insureds in these cases, in many instances, are not customers of any
FirstEnergy company. A sixth case involving the claim of a non-customer seeking
reimbursement for losses incurred when its store was burglarized on
August 14, 2003 was dismissed. On March 7,
2006, the PUCO issued a ruling, consolidating all of the pending outage cases
for hearing; limiting the litigation to service-related claims by customers of
the Ohio operating companies; dismissing FirstEnergy as a defendant; and ruling
that the U.S.-Canada Power System Outage Task Force Report was not admissible
into evidence. In response to a
motion for rehearing filed by one of the claimants, the PUCO ruled on April 26,
2006 that the insurance company claimants, as insurers, may prosecute their
claims in their name so long as they also identify the underlying insured
entities and the Ohio utilities that provide their service. The PUCO denied all
other motions for rehearing. The plaintiffs in each case have since filed
amended complaints and the named FirstEnergy companies have answered and also
have filed a motion to dismiss each action. On September 27, 2006, the PUCO
dismissed certain parties and claims and otherwise ordered the complaints to go
forward to hearing. The cases have been set for hearing on October 16,
2007.





On October 10, 2006,
various insurance carriers refiled a complaint in Cuyahoga County Common Pleas
Court seeking reimbursement for claims paid to numerous insureds who allegedly
suffered losses as a result of the August 14, 2003 outages. All of the insureds
appear to be non-customers. The plaintiff insurance companies are the same
claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and
Penn were served on October 27, 2006. On January 18, 2007, the Court
granted the Companies' motion to dismiss the case. It is unknown whether or not
the matter will be further appealed. No estimate of potential liability is
available for any of these cases.





We are vigorously
defending these actions, but cannot predict the outcome of any of these
proceedings or whether any further regulatory proceedings or legal actions may
be initiated against the Company. Although unable to predict the impact of these
proceedings, if FirstEnergy or its subsidiaries were ultimately determined to
have legal liability in connection with these proceedings, it could have a
material adverse effect on our financial condition, results of operations and
cash flows.








15





*Other Legal
Matters-*





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





On October 20,
2004, we were notified by the SEC that the previously disclosed informal inquiry
initiated by the SEC's Division of Enforcement in September 2003 relating to the
restatements in August 2003 of previously reported results by FirstEnergy and
the Ohio Companies, and the Davis-Besse extended outage, have become the subject
of a formal order of investigation. The SEC's formal order of investigation also
encompasses issues raised during the SEC's examination of FirstEnergy and the
Companies under the now repealed PUHCA. Concurrent with this notification, we
received a subpoena asking for background documents and documents related to the
restatements and Davis-Besse issues. On December 30, 2004, we received a
subpoena asking for documents relating to issues raised during the SEC's PUHCA
examination. On August 24, 2005, additional information was requested
regarding Davis-Besse-related disclosures, which has been provided. We have
cooperated fully with the informal inquiry and continue to do so with the formal
investigation.





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 our financial condition, results of operations
and cash flows.





See Note 12(C)
to the consolidated financial statements for further details and a complete
discussion of other legal proceedings.





**Critical
Accounting Policies**





We prepare our
consolidated financial statements in accordance with GAAP. Application of these
principles often requires a high degree of judgment, estimates and assumptions
that affect financial results. All of our assets are subject to their own
specific risks and uncertainties and are regularly reviewed for impairment. Our
more significant accounting policies are described below.





*Regulatory
Accounting*





We are subject to
regulation that sets the prices (rates) we are permitted to charge our customers
based on the costs that the regulatory agencies determine we are permitted to
recover. At times, regulators permit the future recovery through rates of costs
that would be currently charged to expense by an unregulated company. This
rate-making process results in the recording of regulatory assets based on
anticipated future cash inflows. We regularly review these assets to assess
their ultimate recoverability within the approved regulatory guidelines.
Impairment risk associated with these assets relates to potentially adverse
legislative, judicial or regulatory actions in the future.





*Revenue
Recognition*





We follow the
accrual method of accounting for revenues, recognizing revenue for electricity
that has been delivered to customers but not yet billed through the end of the
accounting period. The determination of electricity sales to individual
customers is based on meter readings, which occur on a systematic basis
throughout the month. At the end of each month, electricity delivered to
customers since the last meter reading is estimated and a corresponding accrual
for unbilled sales is recognized. The determination of unbilled sales requires
management to make estimates regarding electricity available for retail load,
transmission and distribution line losses, demand by customer class,
weather-related impacts, prices in effect for each customer class and
electricity provided by alternative suppliers.





*Pension and
Other Postretirement Benefits Accounting*





Our reported costs
of providing non-contributory qualified and non-qualified defined pension
benefits and postemployment benefits other than pensions are dependent upon
numerous factors resulting from actual plan experience and certain assumptions.





Pension and OPEB
costs are affected by employee demographics (including age, compensation levels,
and employment periods), the level of contributions we make to the plans, and
earnings on plan assets. Such factors may be further affected by business
combinations, which impact employee demographics, plan experience and other
factors. Pension and OPEB costs are also affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.





16








In accordance with
SFAS 87, changes in pension and OPEB obligations associated with these
factors may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of
changes due to the long-term nature of pension and OPEB obligations and the
varying market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.





As of December 31,
2006, we adopted SFAS 158 which requires a net liability or asset to be
recognized for the overfunded or underfunded status of our defined benefit
pension and other postretirement benefit plans on the balance sheet and
recognize changes in funded status in the year in which the changes occur
through OCI. We will continue to apply the provisions of SFAS 87 and SFAS 106 in
measuring plan assets and benefit obligations as of the balance sheet date and
in determining the amount of net periodic benefit cost. FirstLEnergy's
underfunded status as of December 31, 2006 is $637 million.





In selecting an
assumed discount rate, we consider currently available rates of return on
high-quality fixed income investments expected to be available during the period
to maturity of the pension and other postretirement benefit obligations. Due to
recent declines in corporate bond yields and interest rates in general, we
reduced the assumed discount rate as of December 31, 2006 is 6.00% from
5.75% and 6.00% used as of December 31, 2005 and 2004, respectively.





FirstEnergy's assumed rate of
return on pension plan assets considers historical market returns and economic
forecasts for the types of investments held by our pension trusts. In 2006, 2005
and 2004, the FirstEnergy plan assets
actually earned $567 million or 12.5%, $325 million or 8.2% and $415 million or
11.1% ,
respectively. FirstEnergy's pension costs in 2006, 2005 and 2004 were computed
using an assumed 9.0% rate of return on plan assets which generated
$396 million, $345 million and $286 million expected returns on plan
assets, respectively. The 2006 expected return was based upon projections of
future returns and FirstEnergy's pension trust investment allocation of
approximately 64% equities, 29% bonds, 5% real estate, 1% private equities and
1% cash. The gains or losses generated as a result of the difference between
expected and actual returns on plan assets are deferred and amortized and will
increase or decrease future net periodic pension expense,
respectively.





FirstEnergy's
pension and OPEB expense was $94 million in 2006 and $131 million in 2005. On
January 2, 2007 FirstEnergy made a $300 million voluntary contribution to its
pension plan (our share was $8 million). In addition during 2006, FirstEnergy
amended its OPEB plan effective in 2008 to cap its monthly contribution for many
of the retirees and their spouses receiving subsidized health care coverage. As
a result of the $300 million voluntary contribution and the amendment to the
OPEB plan effective in 2008, we expect the pension and OPEB costs for 2007 to be
a credit of $94 million for FirstEnergy.





Health care cost
trends have significantly increased and will affect future OPEB costs. The 2006
and 2005 composite health care trend rate assumptions are approximately 9-11%,
gradually decreasing to 5% in later years. In determining our trend rate
assumptions, we included the specific provisions of our health care plans, the
demographics and utilization rates of plan participants, actual cost increases
experienced in its health care plans, and projections of future medical trend
rates. The effect on TE's portion of pension and OPEB costs from changes in key
assumptions are as follows:





**Increase
      in Costs from Adverse Changes in Key Assumptions****Assumption**
    
    **Adverse
      Change**
    
    **Pension**
    
    **OPEB**
    
    **Total*****(In
      millions)***Discount
      rate
    
    
    Decrease by
      0.25
    %
    $
    0.4
    
    $
    0.1
    
    $
    0.5Long-term
      return on assets
    
    
    Decrease by
      0.25
    %
    $
    0.4
    
    $
    -
    
    $
    0.4Health care
      trend rate
    
    
    Increase by
      1
    %
    
    na
    
    $
    0.3
    
    $
    0.3






*Ohio Transition
Cost Amortization*





In connection with
our Ohio transition plan, the PUCO determined allowable transition costs based
on amounts recorded on our regulatory books. These costs exceeded those deferred
or capitalized on our balance sheet prepared under GAAP since they included
certain costs which have not yet been incurred or that were recognized on the
regulatory financial statements (fair value purchase accounting adjustments). We
use an effective interest method for amortizing transition costs, often referred
to as a "mortgage-style" amortization. The interest rate under this method is
equal to the rate of return authorized by the PUCO in our RSP. In computing the
transition cost amortization, we include only the portion of the transition
revenues associated with transition costs included on the balance sheet prepared
under GAAP. Revenues collected for the off-balance sheet costs and the return
associated with these costs are recognized as income when received. Amortization
of deferred customer shopping incentives and interest costs will be equal to the
related revenue recovery that is recognized under the RCP (see Note 2
(A)).





17





*Long-Lived
Assets*





In accordance with
SFAS 144, we periodically evaluate our long-lived assets to determine
whether conditions exist that would indicate that the carrying value of an asset
might not be fully recoverable. The accounting standard requires that if the sum
of future cash flows (undiscounted) expected to result from an asset is less
than the carrying value of the asset, an asset impairment must be recognized in
the financial statements. If impairment has occurred, we recognize a loss -
calculated as the difference between the carrying value and the estimated fair
value of the asset (discounted future net cash flows).





The calculation of future cash flows is based on assumptions, estimates and
judgement about future events. The aggregate amount of cash flows determines
whether an impairment is indicated. The timing of the cash flows is critical in
determining the amount of the impairment. **





*Goodwill*





In a business
combination, the excess of the purchase price over the estimated fair values of
the assets acquired and liabilities assumed is recognized as goodwill. Based on
the guidance provided by SFAS 142, we evaluate our goodwill for impairment
at least annually and would make such an evaluation more frequently if
indicators of impairment should 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 an impairment
were indicated, we recognize a loss - calculated as the difference between the
implied fair value of our goodwill and the carrying value of the goodwill. Our
annual review was completed in the third quarter of 2006, with no impairment of
goodwill indicated. The forecasts used in our evaluation of goodwill reflect
operations consistent with our general business assumptions. Unanticipated
changes in those assumptions could have a significant effect on our future
evaluations of goodwill. In the year ended December 31, 2005, we adjusted
goodwill to reverse pre-merger tax accruals due to the final resolution of tax
contingencies related to the Centerior acquisition. As of December 31,
2006, we had approximately $501 million of goodwill.





*Asset Retirement
Obligations*





In accordance with
SFAS 143 and FIN 47, we recognize an ARO for the future
decommissioning of our nuclear power plants and future remediation of other
environmental liabilities associated with all of our long-lived assets. The ARO
liability represents an estimate of the fair value of our current obligation
related to nuclear decommissioning and the retirement or remediation of
environmental liabilities of other assets. A fair value measurement inherently
involves uncertainty in the amount and timing of settlement of the liability. We
use an expected cash flow approach to measure the fair value of the nuclear
decommissioning and environmental remediation ARO. This approach applies
probability weighting to discounted future cash flow scenarios that reflect a
range of possible outcomes. The scenarios consider settlement of the ARO at the
expiration of the nuclear power plants' current license, settlement based on an
extended license term and expected remediation dates.





**New
Accounting Standards and Interpretations**





*SFAS 159 -
      The Fair Value Option for Financial Assets and Financial Liabilities -
      Including an amendment of FASB Statement No.
  115*





In February 2007,
FASB issued SFAS 159, which provides companies with an option to report selected
financial assets and liabilities at fair value. The Standard requires companies
to provide additional information that will help investors and other users of
financial statements to more easily understand the effect of the company's
choice to use fair value on its earnings. The Standard also requires companies
to display the fair value of those assets and liabilities for which the company
has chosen to use fair value on the face of the balance sheet. This guidance
does not eliminate disclosure requirements included in other accounting
standards, including requirements for disclosures about fair value measurements
included in SFAS 157, *Fair Value
Measurements,* and SFAS 107, *Disclosures
about Fair Value of Financial Instruments.* We are currently
evaluating the impact of this Statement on our financial
statements.




*SFAS 157 - "Fair
Value Measurements"*





In September 2006,
the FASB issued SFAS 157, that establishes how companies should measure fair
value when they are required to use a fair value measure for recognition or
disclosure purposes under GAAP. This Statement addresses the need for increased
consistency and comparability in fair value measurements and for expanded
disclosures about fair value measurements. The key changes to current practice
are: (1) the definition of fair value which focuses on an exit price rather than
entry price; (2) the methods used to measure fair value such as emphasis that
fair value is a market-based measurement, not an entity-specific measurement, as
well as the inclusion of an adjustment for risk, restrictions and credit
standing; and (3) the expanded disclosures about fair value measurements. This
Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years.
We are currently evaluating the impact of this Statement on its financial
statements.





18








*FIN 48 -
"Accounting for Uncertainty in Income Taxes - an interpretation of FASB
Statement No. 109"*





In June 2006, the
FASB issued FIN 48 which clarifies the accounting for uncertainty in income
taxes recognized in an enterprise's financial statements in accordance with FASB
Statement No. 109, "Accounting for Income Taxes." This interpretation prescribes
a recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken on a
tax return. This interpretation 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 will be a two-step process. The first step will determine if it
is more likely than not that a tax position will be sustained upon examination
and should therefore be recognized. The second step will measure a tax position
that meets the more likely than not recognition threshold to determine the
amount of benefit to recognize in the financial statements. This interpretation
is effective for fiscal years beginning after December 15, 2006. We do not
expect this Statement to have a material impact on our financial
statements.










19





**THE
      TOLEDO EDISON COMPANY****CONSOLIDATED
      STATEMENTS OF INCOME****For
      the Years Ended December 31,**
    
    **2006**
    
    **2005**
    
    **2004*****(In
      thousands)*****REVENUES
      (Note 2(H)):**Electric
      sales
    
    $
    899,930
    
    $
    1,011,239
    
    $
    979,954Excise tax
      collections
    
    
    28,071
    
    
    28,947
    
    
    28,158928,001
    
    
    1,040,186
    
    
    1,008,112**EXPENSES
      (Note 2(H)):**Fuel
    
    
    36,313
    
    
    58,897
    
    
    50,892Purchased
      power
    
    
    368,654
    
    
    296,720
    
    
    312,867Nuclear
      operating costs
    
    
    81,845
    
    
    181,410
    
    
    168,401Other
      operating costs
    
    
    166,403
    
    
    168,522
    
    
    152,879Provision for
      depreciation
    
    
    33,310
    
    
    62,486
    
    
    57,948Amortization
      of regulatory assets
    
    
    95,032
    
    
    141,343
    
    
    123,858Deferral of
      new regulatory assets
    
    
    (54,946
    )
    
    (58,566
    )
    
    (38,696
    )General
      taxes
    
    
    50,869
    
    
    57,108
    
    
    54,142Total
      expenses
    
    
    777,480
    
    
    907,920
    
    
    882,291**OPERATING
      INCOME**
    
    
    150,521
    
    
    132,266
    
    
    125,821**OTHER
      INCOME (EXPENSE) (Note 2(H)):**Investment
      income
    
    
    38,187
    
    
    49,440
    
    
    45,993Miscellaneous
      expense
    
    
    (7,379
    )
    
    (10,587
    )
    
    (3,438
    )Interest
      expense
    
    
    (23,179
    )
    
    (21,489
    )
    
    (33,439
    )Capitalized
      interest
    
    
    1,123
    
    
    465
    
    
    3,696Total other
      income
    
    
    8,752
    
    
    17,829
    
    
    12,812**INCOME
      BEFORE INCOME TAXES**
    
    
    159,273
    
    
    150,095
    
    
    138,633**INCOME
      TAXES**
    
    
    59,869
    
    
    73,931
    
    
    52,350**NET
      INCOME**
    
    
    99,404
    
    
    76,164
    
    
    86,283**PREFERRED
      STOCK DIVIDEND REQUIREMENTS**
    
    
    9,409
    
    
    7,795
    
    
    8,844**EARNINGS
      ON COMMON STOCK**
    
    $
    89,995
    
    $
    68,369
    
    $
    77,439The
      accompanying Notes to Consolidated Financial Statements are an integral
      part of these statements.
   20
  **THE
      TOLEDO EDISON COMPANY****CONSOLIDATED
      BALANCE SHEETS****As of
      December 31,**
    
    **2006**
    
    **2005*****(In
      thousands)*****ASSETS****CURRENT
      ASSETS:**Cash and cash
      equivalents
    
    $
    22
    
    $
    15Receivables-Customers
    
    
    772
    
    
    2,209Associated
      companies
    
    
    13,940
    
    
    16,311Other (less
      accumulated provision of $430,000 foruncollectible accounts in 2006)
    
    
    3,831
    
    
    6,410Notes
      receivable from associated companies
    
    
    100,545
    
    
    48,349Prepayments
      and other
    
    
    851
    
    
    1,059119,961
    
    
    74,353**UTILITY
      PLANT:**In
      service
    
    
    894,888
    
    
    824,677Less -
      Accumulated provision for depreciation
    
    
    394,225
    
    
    372,845500,663
    
    
    451,832Construction
      work in progress
    
    
    16,479
    
    
    33,920517,142
    
    
    485,752**OTHER
      PROPERTY AND INVESTMENTS:**Long-term
      notes receivable from associated companies
    
    
    128,858
    
    
    436,178Investment in
      lessor notes
    
    
    169,493
    
    
    178,798Nuclear plant
      decommissioning trusts
    
    
    61,094
    
    
    59,209Other
    
    
    1,871
    
    
    1,781361,316
    
    
    675,966**DEFERRED
      CHARGES AND OTHER ASSETS:**Goodwill
    
    
    500,576
    
    
    501,022Regulatory
      assets
    
    
    247,595
    
    
    287,095Prepaid
      pension costs (Note 3)
    
    
    -
    
    
    35,566Property
      taxes
    
    
    22,010
    
    
    18,047Other
    
    
    30,042
    
    
    24,164800,223
    
    
    865,894$
    1,798,642
    
    $
    2,101,965**LIABILITIES
      AND CAPITALIZATION****CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    $
    30,000
    
    $
    53,650Accounts
      payable-Associated
      companies
    
    
    84,884
    
    
    46,386Other
    
    
    4,021
    
    
    2,672Notes payable
      to associated companies
    
    
    153,567
    
    
    64,689Accrued
      taxes
    
    
    47,318
    
    
    49,344Lease market
      valuation liability
    
    
    24,600
    
    
    24,600Other
    
    
    37,551
    
    
    40,049381,941
    
    
    281,390**CAPITALIZATION**(See
      Statements of Capitalization)**:**Common
      stockholder's equity
    
    
    481,415
    
    
    863,426Preferred
      stock
    
    
    -
    
    
    96,000Long-term debt
    
    
    358,281
    
    
    237,753839,696
    
    
    1,197,179**NONCURRENT
      LIABILITIES:**Accumulated
      deferred income taxes
    
    
    161,024
    
    
    221,149Accumulated
      deferred investment tax credits
    
    
    11,014
    
    
    11,824Lease market
      valuation liability
    
    
    218,800
    
    
    243,400Retirement
      benefits
    
    
    77,902
    
    
    40,353Asset
      retirement obligations
    
    
    26,543
    
    
    24,836Deferred
      revenues - electric service programs
    
    
    23,546
    
    
    32,606Other
    
    
    58,176
    
    
    49,228577,005
    
    
    623,396**COMMITMENTS
      AND CONTINGENCIES (Notes 5 and 12)**$
    1,798,642
    
    $
    2,101,965The
      accompanying Notes to Consolidated Financial Statements are an integral
      part of these balance sheets.
   21
  **THE
      TOLEDO EDISON COMPANY****CONSOLIDATED
      STATEMENTS OF CAPITALIZATION****Shares
      Outstanding**
    
    **Dollars
      in Thousands****As of
      December 31,**
    
    **2006**
    
    **2005**
    
    **2006**
    
    **2005****COMMON
      STOCKHOLDER'S EQUITY:**Common stock,
      $5 par value, 60,000,000 shares authorized
    
    29,402,054
    
    39,133,887
    
    $            147,010
    
    $           
      195,670Other paid-in
      capital
    
    
    
    
    
    166,786
    
    473,638Accumulated
      other comprehensive income (Note 2(F))
    
    
    
    
    
    (36,804
    )
    4,690Retained
      earnings (Note 9(A))
    
    
    
    
    
    204,423
    
    189,428Total
    
    
    
    
    
    481,415
    
    863,426**PREFERRED
      STOCK NOT SUBJECT TO MANDATORY REDEMPTION (Note
      9(B)):**Cumulative,
      $100 par value, 3,000,000 shares authorized-$4.25
    
    
    -
    
    160,000
    
    -
    
    16,000$4.56
    
    
    -
    
    50,000
    
    -
    
    5,000$4.25
    
    
    -
    
    100,000
    
    -
    
    10,000Total
    
    -
    
    310,000
    
    -
    
    31,000Cumulative,
      $25 par value, 12,000,000 shares authorized-$2.365
    
    
    -
    
    1,400,000
    
    -
    
    35,000Adjustable
      Series B
    
    -
    
    1,200,000
    
    -
    
    30,000Total
    
    -
    
    2,600,000
    
    -
    
    65,000Total
      Preferred Stock
    
    -
    
    2,910,000
    
    -
    
    96,000**LONG-TERM
      DEBT (Note 9(C)):**Secured
      notes-7.130% due
      2007
    
    
    
    
    
    30,000
    
    30,000*
    3.050% due
      2024
    
    
    
    
    
    -
    
    67,3006.100% due
      2027
    
    
    
    
    
    10,100
    
    10,1005.375% due
      2028
    
    
    
    
    
    3,751
    
    3,751*
    3.400% due
      2033
    
    
    
    
    
    -
    
    30,900*
    3.130% due
      2033
    
    
    
    
    
    -
    
    20,200*
    3.150% due
      2033
    
    
    
    
    
    -
    
    30,500*
    3.750% due
      2035
    
    
    
    
    
    45,000
    
    45,000Total
    
    
    
    
    
    88,851
    
    237,751Unsecured
      notes-*
    3.540% due
      2030
    
    
    
    
    
    -
    
    34,850*
    3.620% due
      2033
    
    
    
    
    
    -
    
    18,8006.150% due
      2037
    
    
    
    
    
    300,000
    
    -Total
    
    
    
    
    
    300,000
    
    53,650Net
      unamortized premium (discount) on debt
    
    
    
    
    
    (570
    )
    2Long-term debt
      due within one year
    
    
    
    
    
    (30,000
    )
    (53,650
    )Total
      long-term debt
    
    
    
    
    
    358,281
    
    237,753**TOTAL
      CAPITALIZATION**
    
    
    
    
    
    $            839,696
    
    $       
       1,197,179* Denotes
      variable-rate issue with applicable year-end interest rate
      shown.The
      accompanying Notes to Consolidated Financial Statements are an integral
      part of these statements.
   22
  **THE
      TOLEDO EDISON COMPANY****CONSOLIDATED
      STATEMENTS OF COMMON STOCKHOLDER'S EQUITY****Accumulated****Other**
    
    **Other****Comprehensive**
    
    **Number**
    
    **Par**
    
    **Paid-In**
    
    **Comprehensive**
    
    **Retained****Income**
    
    **of
      Shares**
    
    **Value**
    
    **Capital**
    
    **Income
      (Loss)**
    
    **Earnings*****(Dollars
      in thousands)***Balance,
      January 1, 2004
    
    
    
    
    
    39,133,887
    
    $
    195,670
    
    $
    428,559
    
    $
    11,672
    
    $
    113,620Net
      income
    
    $
    86,283
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    86,283Unrealized
      gain on investments, netof $5,246,000
      of income taxes
    
    
    7,253
    
    
    
    
    
    
    
    
    
    
    
    7,253Minimum
      liability for unfunded retirement benefits,net of
      $717,000 of income taxes
    
    
    1,114
    
    
    
    
    
    
    
    
    
    
    
    1,114Comprehensive
      income
    
    $
    94,650Cash dividends
      on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (8,844
    )Balance,
      December 31, 2004
    
    
    
    
    
    39,133,887
    
    
    195,670
    
    
    428,559
    
    
    20,039
    
    
    191,059Net
      income
    
    $
    76,164
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    76,164Unrealized
      loss on investments, netof $16,884,000
      of income tax benefits
    
    
    (23,654
    )
    
    
    
    
    
    
    
    
    
    
    (23,654
    )Minimum
      liability for unfunded retirement benefits,net of
      $5,836,000 of income taxes
    
    
    8,305
    
    
    
    
    
    
    
    
    
    
    
    8,305Comprehensive
      income
    
    $
    60,815Affiliated
      company asset transfers
    
    
    
    
    
    
    
    
    
    
    
    45,060Restricted
      stock units
    
    
    
    
    
    
    
    
    
    
    
    19Cash dividends
      on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (7,795
    )Cash dividends
      on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (70,000
    )Balance,
      December 31, 2005
    
    
    
    
    
    39,133,887
    
    
    195,670
    
    
    473,638
    
    
    4,690
    
    
    189,428Net
      income
    
    $
    99,404
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    99,404Unrealized
      gain on investments, netof $211,000 of
      income taxes
    
    
    462
    
    
    
    
    
    
    
    
    
    
    
    462Comprehensive
      income
    
    $
    99,866Net liability
      for unfunded retirement benefitsdue to the
      implementation of SFAS 158, netof $26,929,000
      of income tax benefits
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (41,956
    )Affiliated
      company asset transfers (see Note 13)
    
    
    
    
    
    
    
    
    
    
    
    (130,571
    )Repurchase of
      common stock
    
    
    
    
    
    (9,731,833
    )
    
    (48,660
    )
    
    (176,341
    )Preferred
      stock redemption premiums
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (4,840
    )Restricted
      stock units
    
    
    
    
    
    
    
    
    
    
    
    38Stock based
      compensation
    
    
    
    
    
    
    
    
    
    
    
    22Cash dividends
      on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (4,569
    )Cash dividends
      on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (75,000
    )Balance,
      December 31, 2006
    
    
    
    
    
    29,402,054
    
    $
    147,010
    
    $
    166,786
    
    $
    (36,804
    )
    $
    204,423
  **CONSOLIDATED
      STATEMENTS OF PREFERRED STOCK****Not
      Subject to****Mandatory
      Redemption****Number**
    
    **Carrying****of
      Shares**
    
    **Value*****(Dollars
      in thousands)***Balance,
      January 1, 2004
    
    
    4,110,000
    
    $
    126,000Balance,
      December 31, 2004
    
    
    4,110,000
    
    
    126,000Redemptions-Adjustable
      Series A
    
    
    (1,200,000
    )
    
    (30,000
    )Balance,
      December 31, 2005
    
    
    2,910,000
    
    
    96,000Redemptions-$4.25
      Series
    
    
    (160,000
    )
    
    (16,000
    )$4.56
      Series
    
    
    (50,000
    )
    
    (5,000
    )$4.25
      Series
    
    
    (100,000
    )
    
    (10,000
    )$2.365
      Series
    
    
    (1,400,000
    )
    
    (35,000
    )Adjustable
      Series B
    
    
    (1,200,000
    )
    
    (30,000
    )Balance,
      December 31, 2006
    
    
    -
    
    $
    -The
      accompanying Notes to Consolidated Financial Statements are an integral
      part of these statements.
  23
  **THE
      TOLEDO EDISON COMPANY****CONSOLIDATED
      STATEMENTS OF CASH FLOWS****For
      the Years Ended December 31,**
    
    **2006**
    
    **2005**
    
    **2004*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      income
    
    $
    99,404
    
    $
    76,164
    
    $
    86,283Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
    
    
    33,310
    
    
    62,486
    
    
    57,948Amortization
      of regulatory assets
    
    
    95,032
    
    
    141,343
    
    
    123,858Deferral of
      new regulatory assets
    
    
    (54,946
    )
    
    (58,566
    )
    
    (38,696
    )Nuclear fuel
      and capital lease amortization
    
    
    -
    
    
    18,463
    
    
    25,034Deferred rents
      and lease market valuation liability
    
    
    (32,925
    )
    
    (30,088
    )
    
    (23,121
    )Deferred
      income taxes and investment tax credits, net
    
    
    (37,133
    )
    
    (6,519
    )
    
    6,123Accrued
      compensation and retirement benefits
    
    
    4,415
    
    
    5,396
    
    
    6,963Pension trust
      contribution
    
    
    -
    
    
    (19,933
    )
    
    (12,572
    )Tax refund
      related to pre-merger period
    
    
    -
    
    
    8,164
    
    
    -Decrease
      (increase) in operating assets-Receivables
    
    
    6,387
    
    
    10,813
    
    
    10,228Materials and
      supplies
    
    
    -
    
    
    (3,210
    )
    
    (5,133
    )Prepayments
      and other current assets
    
    
    208
    
    
    91
    
    
    5,554Increase
      (decrease) in operating liabilities-Accounts
      payable
    
    
    39,847
    
    
    (45,416
    )
    
    (23,398
    )Accrued
      taxes
    
    
    (2,026
    )
    
    2,387
    
    
    (8,647
    )Accrued
      interest
    
    
    1,899
    
    
    (1,557
    )
    
    (9,080
    )Electric
      service prepayment programs
    
    
    (9,060
    )
    
    32,605
    
    
    -Other
    
    
    4,640
    
    
    (36,939
    )
    
    (18,438
    )Net cash
      provided from operating activities
    
    
    149,052
    
    
    155,684
    
    
    182,906**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Long-term
      debt
    
    
    296,663
    
    
    45,000
    
    
    103,500Short-term
      borrowings, net
    
    
    62,909
    
    
    -
    
    
    73,565Redemptions
      and Repayments-Common
      stock
    
    
    (225,000
    )
    
    -
    
    
    -Preferred
      stock
    
    
    (100,840
    )
    
    (30,000
    )
    
    -Long-term
      debt
    
    
    (202,550
    )
    
    (138,859
    )
    
    (262,162
    )Short-term
      borrowings, net
    
    
    -
    
    
    (8,996
    )
    
    -Dividend
      Payments-Common
      stock
    
    
    (75,000
    )
    
    (70,000
    )
    
    -Preferred
      stock
    
    
    (4,569
    )
    
    (7,795
    )
    
    (8,844
    )Net cash used
      for financing activities
    
    
    (248,387
    )
    
    (210,650
    )
    
    (93,941
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    (61,232
    )
    
    (71,976
    )
    
    (64,629
    )Loan
      repayments from (loans to) associated companies, net
    
    
    (52,178
    )
    
    (409,409
    )
    
    7,081Collection of
      principal on long-term notes receivable
    
    
    202,787
    
    
    552,613
    
    
    203Investments in
      lessor notes (Note 5)
    
    
    9,305
    
    
    11,894
    
    
    10,246Proceeds from
      nuclear decommissioning trust fund sales
    
    
    52,872
    
    
    366,406
    
    
    339,340Investments in
      nuclear decommissioning trust funds
    
    
    (53,138
    )
    
    (394,947
    )
    
    (367,881
    )Other
    
    
    926
    
    
    385
    
    
    (15,547
    )Net cash
      provided from (used for) investing activities
    
    
    99,342
    
    
    54,966
    
    
    (91,187
    )Net change in
      cash and cash equivalents
    
    
    7
    
    
    -
    
    
    (2,222
    )Cash and cash
      equivalents at beginning of year
    
    
    15
    
    
    15
    
    
    2,237Cash and cash
      equivalents at end of year
    
    $
    22
    
    $
    15
    
    $
    15**SUPPLEMENTAL
      CASH FLOW INFORMATION:**Cash Paid
      During the Year-Interest (net
      of amounts capitalized)
    
    $
    17,785
    
    $
    29,709
    
    $
    40,082Income
      taxes
    
    $
    95,753
    
    $
    78,265
    
    $
    53,728The
      accompanying Notes to Consolidated Financial Statements are an integral
      part of these statements.
   24
  **THE
      TOLEDO EDISON COMPANY****CONSOLIDATED
      STATEMENTS OF TAXES****For
      the Years Ended December 31,**
    
    **2006**
    
    **2005**
    
    **2004*****(In
      thousands)*****GENERAL
      TAXES:**Ohio
      kilowatt-hour excise*
    $
    28,071
    
    $
    28,947
    
    $
    28,158Real and
      personal property
    
    20,078
    
    
    25,030
    
    
    23,559Social
      security and unemployment
    
    2,195
    
    
    2,365
    
    
    2,089Other
    
    525
    
    
    766
    
    
    336Total general taxes
    
    
    
    
    $
    50,869
    
    $
    57,108
    
    $
    54,142**PROVISION
      FOR INCOME TAXES:**Currently
      payable-Federal
    
    
    
    
    $
    82,971
    
    $
    61,914
    
    $
    34,587State
    
    
    
    
    
    14,031
    
    
    18,535
    
    
    11,64097,002
    
    
    80,449
    
    
    46,227Deferred, net-Federal
    
    
    
    
    
    (34,776
    )
    
    (18,994
    )
    
    7,156State
    
    
    
    
    
    (1,547
    )
    
    14,875
    
    
    1,064(36,323
    )
    
    (4,119
    )
    
    8,220Investment tax
      credit amortization
    
    (810
    )
    
    (2,399
    )
    
    (2,097
    )Total
      provision for income taxes
    
    
    
    
    $
    59,869
    
    $
    73,931
    
    $
    52,350**RECONCILIATION
      OF FEDERAL INCOME TAX****EXPENSE
      AT STATUTORY RATE TO TOTAL****PROVISION
      FOR INCOME TAXES:**Book income
      before provision for income taxes
    $
    159,273
    
    $
    150,095
    
    $
    138,633Federal income
      tax expense at statutory rate
    $
    55,745
    
    $
    52,533
    
    $
    48,522Increases
      (reductions) in taxes resulting from-State income
      taxes, net of federal income tax benefit
    
    
    
    
    
    8,115
    
    
    21,716
    
    
    8,258Amortization
      of investment tax credits
    
    
    
    
    
    (810
    )
    
    (2,399
    )
    
    (2,097
    )Amortization
      of tax regulatory assets
    
    
    
    
    
    (1,138
    )
    
    (2,841
    )
    
    (2,492
    )Other,
      net
    
    
    
    
    
    (2,043
    )
    
    4,922
    
    
    159Total
      provision for income taxes
    
    
    
    
    $
    59,869
    
    $
    73,931
    
    $
    52,350**ACCUMULATED
      DEFERRED INCOME TAXES AS OF****DECEMBER
      31:**Property basis
      differences
    $
    243,410
    
    $
    229,430
    
    $
    216,933Regulatory
      transition charge
    
    33,408
    
    
    54,719
    
    
    101,190Asset
      retirement obligations
    
    4,437
    
    
    -
    
    
    14,703Unamortized
      investment tax credits
    
    (3,493
    )
    
    (3,785
    )
    
    (9,606
    )Deferred gain
      on asset sales to affiliated companies
    
    10,038
    
    
    10,893
    
    
    11,111Other
      comprehensive income
    
    (23,683
    )
    
    3,036
    
    
    14,084Above market
      leases
    
    (96,112
    )
    
    (104,998
    )
    
    (120,078
    )Retirement
      benefits
    
    7,808
    
    
    6,527
    
    
    41Deferred
      customer shopping incentive
    
    18,399
    
    
    43,926
    
    
    36,628Other
    
    (33,188
    )
    
    (18,599
    )
    
    (43,056
    )Net deferred
      income tax liability
    
    
    
    
    $
    161,024
    
    $
    221,149
    
    $
    221,950*Collected from
      customers through regulated rates and included in revenue in the
      Consolidated Statements of Income.The
      accompanying Notes to Consolidated Financial Statements are an integral
      part of these statements.
   25





**NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS**





**1.**  **ORGANIZATION
AND BASIS OF PRESENTATION:**





The consolidated
financial statements include TE (Company) and its 90% owned subsidiary, TECC.
TECC was formed in 1997 to make equity investments in a business trust in
connection with financing related to the Bruce Mansfield Plant sale and leaseback
transaction (see Note 5). CEI, an affiliate, has a 10% interest in TECC.
The Company is a wholly owned subsidiary of FirstEnergy. FirstEnergy also holds
directly all of the issued and outstanding common shares of its other principal
electric utility operating subsidiaries, including CEI, OE, ATSI, JCP&L,
Met-Ed and Penelec. In the fourth quarter of 2005, the Company completed the
intra-system transfers of its non-nuclear and nuclear generation assets to FGCO
and NGC, respectively. See Note 13 - FirstEnergy Intra-System Generation
Asset Transfers for further discussion.





The Company follows
GAAP and complies with the regulations, orders, policies and practices
prescribed by the SEC, PUCO and FERC. 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 the disclosure of contingent assets and liabilities. Actual
results could differ from these estimates.





The Company
consolidates all majority-owned subsidiaries over which the Company exercises
control and, when applicable, entities for which the Company has a controlling
financial interest. Intercompany transactions and balances are eliminated in
consolidation. Investments in non-consolidated affiliates (20-50% owned
companies, joint ventures and partnerships) over which the Company has the
ability to exercise significant influence, but not control, are accounted for on
the equity basis.





Certain prior year
amounts have been reclassified to conform to the current year presentation.
These reclassifications did not change previously reported earnings for 2005 and
2004.




Unless otherwise
indicated, defined terms used herein have the meanings set forth in the
accompanying Glossary of Terms.




**2.**  **SUMMARY OF
SIGNIFICANT ACCOUNTING POLICIES:**


**(A)**
    **ACCOUNTING FOR THE EFFECTS OF
  REGULATION-**




The Company accounts
for the effects of regulation through the application of SFAS 71 since its
rates:


are established by
  a third-party regulator with the authority to set rates that bind
  customers;are cost-based;
  andcan be charged to
  and collected from customers


An enterprise
meeting all of these criteria capitalizes costs that would otherwise be charged
to expense if the rate actions of its regulator make it probable that those
costs will be re covered in future
revenue. SFAS 71 is applied only to the parts of the business that meet the
above criteria. If a portion of the business applying SFAS 71 no longer
meets those requirements, previously recorded regulatory assets are removed from
the balance sheet in accordance with the guidance in SFAS 101.
 
 *Regulatory
Assets-*


The Company
recognizes, as regulatory assets, costs which the FERC and the PUCO 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. All regulatory assets will continue to be recovered from customers
under the Company's transition plan. Based on that plan, the Company continues
to bill and collect cost-based rates for its transmission and distribution
services, which remain regulated; accordingly, it is appropriate that the
Company co ntinues the
application of SFAS 71 to those operations.





26








Net regulatory
assets on the Consolidated Balance Sheets are comprised of the
following:





**2006**
    
    **2005*****(In
      millions)***Regulatory
      transition costs
    
    $
    134
    
    $
    191Customer
      shopping incentives
    
    
    61
    
    
    132Distribution
      costs -- RCP
    
    
    24
    
    
    -Fuel costs
      -RCP
    
    
    17
    
    
    -Liabilities to
      customers - income taxes
    
    
    (4
    )
    
    (5
    )Gain on
      reacquired debt
    
    
    (3
    )
    
    (4
    )Employee
      postretirement benefit costs
    
    
    5
    
    
    6MISO
      transmission costs
    
    
    16
    
    
    12Asset removal
      costs
    
    
    (5
    )
    
    (47
    )Other
    
    
    3
    
    
    2Total
    
    $
    248
    
    $
    287








The Company had been
deferring customer shopping incentives and interest costs (Extended RTC) as new
regulatory assets in accordance with the prior transition and rate stabilization
plans. As a result of the RCP approved in January 2006, the Extended RTC
balances ($132 million as of December 31, 2005) were reduced on
January 1, 2006 by $45 million by accelerating the application of the
Company's accumulated cost of removal regulatory liability against the Extended
RTC balances. In accordance with the RCP, the recovery periods for the aggregate
of the regulatory transition costs and the Extended RTC amounts were adjusted so
that recovery of these aggregate amounts through the Company's RTC rate
component began on January 1, 2006, with full recovery expected to be
completed as of December 31, 2008. At the end of the recovery period, any
remaining unamortized regulatory transition costs and Extended RTC balances will
be eliminated, first, by applying any remaining cost of removal regulatory
liability balances; any remaining regulatory transition costs and Extended RTC
balances would be written off. The RCP allows the Ohio Companies to defer and
capitalize certain distribution costs during the period January 1, 2006
through December 31, 2008, not to exceed $150 million in each of the
years 2006, 2007 and 2008. These deferrals will be recovered in distribution
rates effective on or after January 1, 2009. In addition, the RCP allows
the Ohio Companies to defer certain increased fuel costs above the amount
collected through a PUCO approved fuel recovery mechanism. See Note 8 for
further discussion of the recovery of the shopping incentives and the new cost
deferrals.





*Transition Cost
Amortization-*





The Company
amortizes transition costs (see Note 8) using the effective interest method.
Extended RTC amortization is equal to the related revenue recovery that is
recognized. The following table provides the estimated net amortization of
regulatory transition costs and Extended RTC amounts (including associated
carrying charges) for the remaining years of the RCP:





**Period**
    
    **Amortization*****(In
      millions)***2007
    
    $
    932008
    
    
    119**Total
      Amortization**
    
    **$**
    212





**(B)**  **CASH AND
SHORT-TERM FINANCIAL INSTRUMENTS-**





All temporary cash
investments purchased with an initial maturity of three months or less are
reported as cash equivalents on the Consolidated Balance Sheets at cost, which
approximates their fair market value.





**(C)**  **REVENUES AND
RECEIVABLES-**





The Company's
principal business is providing electric service to customers in Ohio. The
Company's retail customers are metered on a cycle basis. Electric revenues are
recorded based on energy delivered through the end of the calendar month. An
estimate of unbilled revenues is calculated to recognize electric service
provided between the last meter reading and the end of the month. This estimate
includes many factors including historical customer usage, load profiles,
estimated weather impacts, customer shopping activity and prices in effect for
each class of customer. In each accounting period, the Company accrues the
estimated unbilled amount receivable as revenue and reverses the related prior
period estimate.





27





Receivables from
customers include sales to residential, commercial and industrial customers
located in the Company's service area and sales to wholesale customers. There
was no material concentration of receivables as of December 31, 2006, with
respect to any particular segment of the Company's customers. Total customer
receivables billed were $1 million and $2 million as of
December 31, 2006 and 2005, respectively. There were no unbilled
receivables as of December 31, 2006 and 2005.





The Company and CEI
sell substantially all of their retail customer receivables to CFC, a wholly
owned subsidiary of CEI. In June 2005, the CFC receivable financing structure
was restructured from an off-balance-sheet transaction to an on-balance-sheet
transaction. Under the new structure, any borrowings under the facility appear
on CEI's consolidated balance sheet as short-term debt. The receivables
financing agreement expires on December 5, 2007.





**(D)**  **UTILITY
PLANT AND DEPRECIATION-**





Utility plant
reflects original cost of construction (except for the Company's leasehold
interests in Beaver Valley Unit 2 which were adjusted to fair value),
including payroll and related costs such as taxes, employee benefits,
administrative and general costs, and interest costs incurred to place the
assets in service. The costs of normal maintenance, repairs and minor
replacements are expensed as incurred. The Company's accounting policy for
planned major maintenance projects is to recognize liabilities as they are
incurred.





The Company provides
for depreciation on a straight-line basis at various rates over the estimated
lives of property included in plant in service. The annualized composite rate
was approximately 3.8% in 2006, 3.1% in 2005 and 2.8% in 2004.





*Asset Retirement
Obligations*





The Company
recognizes a liability for retirement obligations associated with tangible
assets in accordance with SFAS 143 and FIN 47. These standards require
recognition of the fair value of a liability for an ARO in the period in which
it is incurred. The associated asset retirement costs are capitalized as part of
the carrying value of the long-lived asset and depreciated over time, as
described further in Note 10, "Asset Retirement Obligations."





**(E)**  **ASSET
IMPAIRMENTS-**





*Long-lived
Assets*





The Company
evaluates the carrying value of its long-lived assets when events or
circumstances indicate that the carrying amount may not be recoverable. In
accordance with SFAS 144, the carrying amount of a long-lived asset is not
recoverable if it exceeds the sum of the undiscounted cash flows expected to
result from the use and eventual disposition of the asset. If an impairment
exists, a loss is recognized for the amount by which the carrying value of the
long-lived asset exceeds its estimated fair value. Fair value is estimated by
using available market valuations or the long-lived asset's expected future net
discounted cash flows. The calculation of expected cash flows is based on
estimates and assumptions about future events.





*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, the Company evaluates its goodwill for
impairment at least annually and would make such an evaluation more frequently
if indicators of impairment should 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 an impairment is
indicated, the Company 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. The Company's 2006 annual review was completed in the third
quarter of 2006 with no impairment indicated. The forecasts used in the
Company's evaluation of goodwill reflect operations consistent with its general
business assumptions. Unanticipated changes in those assumptions could have a
significant effect on its future evaluations of goodwill. The impairment
analysis includes a significant source of cash representing the Company's
recovery of transition costs as described above under "Regulatory Matters." The
Company estimates that completion of transition cost recovery will not result in
an impairment of goodwill. As of December 31, 2006, the Company had
approximately $501 million of goodwill. In the year ended December 31,
2005, the Company adjusted goodwill to reverse pre-merger tax accruals due to
the final resolution of tax contingencies related to the Centerior acquisition.





28





*Investments-*





At the end of each
reporting period, the Company evaluates its investments for impairment. In
accordance with SFAS 115 and FSP SFAS 115-1 and SFAS 124-1,
investments classified as available-for-sale securities are evaluated to
determine whether a decline in fair value below the cost basis is other than
temporary. The Company first considers its intent and ability to hold the
investment until recovery and then considers, among other factors, the duration
and the extent to which the security's fair value has been less than cost and
the near-term financial prospects of the security issuer when evaluating
investments for impairment. If the decline in fair value is determined to be
other than temporary, the cost basis of the investment is written down to fair
value. Upon adoption of FSP SFAS 115-1 and SFAS 124-1, the
Company began recognizing in earnings the unrealized losses on
available-for-sale securities held in the nuclear decommissioning trusts as the
trust arrangements, as they are currently defined, do not meet the required
ability and intent to hold criteria in consideration of the other-than-temporary
impairment. The fair value and unrealized gains and losses of the Company's
investments are disclosed in Note 4(C).





**(F)**
    **COMPREHENSIVE
      INCOME-**





Comprehensive income
includes net income as reported on the Consolidated Statements of Income and all
other changes in common stockholder's equity excluding the effect
from the adoption of SFAS 158 at December 31, 2006, except those resulting from
transactions with FirstEnergy and preferred stockholders. As of
December 31, 2006, accumulated other comprehensive loss consisted of a net
liability for unfunded retirement benefits due to the implementation of
SFAS 158, net of tax benefits (see Note 3) of $42 million and
unrealized gains on investments in securities available for sale of
$5 million. As of December 31, 2005, accumulated other comprehensive
income consisted of unrealized gains on investments in securities available for
sale of $5 million.





**(G)**
    **INCOME
      TAXES-**





Details of the total
provision for income taxes are shown on the Consolidated Statements of Taxes.
The Company records income taxes in accordance with the liability method of
accounting. Deferred income taxes reflect the net tax effect of temporary
differences between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for tax purposes. Investment tax
credits, which were deferred when utilized, are being amortized over the
recovery period of the related property. Deferred income tax assets and
liabilities related to tax and accounting basis differences and tax credit
carryforwards are recognized at the statutory income tax rates in effect when
the liabilities are expected to be paid. The Company is included in
FirstEnergy's consolidated federal income tax return. The consolidated tax
liability is allocated on a "stand-alone" company basis, with the Company
recognizing any tax losses or credits it contributed to the consolidated return
(see Note 7 for Ohio Tax Legislation discussion).





**(H)**
    **TRANSACTIONS
      WITH AFFILIATED COMPANIES-**





Operating revenues,
operating expenses and other income include transactions with affiliated
companies, primarily ATSI, FES, NGC and FESC. The Ohio transition plan resulted
in the corporate separation of FirstEnergy's regulated and unregulated
operations in 2001. In the fourth quarter of 2005, the Company, CEI, OE and Penn
completed the intra-system transfers of their generation a ssets to FGCO and
NGC (see Note 13). This resulted in the elimination of the fossil
generating units rent revenues and the nuclear generation PSA revenues with the
exception of those revenues related to the leasehold interests (see Note 6)
which were not included in the Company's transfers. The Company is now receiving
interest income from FGCO and NGC on the associated companies notes received in
exchange for the transferred net assets. The Company continues to purchase its
power from FES to meet its PLR obligations. The primary affiliated companies
transactions are as follows:








**2006**
    
    **2005**
    
    **2004*****(In
      millions)*****Revenues:**PSA revenues
      from FES
    
    $
    68
    
    $
    195
    
    $
    204Generating
      units rent from FES
    
    
    -
    
    
    12
    
    
    15Electric sales
      to CEI
    
    
    102
    
    
    105
    
    
    101Ground lease
      with ATSI
    
    
    2
    
    
    2
    
    
    2**Expenses:**Purchased
      power under PSA
    
    
    363
    
    
    295
    
    
    311FESC support
      services
    
    
    37
    
    
    34
    
    
    36**Other
      Income:**Interest
      income from ATSI
    
    
    3
    
    
    3
    
    
    3Interest
      income from FES
    
    
    15
    
    
    4
    
    
    10Interest
      income from Shippingport (Note 6)
    
    
    14
    
    
    15
    
    
    16





29





FirstEnergy does not
bill directly or allocate any of its costs to any subsidiary company. Costs are
allocated to the Company from FESC, a subsidiary of FirstEnergy. The majority of
costs are directly billed or assigned at no more than cost. The remaining costs
are for services that are provided on behalf of more than one company, or costs
that cannot be precisely identified and are allocated using formulas developed
by FESC. The current allocation or assignment formulas used and their bases
include multiple factor formulas; each company's proportionate amount of
FirstEnergy's aggregate direct payroll, number of employees, asset balances,
revenues, number of customers, other factors and specific departmental charge
ratios. Management believes that these allocation methods are reasonable.
Intercompany transactions with FirstEnergy and its other subsidiaries are
generally settled under commercial terms within thirty days.





The Company is
selling 150 megawatts of its Beaver Valley Unit 2 leased capacity
entitlement to CEI. Operating revenues for this transaction were
$102 million, $105 million and $101 million in 2006, 2005 and
2004, respectively. This sale agreement is expected to continue through the end
of the lease period (see Note 5).





**3.**  **PENSION AND
OTHER POSTRETIREMENT BENEFIT PLANS:**





FirstEnergy provides
noncontributory defined benefit pension plans that cover substantially all of
its 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 made
a $300 million voluntary cash contribution to its qualified pension plan on
January 2, 2007 (Company's share was $8 million). Projections indicated
that additional cash contributions will not be required before
2016.





FirstEnergy provides
a minimum amount of noncontributory life insurance to retired employees in
addition to optional contributory insurance. Health care benefits, which include
certain employee contributions, deductibles and co-payments, are also available
upon retirement to employees hired prior to January 1, 2005, their
dependents and, under certain circumstances, their survivors. The Company
recognizes the expected cost of providing other postretirement benefits to
employees and their beneficiaries and covered dependents from the time employees
are hired until they become eligible to receive those benefits. During 2006,
FirstEnergy amended the OPEB plan effective in 2008 to cap the monthly
contribution for many of the retirees and their spouses receiving subsidized
healthcare coverage. In addition, FirstEnergy has obligations to former or
inactive employees after employment, but before retirement for disability
related benefits.





Pension and OPEB
costs are affected by employee demographics (including age, compensation levels,
and employment periods), the level of contributions made to the plans and
earnings on plan assets. Such factors may be further affected by business
combinations which impact employee demographics, plan experience and other
factors. Pension and OPEB costs may also be affected by changes in key
assumptions, including anticipated rates of return on plan assets, the discount
rates and health care trend rates used in determining the projected benefit
obligations and pension and OPEB costs. FirstEnergy uses a December 31
measurement date for its pension and OPEB plans. The fair value of the plan
assets represents the actual market value as of December 31, 2006.





In December 2006,
FirstEnergy adopted SFAS 158. This Statement requires employers to recognize an
asset or liability for the overfunded or underfunded status of their pension and
other postretirement benefit plans. For a pension plan, the asset or liability
is the difference between the fair value of the plan's assets and the projected
benefit obligation. For any other postretirement benefit plan, the asset or
liability is the difference between the fair value of the plan's assets and the
accumulated postretirement benefit obligation. The Statement required employers
to recognize all unrecognized prior service costs and credits and unrecognized
actuarial gains and losses in AOCL, net of tax. Such amounts will be adjusted as
they are subsequently recognized as components of net periodic benefit cost or
income pursuant to the current recognition and amortization provisions. TE's
incremental impact of adopting SFAS 158 was a decrease of $35 million in
pension assets, an increase of $34 million in pension liabilities and a
decrease in AOCL of $42 million, net of tax.








30







With the exception
of the Company's share of net pension (asset) liability at the end of year and
net periodic pension expense, the following tables detail the Consolidated
FirstEnergy pension plan and OPEB.





**Pension
      Benefits**
    
    **Other
      Benefits****As of
      December 31**
    
    **2006**
    
    **2005**
    
    **2006**
    
    **2005*****(In
      millions)*****Change
      in benefit obligation**Benefit
      obligation as of January 1
    
    $
    4,750
    
    $
    4,364
    
    $
    1,884
    
    $
    1,930Service
      cost
    
    
    83
    
    
    77
    
    
    34
    
    
    40Interest
      cost
    
    
    266
    
    
    254
    
    
    105
    
    
    111Plan
      participants' contributions
    
    
    -
    
    
    -
    
    
    20
    
    
    18Plan
      amendments
    
    
    3
    
    
    15
    
    
    (620
    )
    
    (312
    )Medicare
      retiree drug subsidy
    
    
    -
    
    
    -
    
    
    6
    
    
    -Actuarial
      (gain) loss
    
    
    33
    
    
    310
    
    
    (119
    )
    
    197Benefits
      paid
    
    
    (274
    )
    
    (270
    )
    
    (109
    )
    
    (100
    )Benefit
      obligation as of December 31
    
    $
    4,861
    
    $
    4,750
    
    $
    1,201
    
    $
    1,884**Change
      in fair value of plan assets**Fair value of
      plan assets as of January 1
    
    $
    4,524
    
    $
    3,969
    
    $
    573
    
    $
    564Actual return
      on plan assets
    
    
    567
    
    
    325
    
    
    69
    
    
    33Company
      contribution
    
    
    -
    
    
    500
    
    
    54
    
    
    58Plan
      participants' contribution
    
    
    -
    
    
    -
    
    
    20
    
    
    18Benefits
      paid
    
    
    (273
    )
    
    (270
    )
    
    (109
    )
    
    (100
    )Fair value of
      plan assets as of December 31
    
    $
    4,818
    
    $
    4,524
    
    $
    607
    
    $
    573**Funded
      status**
    
    $
    (43
    )
    $
    (226
    )
    $
    (594
    )
    $
    (1,311
    )**Accumulated
      benefit obligation**
    
    $
    4,447
    
    $
    4,327**Amounts
      Recognized in the Statement of****Financial
      Position**Noncurrent
      assets
    
    $
    -
    
    $
    1,023
    
    $
    -
    
    $
    -Current
      liabilities
    
    
    -
    
    
    -
    
    
    -
    
    
    -Noncurrent
      liabilities
    
    
    (43
    )
    
    -
    
    
    (594
    )
    
    (1,057
    )Net pension
      asset (liability) as of December 31
    
    $
    (43
    )
    $
    1,023
    
    $
    (594
    )
    $
    (1,057
    )Company's
      share of net pension asset (liability) at end of year
    
    $
    (3
    )
    $
    36
    
    $
    (74
    )
    $
    (40
    )**Amounts
      Recognized in****Accumulated
      Other Comprehensive Income**Prior service
      cost (credit)
    
    $
    63
    
    $
    -
    
    $
    (1,190
    )
    $
    -Actuarial
      loss
    
    
    982
    
    
    -
    
    
    702
    
    
    -Net amount
      recognized
    
    $
    1,045
    
    $
    -
    
    $
    (488
    )
    $
    -**Assumptions
      Used to Determine****Benefit
      Obligations As of December 31**Discount
      rate
    
    
    6.00
    %
    
    5.75
    %
    
    6.00
    %
    
    5.75
    %Rate of
      compensation increase
    
    
    3.50
    %
    
    3.50
    %**Allocation
      of Plan Assets****As of
      December 31**Asset
      CategoryEquity
      securities
    
    
    64
    %
    
    63
    %
    
    72
    %
    
    71
    %Debt
      securities
    
    
    29
    
    
    33
    
    
    26
    
    
    27Real
      estate
    
    
    5
    
    
    2
    
    
    1
    
    
    -Private
      equities
    
    
    1
    
    
    -
    
    
    -
    
    
    -Cash
    
    
    1
    
    
    2
    
    
    1
    
    
    2Total
    
    
    100
    %
    
    100
    %
    
    100
    %
    
    100
    %








31






**Estimated
      Items to be Amortized in 2007 Net****Periodic
      Pension Cost from Accumulated**
    
    **Pension**
    
    **Other****Other
      Comprehensive Income**
    
    **Benefits**
    
    **Benefits*****(In
      millions)***Prior service
      cost (credit)
    
    $
    10
    
    $
    (149
    )Actuarial
      loss
    
    $
    41
    
    $
    45


**Pension
      Benefits**
    
    **Other
      Benefits****Components
      of Net Periodic Benefit Costs**
    
    **2006**
    
    **2005**
    
    **2004**
    
    **2006**
    
    **2005**
    
    **2004*****(In
      millions)***Service
      cost
    
    $
    83
    
    $
    77
    
    $
    77
    
    $
    34
    
    $
    40
    
    $
    36Interest
      cost
    
    
    266
    
    
    254
    
    
    252
    
    
    105
    
    
    111
    
    
    112Expected
      return on plan assets
    
    
    (396
    )
    
    (345
    )
    
    (286
    )
    
    (46
    )
    
    (45
    )
    
    (44
    )Amortization
      of prior service cost
    
    
    10
    
    
    8
    
    
    9
    
    
    (76
    )
    
    (45
    )
    
    (40
    )Recognized net
      actuarial loss
    
    
    58
    
    
    36
    
    
    39
    
    
    56
    
    
    40
    
    
    39Net periodic
      cost
    
    $
    21
    
    $
    30
    
    $
    91
    
    $
    73
    
    $
    101
    
    $
    103Company's
      share of net periodic cost
    
    $
    1
    
    $
    1
    
    $
    3
    
    $
    8
    
    $
    9
    
    $
    7****Weighted-Average
      Assumptions Used****
    
    ****
    ******to
      Determine Net Periodic Benefit Cost**
    
    
    **Pension
      Benefits**
    
    
    **Other
      Benefits****for
      Years Ended December 31**
    
    
    **2006**
    
    
    **2005**
    
    
    **2004**
    
    
    **2006**
    
    
    **2005**
    
    
    **2004**Discount
      rate
    
    
    5.75
    %
    
    6.00
    %
    
    6.25
    %
    
    5.75
    %
    
    6.00
    %
    
    6.25
    %Expected
      long-term return on plan assets
    
    
    9.00
    %
    
    9.00
    %
    
    9.00
    %
    
    9.00
    %
    
    9.00
    %
    
    9.00
    %Rate of
      compensation increase
    
    
    3.50
    %
    
    3.50
    %
    
    3.50
    %


In selecting an
assumed discount rate, FirstEnergy considers currently available rates of return
on high-quality fixed income investments expected to be available during the
period to maturity of the pension and other postretirement benefit obligations.
The assumed rates of return on pension plan assets consider historical market
returns and economic forecasts for the types of investments held by the
Company's pension trusts. The long-term rate of return is developed considering
the portfolio?s asset allocation strategy.
 
 FirstEnergy employs a
total return investment approach whereby a mix of equities and fixed income
investments are used to maximize the long-term return on plan assets for a
prudent level of risk. Risk tolerance is established through careful
consideration of plan liabilities, plan funded status, and corporate financial
condition. The investment portfolio contains a diversified blend of equity and
fixed-income investments. Furthermore, equity investments are diversified across
U.S. and non-U.S. stocks, as well as growth, value, and small and large
capitalization funds. Other assets such as real estate are used to enhance
long-term returns while improving portfolio diversification. Derivatives may be
used to gain market exposure in an efficient and timely manner; however,
derivatives are not used to leverage the portfolio beyond the market value of
the underlying investments. Investment risk is measured and monitored on a
continuing basis through periodic investment portfolio reviews, annual liability
measurements, and periodic asset/liability studies.





**Assumed
      Health Care Cost Trend Rates****As of
      December 31**
    
    **2006**
    
    **2005**Health care
      cost trend rate assumed for nextyear
      (pre/post-Medicare)
    
    
    9-11
    %
    
    9-11
    %Rate to which
      the cost trend rate is assumed todecline (the
      ultimate trend rate)
    
    
    5
    %
    
    5
    %Year that the
      rate reaches the ultimate trendrate
      (pre/post-Medicare)
    
    
    2011-2013
    
    
    2010-2012





Assumed health care
cost trend rates have a significant effect on the amounts reported for the
health care plans. A one-percentage-point change in assumed health care cost
trend rates would have the following effects:





**1-Percentage-**
    
    **1-Percentage-****Point
      Increase**
    
    **Point
      Decrease*****(In
      millions)***Effect on
      total of service and interest cost
    
    $
    6
    
    $
    (5
    )Effect on
      accumulated postretirement benefit obligation
    
    $
    33
    
    $
    (29
    )








32








Taking into account
estimated employee future service, FirstEnergy expects to make the following
benefit payments from plan assets:





**Pension**
    
    **Other****Benefits**
    
    **Benefits*****(In
      millions)***2007
    $
    247
    
    $
    912008
    
    249
    
    
    912009
    
    256
    
    
    942010
    
    269
    
    
    982011
    
    280
    
    
    101Years 2012-
      2016
    
    1,606
    
    
    537




**4.FAIR VALUE OF FINANCIAL
INSTRUMENTS:**




**(A)**  **LONG-TERM
DEBT-**





All borrowings with
initial maturities of less than one year are defined as financial instruments
under GAAP and are reported on the Consolidated Balance Sheets at cost, which
approximates their fair market value. The following table provides the
approximate fair value and related carrying amounts of long-term debt as
disclosed in the Consolidated Statements of Capitalization as of
December 31:





**2006**
    
    **2005****Carrying**
    
    **Fair**
    
    **Carrying**
    
    **Fair****Value**
    
    **Value**
    
    **Value**
    
    **Value*****(In
      millions)***Long-term
      debt
    
    $
    389
    
    $
    388
    
    $
    291
    
    $
    293





The fair value of
long-term debt reflects the present value of the cash outflows relating to those
securities based on the current call price, the yield to maturity or the yield
to call, as deemed appropriate at the end of each respective year. The yields
assumed were based on securities with similar characteristics offered by a
corporation with credit ratings similar to the Company's ratings.




**(B)**  **INVESTMENTS-**





The following table
provides the approximate fair value and related carrying amounts of investments
excluding nuclear decommissioning trust funds and investments of $2 million
excluded by SFAS 107, "Disclosures about Fair Values of Financial Instruments",
as of December 31:





**2006**
    
    **2005****Carrying**
    
    **Fair**
    
    **Carrying**
    
    **Fair****Value**
    
    **Value**
    
    **Value**
    
    **Value*****(In
      millions)***Notes
      receivable
    
    $
    298
    
    $
    327
    
    $
    615
    
    $
    645








The table above
represents notes receivable. Fair value of notes receivables represents the
present value of the cash inflows based on the yield to maturity. The yields
assumed were based on financial instruments with similar characteristics and
terms and have maturity dates ranging from 2007 to 2040.




**(C)**  **NUCLEAR
DECOMMISSIONING TRUST FUND INVESTMENTS-**
 
 Nuclear
d ecommissioning trust
investments are classified as available-for-sale securities. As part of the
intra-system nuclear generation asset transfer in the fourth quarter of 2005,
the Company transferred its decommissioning trust investments to NGC with the
exception of a portion related to the leasehold interests in Beaver Valley
Unit 2 retained by the Company. The Company has no securities held for
trading purposes. Upon adoption of FSP SFAS 115-1 and SFAS 124-1,
the Company began expensing unrealized losses on available-for-sale securities
held in the nuclear decommissioning trusts since the trust arrangements, as
they are currently defined, do not meet the required ability and intent to hold
criteria in consideration of other-than-temporary impairment. Approximately
$0.3 million of unrealized losses on available-for-sale securities were
reclassified from OCI to earnings upon adoption of this pronouncement. The
balance was determined using the specific identification method. The following
table provides the approximate fair value and related carrying amounts of
investments other than cash and cash equivalents as of December 31:







33








**2006**
    
    **2005****Carrying**
    
    **Fair**
    
    **Carrying**
    
    **Fair****Value**
    
    **Value**
    
    **Value**
    
    **Value*****(In
      millions)***Debt
      securities:-Government
      obligations
    
    $
    61
    
    $
    61
    
    $
    59
    
    $
    59








The following table
summarizes the amortized cost basis, gross unrealized gains and losses and fair
values for decommissioning trust investments as of
December 31:





**2006**
    
    **2005****Cost**
    
    **Unrealized**
    
    **Unrealized**
    
    **Fair**
    
    **Cost**
    
    **Unrealized**
    
    **Unrealized**
    
    **Fair****Basis**
    
    
    
    
    
    **Gains**
    
    
    **Losses**
    
    
    **Value**
    
    
    **Basis**
    
    
    **Gains**
    
    
    **Losses**
    
    
    **Value*****(In
      millions)***Debt
      securities
    
    $
    61
    
    $
    -
    
    $
    -
    
    $
    61
    
    $
    60
    
    $
    -
    
    $
    1
    
    $
    59








Unrealized gains
applicable to the Company's decommissioning trusts are recognized in OCI in
accordance with SFAS 115, as fluctuations in the fair value of these trust
balances will eventually affect earnings.





Proceeds from the
sale of decommissioning trust investments, gross realized gains and losses on
those sales, and interest and dividend income for the three years ended
December 31, 2006 were as follows:





**2006**
    
    **2005**
    
    **2004*****(In
      millions)***Proceeds from
      sales
    
    $
    53
    
    $
    366
    
    $
    269Gross realized
      gains
    
    
    -
    
    
    35
    
    
    22Gross realized
      losses
    
    
    1
    
    
    15
    
    
    13Interest and
      dividend income
    
    
    -
    
    
    9
    
    
    9







The investment
policy for the nuclear decommissioning trust funds restricts or limits the
ability to hold certain types of assets including private or direct placements,
warrants, securities of FirstEnergy, investments in companies owning nuclear
power plants, financial derivatives, preferred stocks, securities convertible
into common stock and securities of the trust fund's custodian or managers and
their parents or subsidiaries.





**5.** **LEASES:**





The Company leases
certain generating facilities, office space and other property and equipment
under cancelable and noncancelable leases.





The Company and CEI
sold their ownership int erests in Bruce
Mansfield Units 1, 2 and 3 and the Company sold a portion of its ownership
interest in Beaver Valley Unit 2. In connection with these sales, which
were completed in 1987, the Company and CEI entered into operating leases for
lease terms of approximately 30 years as co-lessees. Subsequent to the
intra-system generation assets transfers in the fourth quarter of 2005, the
Company and CEI continue to be responsible, to the extent of their leasehold
interests during the terms of the leases, for costs associated with the units
including construction expenditures, operation and maintenance expenses,
insurance, nuclear fuel, property taxes and decommissioning. The Company and CEI
have the right, at the end of the respective basic lease terms, to renew the
leases. The Company and CEI also have the right to purchase the facilities at
the expiration of the basic lease term or any renewal term at a price equal to
the fair market value of the facilities.





As co-lessee with
CEI, the Company is also obligated for CEI's lease payments. If CEI is unable to
make its payments under the Bruce Mansfield Plant lease, the Company would be
obligated to make such payments. No such payments have been made on behalf of
CEI. (CEI's future minimum lease payments as of December 31,
200 6
were approximately $0.1 billion, net of trust cash receipts.)





Consistent with the
regulatory treatment, the rentals for operating leases are charged to operating
expenses on the Consolidated Statements of Income. Such costs for the three
years ended December 31, 2006 are summarized as follows:








34





**2006**
    
    **2005**
    
    **2004*****(In
      millions)***Operating
      leasesInterest
      element
    
    $
    41.1
    
    $
    43.9
    
    $
    46.4Other
    
    
    68.3
    
    
    62.3
    
    
    52.9Total
      rentals
    
    $
    109.4
    
    $
    106.2
    
    $
    99.3





The future minimum
lease payments as of December 31, 200 6 are:





**Operating
      Leases****Lease**
    
    **Capital****Payments**
    
    **Trust**
    
    **Net*****(In
      millions)***2007
    
    $
    101.4
    
    $
    22.6
    
    $
    78.82008
    
    
    99.3
    
    
    27.2
    
    
    72.12009
    
    
    100.5
    
    
    23.3
    
    
    77.22010
    
    
    100.8
    
    
    28.5
    
    
    72.32011
    
    
    98.8
    
    
    29.1
    
    
    69.7Years
      thereafter
    
    
    530.8
    
    
    120.1
    
    
    410.7Total minimum
      lease payments
    
    $
    1,031.6
    
    $
    250.8
    
    $
    780.8





The Company has
recorded above-market lease lia bilities for Beaver
Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger
creating FirstEnergy. The total above-market lease obligation of
$111 million associated with Beaver Valley Unit 2 is being amortized
on a straight-line basis through the end of the lease term in 2017
(approximately $6 million per year). The total above-market lease
obligation of $298 million associated with the Bruce Mansfield Plant is
being amortized on a straight-line basis through the end of 2016 (approximately
$19 million per year). As of December 31, 2006 the above-market lease
liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant totaled
approximately $243 million, of which $25 million is payable within one
year.





The Company and CEI
refinanced high-cost fixed obligations related to their 1987 sale and leaseback
transaction for the Bruce Mansfield Plant through a lower cost transaction in
June and July 1997. In a June 1997 offering (Offering), the two companies
pledged $720 million aggregate principal amount ($145 million for the
Company and $575 million for CEI) of FMB due through 2007 to a trust as
security for the issuance of a like principal amount of secured notes due
through 2007. The obligations of the two companies under these secured notes are
joint and several. Using available cash, short-term borrowings and the net
proceeds from the Offering, the two companies invested $907 million
($337 million for the Company and $570 million for CEI) in a business
trust, in June 1997. The trust used these funds in July 1997 to purchase lease
notes and redeem all $873 million aggregate principal amount of 10-1/4% and
11-1/8% secured lease obligations bonds (SLOBs) due 2003 and 2016. The SLOBs
were issued by a special-purpose funding corporation in 1988 on behalf of
lessors in the two companies' 1987 sale and leaseback transactions. The
Shippingport arrangement effectively reduces lease costs related to that
transaction (see Note 6 for FIN 46R discussion).





**6.** **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 adopted
FIN 46R for special-purpose entities as of December 31, 2003 and for all
other entities in the first quarter of 2004. The Company consolidates a VIE when
it is determined to be the VIE's primary beneficiary as defined by FIN 46R.





Shippingport was
established to purchase all of the lease obligation bonds issued in connection
with the Company's and CEI's Bruce Mansfield Plant sale and leaseback
transaction in 1987. The Company and CEI used debt and available funds to
purchase the notes issued by Shippingport. Adoption of FIN 46R resulted in the
consolidation of Shippingport by CEI as of December 31, 2003.





Through its
investment in Shippingport, the Company has a variable interest in certain owner
trusts that acquired the interests in the Bruce Mansfield Plant. The Company
concluded that it was not the primary beneficiary of the owner trusts and it was
therefore not required to consolidate these entities. The leases are accounted
for as operating leases in accordance with GAAP.






35





The Company is
exposed to losses under the applicable sale and leaseback agreements upon the
occurrence of certain contingent events that the Company considers unlikely to
occur. The Company has a maximum exposure to loss under these provisions of
approximately $955 million, which represents the net amount of casualty value
payments upon the occurrence of specified casualty events that render the
applicable plant worthless. Under the sale and leaseback agreements, the Company
has net minimum discounted lease payments of $503 million, that would not be
payable if the casualty value payments are made.





**7.**
    **OHIO
      TAX LEGISLATION:**





On June 30,
2005, tax legislation was enacted in the State of Ohio that created a new CAT
tax, which is based on qualifying "taxable gross receipts" and does not consider
any expenses or costs incurred to generate such receipts, except for items such
as cash discounts, returns and allowances, and bad debts. The CAT tax was
effective July 1, 2005, and replaces the Ohio income-based franchise tax
and the Ohio personal property tax. The CAT tax is phased-in while the current
income-based franchise tax is phased-out over a five-year period at a rate of
20% annually, beginning with the year ended 2005, and the personal property tax
is phased-out over a four-year period at a rate of approximately 25% annually,
beginning with the year ended 2005. During the phase-out period, the Ohio
income-based franchise tax will be computed consistent with the prior tax law,
except that the tax liability as computed was or will be multiplied by 4/5 in
2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the
current income-based franchise tax over a five-year period. As a result of the
new tax structure, all net deferred tax benefits that were not expected to
reverse during the five-year phase-in period were written-off as of
June 30, 2005. The impact on income
taxes associated with the required adjustment to net deferred taxes for 2005 was
an additional tax expense of approximately $18 million, which was partially
offset by the initial phase-out of the Ohio income-based franchise tax, which
reduced income taxes by approximately $1 million in 2005.





**8.**
    **REGULATORY
      MATTERS:**





Regulatory assets
are costs which have been authorized by the PUCO and the FERC for recovery from
customers in the 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. All regulatory assets are
expected to be recovered under the provisions of the Company's transition plan.





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 (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force)
regarding enhancements to regional reliability. In 2004, FirstEnergy completed
implementation of all actions and initiatives related to enhancing area
reliability, improving voltage and reactive management, operator readiness and
training and emergency response preparedness recommended for completion in 2004.
On July 14, 2004, NERC independently verified that FirstEnergy had
implemented the various initiatives to be completed by June 30 or summer
2004, with minor exceptions noted by FirstEnergy, which exceptions are now
essentially complete. FirstEnergy is 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 equipment or material upgrades to
existing equipment. The FERC or other applicable government agencies and
reliability entities may, however, take a different view as to recommended
enhancements or may recommend additional enhancements in the future, which could
require additional, material expenditures.





The EPACT provides
for the creation of an ERO to establish and enforce reliability standards for
the bulk power system, subject to FERC's review. On February 3, 2006, the
FERC adopted a rule establishing certification requirements for the ERO, as well
as regional entities envisioned to assume compliance monitoring and enforcement
responsibility for the new reliability standards. The FERC issued an order on
rehearing on March 30, 2006, providing certain clarifications and
essentially affirming the rule.






36





The NERC has been
preparing the implementation aspects of reorganizing its structure to meet the
FERC's certification requirements for the ERO. The NERC made a filing with the
FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC
approval of pro forma delegation agreements with regional reliability
organizations (regional entities). The new FERC rule referred to above, further
provides for reorganizing regional entities that would replace the current
regional councils and for rearranging their relationship with the ERO. The
"regional entity" may be delegated authority by the ERO, subject to FERC
approval, for compliance and enforcement of reliability standards adopted by the
ERO and approved by the FERC. The ERO filing was noticed on April 7, 2006 and
comments and reply comments were filed in May, June and July 2006. On July 20,
2006, the FERC certified the NERC as the ERO to implement the provisions of
Section 215 of the Federal Power Act and directed the NERC to make compliance
filings addressing governance and non-governance issues and the regional
delegation agreements. On September 18, 2006 and October 18, 2006, NERC
submitted compliance filings addressing the governance and non-governance issues
identified in the FERC ERO Certification Order, dated July 20, 2006. On October
30, 2006, the FERC issued an order accepting most of NERC's governance filings.
On January 18, 2007, the FERC issued an order largely accepting NERC's
compliance filings addressing non-governance issues, subject to an additional
compliance filing requirement.
 
 On April 4, 2006,
NERC also submitted a filing with the FERC seeking approval of mandatory
reliability standards, as well as for approval with the relevant Canadian
authorities. These reliability standards are based, with some modifications and
additions, on the current NERC Version 0 reliability standards. The reliability
standards filing was subsequently evaluated by the FERC on May 11, 2006, leading
to the FERC staff's release of a preliminary assessment that cited many
deficiencies in the proposed reliability standards. The NERC and industry
participants filed comments in response to the Staff's preliminary assessment.
The FERC held a technical conference on the proposed reliability standards on
July 6, 2006. The FERC issued a NOPR on the proposed reliability standards on
October 20, 2006. In the NOPR, the FERC proposed to approve 83 of the 107
reliability standards and directed NERC to make technical improvements to 62 of
the 83 standards approved. The 24 standards that were not approved remain
pending at the FERC awaiting further clarification and filings by the NERC and
regional entities. The FERC also provided additional clarification within the
NOPR regarding the proposed application of final standards and guidance with
regard to technical improvements of the standards. On November 15, 2006, NERC
submitted several revised reliability standards and three new proposed
reliability standards. Interested parties were provided the opportunity to
comment on the NOPR (including the revised standards submitted by NERC in
November) by January 3, 2007. Numerous parties, including FirstEnergy, filed
comments on the NOPR on January 3, 2007. Mandatory reliability standards
enforceable with penalties are expected to be in place by the summer of 2007. In
a separate order issued October 24, 2006, the FERC approved NERC's 2007
budget and business plan subject to certain compliance
filings.





On November 29,
2006, NERC submitted an additional compliance filing with the FERC regarding the
Compliance Monitoring and Enforcement Program (CMEP) along with the proposed
Delegation Agreements between the ERO and the regional reliability entities. The
FERC provided opportunity for interested parties to comment on the CMEP by
January 10, 2007. FirstEnergy, as well as other parties, moved to intervene and
submitted responsive comments on January 10, 2007. This filing is pending before
the FERC.





The ECAR,
Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability
councils completed the consolidation of these regions into a single new regional
reliability organization known as Reliability *First* Corporation.
Reliability *First* began operations as
a regional reliability council under NERC on January 1, 2006 and on
November 29, 2006 filed a proposed Delegation Agreement with NERC to obtain
certification consistent with the final rule as a "regional entity" under the
ERO. All of FirstEnergy's facilities are located within the
Reliability *First* region.





On May 2, 2006, the
NERC Board of Trustees adopted eight new cyber security standards that replaced
interim standards put in place in the wake of the September 11, 2001 terrorist
attacks, and thirteen additional reliability standards. The security standards
became effective on June 1, 2006, and the remaining standards will become
effective throughout 2006 and 2007. NERC filed these proposed standards with the
FERC and relevant Canadian authorities for approval. The cyber security
standards were not included in the October 20, 2006 NOPR and are being
addressed in a separate FERC docket. On December 11, 2006, the FERC Staff
provided its preliminary assessment of these proposed mandatory reliability
standards and again cited various deficiencies in the proposed standards,
providing interested parties with the opportunity to comment on the assessment
by February 12, 2007.





FirstEnergy believes
it is in compliance with all current NERC reliability standards. However, based
upon a review of the October 20, 2006 NOPR, it appears that the FERC will
adopt more strict reliability standards than those contained in the current NERC
standards. The financial impact of complying with the new standards cannot be
determined at this time. However, the EPACT required that all prudent costs
incurred to comply with the new reliability standards be recovered in rates. If
FirstEnergy is unable to meet the reliability standards for its bulk power
system in the future, it could have a material adverse effect on FirstEnergy's
and its subsidiaries' financial condition, results of operations and cash
flows.






37





On October 21, 2003,
the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the
Ohio Companies accepted the RSP as modified and approved by the PUCO in an
August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to
establish generation service rates beginning January 1, 2006, in response to the
PUCO's concerns about price and supply uncertainty following the end of the Ohio
Companies' transition plan market development period. On May 3, 2006, the
Supreme Court of Ohio issued an opinion affirming the PUCO's order in all
respects, except it remanded back to the PUCO the matter of ensuring the
availability of sufficient means for customer participation in the marketplace.
The RSP contained a provision that permitted the Ohio Companies to withdraw and
terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio,
rejected all or part of the RSP. In such event, the Ohio Companies have 30 days
from the final order or decision to provide notice of termination. On July 20,
2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding
on Remand. In their Request, the Ohio Companies provided notice of termination
to those provisions of the RSP subject to termination, subject to being
withdrawn, and also set forth a framework for addressing the Supreme Court of
Ohio's findings on customer participation. If the PUCO approves a resolution to
the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio
Companies, the Ohio Companies' termination will be withdrawn and considered to
be null and void. On July 26, 2006, the PUCO issued an Entry directing the Ohio
Companies to file a plan in a new docket to address the Court's concern. The
Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial
comments were filed on January 12, 2007 and reply comments were filed on
January 29 , 2007.
I n
their reply comments the Ohio Companies described the highlights of a new tariff
offering they would be willing to make available to customers that would allow
customers to purchase renewable energy certificates associated with a renewable
generation source, subject to PUCO approval. No further
proceedings are scheduled at this time.





The Ohio Companies
filed an application and stipulation with the PUCO on September 9, 2005
seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the
Ohio Companies filed a supplemental stipulation with the PUCO, which constituted
an additional component of the RCP filed on September 9, 2005. Major provisions
of the RCP include:




Maintaining
      the existing level of base distribution rates through December 31,
      2008 for the Company;Deferring and
      capitalizing for future recovery (over a 25-year period) with carrying
      charges certain distribution costs to be incurred during the period
      January 1, 2006 through December 31, 2008, not to exceed
      $150 million in each of the three years;Adjusting the
      RTC and extended RTC recovery periods and rate levels so that full
      recovery of authorized costs will occur as of December 31, 2008 for
      the Company;Reducing the
      deferred shopping incentive balances as of January 1, 2006 by up to
      $45 million for the Company by accelerating the application of the
      Company's accumulated cost of removal regulatory liability;
      andRecovering
      increased fuel costs (compared to a 2002 baseline) of up to
      $75 million, $77 million, and $79 million, in 2006, 2007,
      and 2008, respectively, from all of OE's and the Company's distribution
      and transmission customers through a fuel recovery mechanism. The Company
      may defer and capitalize (for recovery over a 25-year period) increased
      fuel costs above the amount collected through the fuel recovery
      mechanism.




On January 4, 2006,
the PUCO approved, with modifications, the Ohio Companies' RCP to supplement the
RSP to provide customers with more certain rate levels than otherwise available
under the RSP during the plan period. On January 10,
2006, the Ohio Companies filed a Motion for Clarification seeking clarity on a
number of issues. On January 25, 2006, the PUCO issued an Entry on
Rehearing granting in part, and denying in part, the Ohio Companies' previous
requests and clarifying issues referred to above. The PUCO granted the Ohio
Companies' requests to:


Recognize fuel
      and distribution deferrals commencing January 1,
  2006;Recognize
      distribution deferrals on a monthly basis prior to review by the PUCO
      Staff;Clarify that
      the types of distribution expenditures included in the Supplemental
      Stipulation may be deferred; andClarify that
      distribution expenditures do not have to be "accelerated" in order to be
      deferred.
 
  38





The PUCO approved
the Ohio Companies' methodology for determining distribution deferral amounts,
but denied the Motion in that the PUCO Staff must verify the level of
distribution expenditures contained in current rates, as opposed to simply
accepting the amounts contained in the Ohio Companies' Motion. On
February 3, 2006, several other parties filed applications for rehearing,
which the PUCO denied on March 1, 2006. Two of these parties subsequently filed
notices of appeal with the Supreme Court of Ohio. The Ohio Supreme Court
scheduled this case for oral argument on February 27, 2007. On January 31, 2007,
the Ohio Companies filed a stipulation which, among other matters and subject to
PUCO approval, affirmed that the supplemental stipulation in the RCP would be
implemented. This stipulation was approved by the PUCO on February 14,
2007.





On December 30,
2004, the Ohio Companies filed with the PUCO two applications related to the
recovery of transmission and ancillary service related costs. The first
application sought recovery of these costs beginning January 1, 2006. The
Ohio Companies requested that these costs be recovered through a rider that
would be effective on January 1, 2006 and adjusted each July 1
thereafter. The parties reached a settlement agreement that was approved by the
PUCO on August 31, 2005. The incremental transmission and ancillary service
revenues recovered from January 1 through June 30, 2006 were
approximately $54 million. That amount included the recovery of a portion
of the 2005 deferred MISO expenses as described below. On April 27, 2006,
the Ohio Companies filed the annual update rider to determine revenues
($124 million) from July 2006 through June 2007. The filed rider went into
effect on July 1, 2006.





The second
application sought authority to defer costs associated with transmission and
ancillary service related costs incurred during the period October 1, 2003
through December 31, 2005. On May 18, 2005, the PUCO granted the
accounting authority for the Ohio Companies to defer incremental transmission
and ancillary service-related charges incurred as a participant in MISO, but
only for those costs incurred during the period December 30, 2004 through
December 31, 2005. Permission to defer costs incurred prior to
December 30, 2004 was denied. The PUCO also authorized the Ohio Companies
to accrue carrying charges on the deferred balances. On August 31, 2005,
the OCC appealed the PUCO's decision. On January 20,
2006, the OCC sought rehearing of the PUCO's approval of the recovery of
deferred costs through the rider during the period January 1, 2006 through
June 30, 2006. The PUCO denied the OCC's application on February 6,
2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio
Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate
this appeal with the deferral appeals discussed above and to postpone oral
arguments in the deferral appeal until after all briefs are filed in this most
recent appeal of the rider recovery mechanism. On March 20, 2006,
the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of the
Ohio Companies' case with a similar case involving Dayton Power & Light
Company. Oral arguments were heard on May 10, 2006. On November 29,
2006, the Ohio Supreme Court issued its opinion upholding the PUCO's
determination that the Ohio Companies may defer transmission and ancillary
service related costs incurred on and after December 30, 2004. The Ohio
Supreme Court also determined that the PUCO erred when it denied the OCC
intervention, but further ruled that such error did not prejudice OCC and,
therefore, the Ohio Supreme Court did not reverse or remand the PUCO on this
ground. The Ohio Supreme Court also determined that the OCC's appeal was not
premature. No party filed a motion for reconsideration with the Ohio Supreme
Court.





On November 1, 2005,
FES filed a power sales agreement for approval with the FERC. The power sales
agreement provided for FES to provide the PLR requirements of the Ohio Companies
at a price equal to the retail generation rates approved by the PUCO for a
period of three years beginning January 1, 2006. The Ohio Companies will be
relieved of their obligation to obtain PLR power requirements from FES if the
Ohio CBP results in a lower price for retail customers.





On December 29,
2005, the FERC issued an order setting the power sales agreement for hearing.
The order criticized the Ohio CBP, and required FES to submit additional
evidence in support of the reasonableness of the prices charged in the power
sales agreement. On July 14, 2006, the Chief Judge granted the joint motion of
FES and the Trial Staff to appoint a settlement judge in this proceeding and the
procedural schedule was suspended pending settlement discussions among the
parties. A settlement conference was held on September 5, 2006. FES, the Ohio
Companies and the PUCO, along with other
parties, reached an agreement to settle the case. The settlement was filed with
the FERC on October 17, 2006, and was unopposed by the remaining parties,
including the FERC Trial Staff. This settlement was accepted by the FERC on
December 8, 2006.





The terms of the
settlement provide for modification of the power supply agreement with FES.
Under the power supply agreement, separate rates are established for the Ohio
Companies' PLR requirements; special retail contract requirements, wholesale
contract requirements, and interruptible buy-through retail load requirements.
For their PLR and special retail contract requirements, the Ohio Companies will
pay FES no more than the lower of (i) the sum of the retail generation charge,
the rate stabilization charge, the fuel recovery mechanism charge, and FES'
actual incremental fuel costs for such sales; or (ii) the wholesale price cap.
Different wholesale price caps are imposed for PLR sales, special retail
contracts, and wholesale contracts. The wholesale price for interruptible
buy-through retail load requirements is limited to the actual spot price of
power obtained by FES to provide this power. FES billed the Ohio Companies for
the additional amount payable to FES for incremental fuel costs on power
supplied during 2006. The total power supply cost billed by FES was lower in
each case than the wholesale price caps specified in the settlement accepted by
the FERC.





39





On February 15,
2007, MISO filed documents with the FERC to establish a market-based,
competitive ancillary services market. MISO contends that the filing will
integrate operating reserves into MISO's existing day-ahead and real-time
settlements process, incorporate opportunity costs into these markets, address
scarcity pricing through the implementation of a demand curve methodology,
foster demand response in the provision of operating reserves, and provide for
various efficiencies and optimization with regard to generation dispatch. The
filing also proposes amendments to existing documents to provide for the
transfer of balancing functions from existing local balancing authorities to
MISO. MISO will then carry out this reliability function as the NERC-certified
balancing authority for the MISO region. MISO is targeting implementation for
the second or third quarter of 2008. The FERC has established March 23, 2007, as
the date for interested parties to submit comments addressing the filing. The
filing has not yet been fully evaluated to assess its impact on our operations.





On February 16,
2007, the FERC issued a final rule that revises its decade-old open access
transmission regulations and policies. The FERC explained that the final rule is
intended to strengthen non-discriminatory access to the transmission grid,
facilitate FERC enforcement, and provide for a more open and coordinated
transmission planning process. The final rule will not be effective until 60
days after publication in the Federal Register. The final rule has not yet been
fully evaluated to assess its impact on our operations.




**9.**  **CAPITALIZATION:**





**(A)**
    **RETAINED
      EARNINGS-**





There are no
restrictions on retained earnings for payment of cash dividends on the Company's
common stock.





**(B)**
    **PREFERRED
      AND PREFERENCE STOCK-**





The Company
has five million authorized and unissued shares of $25 par value
preference stock.





**(C)**
    **LONG-TERM
      DEBT-**





The Company has a
first mortgage indenture under which it issues FMB, secured by a
direct first mortgage lien on substantially all of its property and franchises,
other than specifically excepted property. The Company has various debt
covenants under its financing arrangements. The most restrictive of the debt
covenants relate to the nonpayment of interest and/or principal on debt which
could trigger a default and the maintenance of minimum fixed charge ratios and
debt to capitalization ratios. There also exist cross-default provisions among
financing arrangements of FirstEnergy and the Company. Sinking fund requirements
for maturing long-term debt for the next five years are $30 million in
2007.





The Company's
obligations to repay certain pollution control revenue bonds are secured by
several series of FMB. Certain pollution control revenue bonds are entitled to
the benefit of noncancelable municipal bond insurance policies of
$49 million to pay principal of, or interest on, the pollution control
revenue bonds. To the extent that drawings are made under the policies, the
Company is entitled to a credit against its obligation to repay that bond. For
the pollution control revenue bonds issued in 2005, the Company pays annual fees
of 0.35% of the amount of the policy to the insurer. The Company is obligated to
reimburse the insurer for any drawings thereunder.





Certain secured
notes of the Company are entitled to the benefit of noncancelable municipal bond
insurance policies of $30 million to pay principal of, or interest on, the
applicable notes. To the extent that drawings are made under the policy, the
Company is entitled to a credit against its obligation to repay those notes. The
Company is obligated to reimburse the insurer for any drawings
thereunder.





The Company and CEI
have unsecured LOCs of approximately $ 194 million in
connection with the sale and leaseback of Beaver Valley Unit 2. The Company
and CEI are jointly and severally liable for the LOCs (see
Note 5).




**10.**  **ASSET
RETIREMENT OBLIGATIONS:**





The Company has
recognized legal obligations under SFAS 143 and FIN 47. SFAS 143
requires recognition of the fair value of a liability for an ARO in the period
in which it is incurred. The associated asset retirement costs are capitalized
as part of the carrying amount of the long-lived asset. Over time the
capitalized costs are depreciated and the present value of the ARO increases,
resulting in a period expense. Upon retirement, a gain or loss would be
recognized if the cost to settle the retirement obligation differs from the
carrying amount.





Pursuant to the
generation asset transfers on October 24, 2005 and December 16, 2005,
FGCO and NGC now own nearly all of the fossil and nuclear generation assets,
respectively, previously owned by the Company. The generating plant interests
transferred do not include leasehold interests of the Company that are currently
subject to sale and leaseback arrangements with non-affiliates (see
Note 13). As a result, only the ARO associated with sale and leaseback
arrangements remain with the Company.





40





In 2005, the Company
revised the ARO associated with Beaver Valley Unit 2, Davis-Besse and Perry
as a result of an updated decommissioning study. The present value of revisions
in the estimated cash flows associated with projected decommissioning costs
connected with the assets subject to sale and leaseback arrangements decreased
the ARO and corresponding plant asset for Beaver Valley Unit 2 by
$4 million.





The Company
continues to maintain the nuclear decommissioning trust funds associated with
the sale and leaseback arrangements that are legally restricted for purposes of
settling the nuclear decommissioning ARO. As of December 31, 2006, the fair
value of the decommissioning trust assets was $61 million.





FIN 47 provides
accounting standards for conditional retirement obligations associated with
tangible long-lived assets, requiring recognition of the fair value of a
liability for an ARO in the period in which it is incurred if a reasonable
estimate can be identified. FIN 47 states that an **** obligation exists
even though there may be uncertainty about timing or method of settlement
and **** further clarifies
SFAS 143, stating that the uncertainty surrounding the timing and method of
settlement when settlement is conditional on a future event occurring should be
reflected in the measurement of the liability not in the recognition of the
liability. Accounting for conditional ARO under FIN 47 is the same as
described above for SFAS 143. The effect on income as if FIN 47 had
been applied during 2004 is immaterial.





The following table
describes the changes to the ARO balances during 2006 and 2005:





**ARO
      Reconciliation**
    
    **2006**
    
    **2005*****(In
      millions)***Balance at
      beginning of year
    
    $
    25
    
    $
    194Transfers to
      FGCO and NCG
    
    
    -
    
    
    (157
    )Accretion
    
    
    2
    
    
    13Revisions in
      estimated cash flows
    
    
    -
    
    
    (26
    )FIN 47 ARO
      upon adoption
    
    
    -
    
    
    1Balance at end
      of year
    
    $
    27
    
    $
    25


**1** **1.**  **SHORT-TERM
BORROWINGS:**





Short-term
borrowings outstanding as of December 31, 2006, consisted of
$154 million of borrowings from affiliates. The Company and CEI sell
substantially all of their retail customer receivables to CFC, a wholly owned
subsidiary of CEI. In June 2005, the CFC receivable financing structure was
restructured from an off-balance-sheet transaction to an on-balance-sheet
transaction. Under the new structure, any borrowings under the facility appear
on CEI's consolidated balance sheet as short-term debt. The receivables
financing agreement expires on December 5, 2007. As of December 31, 2006,
the facility was undrawn.





On August 24,
2006,  the Company, FirstEnergy, OE,
Penn, CEI, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into
a new $2.75 billion five-year revolving credit facility, which replaced the
prior $2 billion credit facility. Subject to specified conditions, FirstEnergy
may request an increase in the total commitments available under the new
facility up to a maximum of $3.25 billion. Commitments under the new
facility are available until August 24, 2011, unless the lenders agree, at
the request of the Borrowers, to two 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 sublimit, as well as applicable
regulatory and other limitations. The Company's borrowing limit under the
facility is $250 million subject to applicable regulatory approval. The
average interest rate on short-term borrowings outstanding as of
December 31, 2006 and 2005 was 5.4% and 4.0%, respectively.




**12.**  **COMMITMENTS
AND CONTINGENCIES:**





**(A)**
    **NUCLEAR
      INSURANCE-******





The Price-Anderson
Act limits the public liability relative to a single incident at a nuclear power
plant to $10.8 billion. The amount is covered by a combination of private
insurance and an industry retrospective rating plan. Based on its leasehold
interest in Beaver Valley Unit 2, the Company's maximum potential
assessment under the industry retrospective rating plan (assuming the other
affiliate co-owners contribute their proportionate shares of any assessments
under the retrospective rating plan) would be $18.4 million per incident
but not more than $2.8 million in any one year for each
incident.





The Company is also
insured as to its respective interest in Beaver Valley Unit 2 under
policies issued to the operating company of the plant. Under these policies, up
to $2.75 billion is provided for property damage and decontamination and
decommissioning costs. The Company has also obtained approximately
$89.5 million of insurance coverage for replacement power costs for its
respective leasehold interest in Beaver Valley Unit 2. Under these
policies, the Company can be assessed a maximum of approximately
$2.8 million for incidents at any covered nuclear facility occurring during
a policy year which are in excess of accumulated funds available to the insurer
for paying losses.





41








The Company intends
to maintain insurance against nuclear risks as described above as long as it is
available. To the extent that replacement power, property damage,
decontamination, decommissioning, repair and replacement costs and other such
costs arising from a nuclear incident at any of the Company's plants exceed the
policy limits of the insurance in effect with respect to that plant, to the
extent a nuclear incident is determined not to be covered by the Company's
insurance policies, or to the extent such insurance becomes unavailable in the
future, the Company would remain at risk for such costs.





**(B)**
    **ENVIRONMENTAL
      MATTERS-**





The Company accrues
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 the Company's determination of
environmental liabilities and are accrued in the period that they become both probable
and reasonably estimable.





*Regulation of
Hazardous Waste*





The Company has been
named as a PRP 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 are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of
December 31, 2006, based on estimates of the total costs of cleanup, the
Company's proportionate responsibility for such costs and the financial ability
of other unaffiliated entities to pay. Total liabilities of approximately
$2.7 million have been accrued through December 31, 2006.





**(C)**
    **OTHER
      LEGAL PROCEEDINGS-**





*Power Outages
and Related Litigation*





On August 14,
2003, various states and parts of southern Canada experienced widespread power
outages. The outages affected approximately 1.4 million customers in
FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force's
final report in April 2004 on the outages concluded, among other things, that
the problems leading to the outages began in FirstEnergy's Ohio service area. Specifically, the
final report concluded, among other things, that the initiation of the
August 14, 2003 power outages resulted from an alleged failure of both
FirstEnergy and ECAR to assess and understand perceived inadequacies within the
FirstEnergy system; inadequate situational awareness of the developing
conditions; and a perceived failure to adequately manage tree growth in certain
transmission rights of way. The Task Force also concluded that there was a
failure of the interconnected grid's reliability organizations (MISO and PJM) to
provide effective real-time diagnostic support. The final report is publicly
available through the Department of Energy's Web site (www.doe.gov). We believe
that the final report does not provide a complete and comprehensive picture of
the conditions that contributed to the August 14, 2003 power outages and
that it does not adequately address the underlying causes of the outages. We
remain convinced that the outages cannot be explained by events on any one
utility's system. The final report contained 46 "recommendations to prevent or
minimize the scope of future blackouts." Forty-five of those recommendations
related to broad industry or policy matters while one, including subparts,
related to activities the Task Force recommended be undertaken by FirstEnergy,
MISO, PJM, ECAR, and other parties to correct the causes of the August 14,
2003 power outages. FirstEnergy implemented several initiatives, both prior to
and since the August 14, 2003 power outages, which were independently
verified by NERC as complete in 2004 and were consistent with these and other
recommendations and collectively enhance the reliability of its electric system.
FirstEnergy's implementation of these recommendations in 2004 included
completion of the Task Force recommendations that were directed toward
FirstEnergy. 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.








42





FirstEnergy
companies also are defending five separate complaint cases before the PUCO
relating to the August 14, 2003 power outages. Two cases were originally
filed in Ohio State courts but were subsequently dismissed for lack of subject
matter jurisdiction and further appeals were unsuccessful. In these cases the
individual complainants "three in one case and four in the other" sought to
represent others as part of a class action. The PUCO dismissed the class
allegations, stating that its rules of practice do not provide for class action
complaints. Three other pending PUCO complaint cases were filed by various
insurance carriers either in their own name as subrogees or in the name of their
insured. In each of these three cases, the carrier seeks reimbursement from
various FirstEnergy companies (and, in one case, from PJM, MISO and American
Electric Power Company, Inc., as well) for claims paid to insureds for damages
allegedly arising as a result of the loss of power on August 14, 2003. The
listed insureds in these cases, in many instances, are not customers of any
FirstEnergy company. A sixth case involving the claim of a non-customer seeking
reimbursement for losses incurred when its store was burglarized on
August 14, 2003 was dismissed. On March 7,
2006, the PUCO issued a ruling, consolidating all of the pending outage cases
for hearing; limiting the litigation to service-related claims by customers of
the Ohio operating companies; dismissing FirstEnergy as a defendant; and ruling
that the U.S.-Canada Power System Outage Task Force Report was not admissible
into evidence. In response to a
motion for rehearing filed by one of the claimants, the PUCO ruled on April 26,
2006 that the insurance company claimants, as insurers, may prosecute their
claims in their name so long as they also identify the underlying insured
entities and the Ohio utilities that provide their service. The PUCO denied all
other motions for rehearing. The plaintiffs in each case have since filed
amended complaints and the named FirstEnergy companies have answered and also
have filed a motion to dismiss each action. On September 27, 2006, the PUCO
dismissed certain parties and claims and otherwise ordered the complaints to go
forward to hearing. The cases have been set for hearing on October 16,
2007.





On October 10, 2006,
various insurance carriers refiled a complaint in Cuyahoga County Common Pleas
Court seeking reimbursement for claims paid to numerous insureds who allegedly
suffered losses as a result of the August 14, 2003 outages. All of the insureds
appear to be non-customers. The plaintiff insurance companies are the same
claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and
Penn were served on October 27, 2006. On January 18, 2007, the Court
granted the Companies' motion to dismiss the case. It is unknown whether or not
the matter will be further appealed. No estimate of potential liability is
available for any of these cases.





The Company
is vigorously defending these actions, but cannot predict the outcome of any of
these proceedings or whether any further regulatory proceedings or legal actions
may be initiated against the Company. Although unable to predict the impact of
these proceedings, if FirstEnergy or its subsidiaries were ultimately determined
to have legal liability in connection with these proceedings, it could have a
material adverse effect on the Company's financial condition, results of
operations and cash flows.





*Other Legal
Matters*





Various lawsuits,
claims (including claims for asbestos exposure) and proceedings related to the
Company's normal business operations are pending against the Company. The most
significant not otherwise discussed above are described herein.





On October 20,
2004, we were notified by the SEC that the previously disclosed informal inquiry
initiated by the SEC's Division of Enforcement in September 2003 relating to the
restatements in August 2003 of previously reported results by FirstEnergy and
the Ohio Companies, and the Davis-Besse extended outage, have become the subject
of a formal order of investigation. The SEC's formal order of investigation also
encompasses issues raised during the SEC's examination of FirstEnergy and the
Companies under the now repealed PUHCA. Concurrent with this notification, we
received a subpoena asking for background documents and documents related to the
restatements and Davis-Besse issues. On December 30, 2004, we received a
subpoena asking for documents relating to issues raised during the SEC's PUHCA
examination. On August 24, 2005, additional information was requested
regarding Davis-Besse-related disclosures, which has been provided. We have
cooperated fully with the informal inquiry and continue to do so with the formal
investigation.





If it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
or are otherwise made subject to liability based on any of the above matters, it
could have a material adverse effect on the Company's financial condition,
results of operations and cash flows.





**13.**
    **FIRSTENERGY
      INTRA-SYSTEM GENERATION ASSET
  TRANSFERS:**





In 2005, the Ohio
Companies entered into certain agreements implementing a series of intra-system
generation asset transfers that were completed in the fourth quarter of 2005.
The asset transfers resulted in the respective undivided ownership interests of
the Ohio Companies and Penn in FirstEnergy's nuclear and non-nuclear generation
assets being owned by NGC and FGCO, respectively. The generating plant interests
transferred do not include the Company's leasehold interests in certain of the
plants that are currently subject to sale and leaseback arrangements with
non-affiliates.








43





On October 24,
2005, the Company completed the intra-system transfer of non-nuclear generation
assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility
Lease with the Ohio Companies, leased, operated and maintained the non-nuclear
generation assets that it now owns. The asset transfers were consummated
pursuant to FGCO's purchase option under the Master Facility Lease.





The difference
(approximately $22.9 million) between the purchase price specified in the Master
Facility Lease and the net book value at the date of transfer was credited to
equity. FGCO also assumed certain assets and liabilities relating to the
purchased units. As consideration, FGCO delivered to the Company a promissory
note of approximately $101.0 million that is secured by a lien on the units
purchased, bears interest at a rate per annum based on the weighted cost of TE's
long-term debt (4.38%) and matures twenty years after the date of issuance. FGCO
may pre-pay a portion of the promissory note through refunding from time to time
of TE's outstanding pollution control debt. The timing of any refunding will be
subject to market conditions and other factors.





On December 16,
2005, the Company completed the intra-system transfer of its respective
ownership in the nuclear generation assets to NGC through a sale at net book
value. FENOC continues to operate and maintain the nuclear generation
assets.





The purchase price
of the generation assets was the net book value as of September 30, 2005. The
difference (approximately $22.1 million) between the purchase price of the
generation assets and the net book value at the date of transfer was credited to
equity. NGC also assumed TE's interest in associated decommissioning trust
funds, other related assets and other liabilities associated with the
transferred assets. In addition, TE received a promissory note from NGC in the
principal amount of approximately $726.1 million, representing the net book
value of the contributed assets as of September 30, 2005, less other
liabilities assumed. The note bears interest at a rate per annum based on TE's
weighted average cost of long-term debt (4.38%), matures twenty years from the
date of issuance, and is subject to prepayment at any time, in whole or in part,
by NGC. In December 2006, the Company recorded a purchase price adjustment of
$130.8 million for the nuclear generation asset transfer to adjust
intercompany notes and equity accounts to reflect a change in the agreed upon
value for the asset retirement obligations that were assumed by
NGC.





These transactions
were undertaken pursuant to the Ohio Companies' restructuring plans that were
approved by the PUCO under applicable Ohio electric utility restructuring
legislation. Consistent with the restructuring plans, generation assets that had
been owned by the Ohio Companies were required to be separated from the
regulated delivery business of those companies through transfer or sale to a
separate corporate entity. The transactions essentially completed the
divestitures of owned assets contemplated by the restructuring plans by
transferring the ownership interests to NGC and FGCO without impacting the
operation of the plants.





The transfers are
expected to affect the Company's near-term future results with reductions in
revenues and expenses. Revenues will be reduced due to the termination of the
sale of its nuclear-generated KWH and the lease of its non-nuclear generation
assets arrangements to FES. The Company's expenses will be lower due to the
nuclear fuel and operating costs assumed by NGC as well as depreciation and
property tax expenses assumed by FGCO and NGC related to the transferred
generating assets. The Company will retain the generated KWH sales arrangement
and the portion of expenses related to its retained leasehold interests in the
Bruce Mansfield Plant and Beaver Valley Unit 2. In addition, the Company will
receive interest income from associated company notes receivable from FGCO and
NGC for the transfer of its generation net assets. FES will continue to provide
the Company's PLR requirements under revised purchased power arrangements for a
three-year period beginning January 1, 2006 (see Note 8 - Regulatory
Matters).





The following table
provides the value of assets transferred in 2005 along with the related
liabilities:





**Assets
      Transferred (In millions)**Property,
      plant and equipment
    
    $
    651Other property
      and investments
    
    
    287Current
      assets
    
    
    43Deferred
      charges
    
    
    2$
    983**Liabilities
      Related to Assets Transferred**Long-term
      debt
    
    $
    -Current
      liabilities
    
    
    -Noncurrent
      liabilities
    
    
    178$
    178**Net
      Assets Transferred**
    
    $
    805








44




**14.**  **NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS:**





*SFAS 159 -
      The Fair Value Option for Financial Assets and Financial Liabilities -
      Including an amendment of FASB Statement No.
  115*





In February 2007,
FASB issued SFAS 159, which provides companies with an option to report selected
financial assets and liabilities at fair value. The Standard requires companies
to provide additional information that will help investors and other users of
financial statements to more easily understand the effect of the company's
choice to use fair value on its earnings. The Standard also requires companies
to display the fair value of those assets and liabilities for which the company
has chosen to use fair value on the face of the balance sheet. This guidance
does not eliminate disclosure requirements included in other accounting
standards, including requirements for disclosures about fair value measurements
included in SFAS 157, *Fair Value
Measurements,* and SFAS 107, *Disclosures
about Fair Value of Financial Instruments.* The Company is
currently evaluating the impact of this Statement on its financial
statements.





*SFAS 157 - "Fair
Value Measurements"*





In September 2006,
the FASB issued SFAS 157, that establishes how companies should measure fair
value when they are required to use a fair value measure for recognition or
disclosure purposes under GAAP. This Statement addresses the need for increased
consistency and comparability in fair value measurements and for expanded
disclosures about fair value measurements. The key changes to current practice
are: (1) the definition of fair value which focuses on an exit price rather than
entry price; (2) the methods used to measure fair value such as emphasis that
fair value is a market-based measurement, not an entity-specific measurement, as
well as the inclusion of an adjustment for risk, restrictions and credit
standing; and (3) the expanded disclosures about fair value measurements. This
Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years.
The Company is currently evaluating the impact of this Statement on its
financial statements.





*FIN 48 - "Accounting
for Uncertainty in Income Taxes - an interpretation of FASB Statement No.
109"*





In June 2006, the
FASB issued FIN 48 which clarifies the accounting for uncertainty in income
taxes recognized in an enterprise's financial statements in accordance with FASB
Statement No. 109, "Accounting for Income Taxes." This interpretation prescribes
a recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken on a
tax return. This interpretation 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 will be a two-step process. The first step will determine if it
is more likely than not that a tax position will be sustained upon examination
and should therefore be recognized. The second step will measure a tax position
that meets the more likely than not recognition threshold to determine the
amount of benefit to recognize in the financial statements. This interpretation
is effective for fiscal years beginning after December 15, 2006. The Company
does not expect this Statement to have a material impact on its financial
statements.




**15.**  **SUMMARY OF
QUARTERLY FINANCIAL DATA (UNAUDITED):**





The following
summarizes certain consolidated operating results by quarter for 200 6 and
2005:





**Three
      Months Ended**
    
    **March
      31,**
      **2006**
    
    **June
      30,**
      **2006**
    
    **September
      30, 2006**
    
    **December
      31, 2006*****(In
      millions)***Revenues
    
    $
    218.0
    
    $
    225.6
    
    $
    262.8
    
    $
    221.6Expenses
    
    
    174.8
    
    
    176.3
    
    
    219.1
    
    
    207.3Operating
      Income
    
    
    43.2
    
    
    49.3
    
    
    43.7
    
    
    14.3Other Income
      (Expense)
    
    
    3.0
    
    
    3.0
    
    
    3.1
    
    
    (0.4
    )Income Before
      Income Taxes
    
    
    46.2
    
    
    52.3
    
    
    46.8
    
    
    13.9Income
      Taxes
    
    
    17.2
    
    
    19.9
    
    
    17.7
    
    
    5.1Net
      Income
    
    $
    29.0
    
    $
    32.4
    
    $
    29.1
    
    $
    8.8Earnings on
      Common Stock
    
    $
    27.8
    
    $
    31.2
    
    $
    28.0
    
    $
    3.0





**Three
      Months Ended**
    
    **March
      31,**
      **2005**
    
    **June
      30,**
      **2005**
    
    **September
      30, 2005**
    
    **December
      31, 2005*****(In
      millions)***Revenues
    
    $
    241.8
    
    $
    259.1
    
    $
    286.9
    
    $
    252.4Expenses
    
    
    240.6
    
    
    224.1
    
    
    230.2
    
    
    213.1Operating
      Income
    
    
    1.2
    
    
    35.0
    
    
    56.7
    
    
    39.3Other Income
      (Expense)
    
    
    (1.9
    )
    
    2.3
    
    
    13.9
    
    
    3.5Income (Loss)
      Before Income Taxes
    
    
    (0.7
    )
    
    37.3
    
    
    70.6
    
    
    42.8Income Taxes
      (Benefit)
    
    
    (1.1
    )
    
    29.6
    
    
    28.4
    
    
    16.9Net
      Income
    
    $
    0.4
    
    $
    7.7
    
    $
    42.2
    
    $
    25.9Earnings
      (Loss) on Common Stock
    
    $
    (1.8
    )
    $
    5.5
    
    $
    40.5
    
    $
    24.2









45