**THE
CLEVELAND ELECTRIC** **ILLUMINATING COMPANY**





**200** **6 ANNUAL
REPORT TO STOCKHOLDERS**











The Cleveland
Electric Illuminating 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 1,600 square miles in northeastern
Ohio. It also engages in the sale, purchase and interchange of electric energy
with other electric companies. The area it serves has a population of
approximately 1.9 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
    26-46








**GLOSSARY
OF TERMS**







The following
abbreviations and acronyms are used in this report to identify The Cleveland
Electric Illuminating Company and its affiliates:





ATSI
    American
      Transmission Systems, Inc., owns and operates transmission
      facilitiesCEI
    The Cleveland
      Electric Illuminating CompanyCFC
    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
  utilityShippingport
    Shippingport
      Capital Trust, a special purpose entity created by CEI and TE in
      1997TE
    The Toledo
      Edison Company, an affiliated Ohio electric utilityThe 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 Coordination AgreementEPACT
    Energy Policy
      Act of 2005FASB
    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"FMB
    First Mortgage
      BondsFitch
    Fitch Ratings,
      Ltd.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
      GenerationMW
    MegawattsNERC
    North American
      Electric Reliability CorporationNOPR
    Notice of
      Proposed RulemakingOCC
    Ohio
      Consumers' CouncilOCI
    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
      PlanRSP
    Rate
      Stabilization PlanRTC
    Regulatory
      Transition ChargeS&P
    Standard &
      Poor's Ratings Service





i
 **GLOSSARY
OF TERMS, Cont'd.**








SEC
    United States
      Securities and Exchange CommissionSFAC
    Statement of
      Financial Accounting ConceptsSFAC
      7
    SFAC No. 7,
      "Using Cash Flow Information and Present Value in Accounting
      Measurements"SFAS
    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 Pension 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 Statement No. 115"VIE
    Variable
      Interest Entity










ii











**Report of
Independent Registered Public Accounting Firm**


























To the Stockholder
and Board of Directors of


The Cleveland
Electric Illuminating 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
Cleveland Electric Illuminating Company and its subsidiaries 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. As discussed in Note 2(G) and Note 10 to the
consolidated financial statements, the Company changed its method of accounting
for conditional asset
retirement obligations as of December 31, 2005 .














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
      CLEVELAND ELECTRIC ILLUMINATING COMPANY****SELECTED
      FINANCIAL DATA****For
      the Years Ended December 31,**
    
    **2006**
    
    **2005**
    
    **2004**
    
    **2003**
    
    **2002*****(Dollars
      in thousands)*****GENERAL
      FINANCIAL INFORMATION:**Revenues
    
    $
    1,769,708
    
    $
    1,868,161
    
    $
    1,808,485
    
    $
    1,719,739
    
    $
    1,843,671Operating
      Income
    
    $
    526,561
    
    $
    435,898
    
    $
    439,905
    
    $
    255,615
    
    $
    306,152Income
      Before Cumulative Effect of aChange
      in Accounting Principle
    
    $
    306,051
    
    $
    231,058
    
    $
    236,531
    
    $
    197,033
    
    $
    136,952Net
      Income
    
    $
    306,051
    
    $
    227,334
    
    $
    236,531
    
    $
    239,411
    
    $
    136,952Earnings
      on Common Stock
    
    $
    306,051
    
    $
    224,416
    
    $
    229,523
    
    $
    231,885
    
    $
    121,262Total
      Assets
    
    $
    5,563,498
    
    $
    6,101,670
    
    $
    6,675,377
    
    $
    6,758,501
    
    $
    6,500,238**CAPITALIZATION
      AS OF DECEMBER 31:**Common
      Stockholder's Equity
    
    $
    1,468,903
    
    $
    1,942,074
    
    $
    1,853,561
    
    $
    1,778,827
    
    $
    1,200,001Preferred
      Stock-Not
      Subject to Mandatory Redemption
    
    
    -
    
    
    -
    
    
    96,404
    
    
    96,404
    
    
    96,404Subject
      to Mandatory Redemption
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    105,021Long-Term
      Debt and Other Long-Term Obligations
    
    
    1,805,871
    
    
    1,939,300
    
    
    1,970,117
    
    
    1,884,643
    
    
    1,975,001Total
      Capitalization
    
    $
    3,274,774
    
    $
    3,881,374
    
    $
    3,920,082
    
    $
    3,759,874
    
    $
    3,376,427**CAPITALIZATION
      RATIOS:**Common
      Stockholder's Equity
    
    
    44.9
    %
    
    50.0
    %
    
    47.3
    %
    
    47.3
    %
    
    35.5
    %Preferred
      Stock-Not
      Subject to Mandatory Redemption
    
    
    -
    
    
    -
    
    
    2.4
    
    
    2.6
    
    
    2.9Subject
      to Mandatory Redemption
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    3.1Long-Term
      Debt and Other Long-Term Obligations
    
    
    55.1
    
    
    50.0
    
    
    50.3
    
    
    50.1
    
    
    58.5Total
      Capitalization
    
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %**DISTRIBUTION
      KWH DELIVERIES (Millions):**Residential
    
    
    5,441
    
    
    5,699
    
    
    5,264
    
    
    5,216
    
    
    5,370Commercial
    
    
    4,784
    
    
    4,998
    
    
    4,817
    
    
    4,690
    
    
    4,628Industrial
    
    
    8,898
    
    
    9,041
    
    
    9,006
    
    
    8,908
    
    
    8,921Other
    
    
    170
    
    
    172
    
    
    162
    
    
    169
    
    
    167Total
    
    
    19,293
    
    
    19,910
    
    
    19,249
    
    
    18,983
    
    
    19,086**CUSTOMERS
      SERVED:**Residential
    
    
    674,392
    
    
    675,071
    
    
    674,292
    
    
    669,337
    
    
    677,095Commercial
    
    
    85,015
    
    
    85,033
    
    
    81,093
    
    
    80,596
    
    
    71,893Industrial
    
    
    2,270
    
    
    2,304
    
    
    2,211
    
    
    2,318
    
    
    4,725Other
    
    
    295
    
    
    295
    
    
    293
    
    
    286
    
    
    289Total
    
    
    761,972
    
    
    762,703
    
    
    757,889
    
    
    752,537
    
    
    754,002**NUMBER
      OF EMPLOYEES**
    
    
    943
    
    
    949
    
    
    905
    
    
    949
    
    
    974







2





**T** **HE CLEVELAND
ELECTRIC ILLUMINATING 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, we have continued the fossil generation KWH sales
arrangement with FES 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 Regulatory Matters).





The effects on our
results of operations in 2006 compared to 2005 from the generation asset
transfers (also reflecting our retained leasehold interests discussed above) are
summarized in the following table:





**Intra-System
      Generation Asset Transfers****Income
      Statement Effects**
    
    **Increase**
      **(Decrease)*****(In
      millions)***Revenues:Non-nuclear generating units rent
    (a)
    $
    (49)Nuclear-generated KWH sales
    (b)
    
    (217)Total - Revenues Effect
    
    
    (266)Expenses:Fuel costs -
      nuclear
    (c)
    
    (34)Nuclear operating costs
    (c)
    
    (174)Provision for depreciation
    (d)
    
    (57)General taxes
    (e)
    
    (15)Total -
      Expenses Effect
    
    
    (280)Operating
      Income Effect
    
    
    14Other Income
      (Expense):Interest income from notes receivable
    (f)
    
    57Nuclear decommissioning trust earnings
    (g)
    
    (31)Interest expense
    (h)
    
    12Capitalized interest
    (i)
    
    (1)Total - Other Income Effect
    
    
    37Income Before
      Income Taxes Effect
    
    
    51Income
      Taxes
    (j)
    
    21Net Income
      Effect
    
    $
    30(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.(i) Reduction
      of allowance for borrowed funds used during construction on nuclear
      capital expenditures.(j) Income tax
      effect of the above adjustments.





**Results
of Operations**





Earnings on common
stock in 2006 increased to $306 million from $224 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 $52 million primarily due to higher revenues and decreased
amortization of regulatory assets, partially offset by increased purchased power
costs.





Earnings on common
stock in 2005 decreased to $224 million from $230 million in 2004.
Earnings on common stock in 2005 included an after-tax loss of $4 million
from the cumulative effect of a change in accounting
principle due to the adoption of FIN 47. The $5 million decrease in
income before the cumulative effect in 2005 resulted principally from higher
nuclear and other operating costs and higher fuel and purchased power costs,
partially offset by higher operating revenues and other income. Increased
nuclear operating costs in 2005 compared to 2004 were due to an inspection
outage at Davis-Besse and two nuclear refueling outages in 2005.





4





*Revenues*





Revenues decreased
by $98 million or 5.3% in 2006 compared to 2005. Excluding the
effects of the generation asset transfers displayed above, revenues increased
$168 million primarily due to a $427 million increase in retail generation
sales revenues and a $106 million reduction in customer shopping incentives,
partially offset by a $246 million decrease in distribution revenues and a $121
million decrease in wholesale sales.





Wholesale revenues
from non-affiliates decreased by $72 million 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.





Wholesale sales to
FES decreased by $49 million in 2006 due primarily to the termination of an
arrangement to sell power purchased from TE related to its leasehold interest in
Beaver Valley Unit 2 . Subsequent to the
generation asset transfer, we now retain this purchased power from TE to meet a
portion of our retail PLR obligation.





Revenues increased
by $60 million or 3.3% in 2005 compared with 2004. Higher revenues resulted
principally from increased generation sales revenue from franchise customers of
$33 million and a $33 million increase in revenues from distribution
deliveries. Under the Ohio transition plan, we provided incentives to customers
to encourage switching to alternative energy providers (shopping) -
$7 million of additional credits were provided to customers in 2005
compared with 2004. These revenue reductions were deferred for future recovery
under our transition plan and did not affect earnings (see Note
2(A)).





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





**Changes
      in Generation KWH Sales**
    
    **2006**
    
    **2005****Increase
      (Decrease)**Electric
      Generation:Retail
    
    
    46.7
    %
    
    4.9
    %Wholesale
      *
    
    
    (50.6
    )%
    
    (2.7
    )%**Net
      Change in Generation Sales**
    
    
    9.3
    %
    
    0.5
    %





**Changes
      in Generation Revenues**
    
    **2006**
    
    **2005****Increase
      (Decrease)**
    
    ***(In
      millions)***Retail
      Generation:Residential
    
    $
    165
    
    $
    11Commercial
    
    
    150
    
    
    5Industrial
    
    
    112
    
    
    17Total Retail
      Generation
    
    
    427
    
    
    33Wholesale*
    
    
    (121
    )
    
    26**Net
      Increase in Generation Revenues**
    
    **$**
    **306**
    
    **$**
    **59**





*Excludes impact of
generation asset transfers related to nuclear generated KWH sales.





Increased retail
generation revenues in 2006 compared to 2005 (as shown in the table above) were
due to higher unit prices and increased KWH sales. The higher unit prices for
generation reflected the rate stabilization charge that became effective in the
first quarter of 2006 under provisions of the RSP and RCP. The increase in
generation KWH sales resulted from decreased customer shopping. Generation
services provided by alternative suppliers as a percent of total sales delivered
in our service area decreased by: residential - 55.5 percentage points,
commercial - 40.5 percentage points and industrial - 8.3 percentage points. The
decreased shopping resulted from certain alternative energy suppliers
terminating their supply arrangements with our shopping customers in the fourth
quarter of 2005.





An increase in
retail generation revenues to residential and commercial customers of
$11 million and $5 million, respectively, in 2005 reflected higher
generation KWH sales due to decreases in shopping by residential and commercial
customers of 6.0 percentage points and 0.6 percentage point, respectively. A
$17 million increase in the industrial sector was primarily due to higher unit
prices partially offset by slightly lower KWH sales. Wholesale sales revenue
increased by $1 million due to a $26 million increase (28.5% KWH
increase) in MSG sales to unaffiliated wholesale customers partially offset by a
$25 million decrease in sales (5.6% KWH decrease) to FES.





5





Changes in
distribution KWH deliveries and revenues in 2006 and
2005, compared to the prior year, are summarized in the following
tables.





**Changes
      in Distribution KWH Sales**
    
    **2006**
    
    **2005****Increase
      (Decrease)**Distribution
      Deliveries:Residential
    
    (4.5)
    %
    8.3
    %Commercial
    
    (4.3)
    %
    3.8
    %Industrial
    
    (1.6)
    %
    0.4
    %**Net
      Change in Distribution Deliveries**
    
    **(3.1)**
    %
    **3.4**
    %





**Changes
      in Distribution Revenues**
    
    **2006**
    
    **2005****Increase
      (Decrease)**
    
    ***(In
      millions)***Residential
    
    $
    (59)
    
    $
    31Commercial
    
    
    (97)
    
    
    3Industrial
    
    
    (90)
    
    
    (1)**Net
      Change in Distribution Revenues**
    
    **$**
    **(246)**
    
    **$**
    **33**








Lower distribution
revenues, shown in the table above, for 2006 primarily reflected
lower unit prices and decreased KWH deliveries. The lower unit prices reflected
the completion of the generation-related transition cost recovery under our
transition plan in 2005, partially offset by increased transmission rates to
recover MISO costs beginning in 2006 (see Outlook -- Regulatory Matters). The lower
KWH distribution deliveries to residential and commercial customers were
primarily due to milder weather conditions in 2006 compared to 2005.





Revenues from
distribution throughput increased by $33 million in 2005 compared with
2004, as total distribution deliveries increased by 3.4% in 2005. The increase
in revenues was primarily due to higher distribution deliveries to residential
and commercial customers, in part due to warmer summer temperatures, partially
offset by lower unit prices in both sectors. Industrial revenues were down
slightly as lower unit prices were partially offset by higher distribution
deliveries.





*Expenses*





Total expenses
increased by $91 million in 2006 and $64 million in 2005 from the prior
year. The change in 2006 was impacted by the effects of the generation
asset transfers 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
      costs
    
    $
    (2
    )
    $
    8Purchased
      power costs
    
    
    178
    
    
    14Nuclear
      operating costs
    
    
    -
    
    
    26Other
      operating costs
    
    
    (10
    )
    
    29Provision for
      depreciation
    
    
    (7
    )
    
    (4
    )Amortization
      of regulatory assets
    
    
    (100
    )
    
    31Deferral of
      new regulatory assets
    
    
    35
    
    
    (46
    )General
      taxes
    
    
    (3
    )
    
    6**Net
      increase in expenses**
    
    $
    91
    
    $
    64





Higher purchased
power costs in 2006 as compared to 2005 resulted from increased KWH purchases to
meet our higher retail generation sales requirements and higher unit prices
associated with our current power supply agreement with FES (see
Outlook-Regulatory Matters). Lower other operating costs in 2006 compared with
2005 reflected the absence in 2006 of transmission expenses related to the 2005
competitive retail energy supplier reimbursements which were discontinued at the
end of 2005. In addition, decreased employee and contractor costs resulted from
lower storm-related expenses and higher accelerated reliability improvement
projects that were capitalized in 2006 compared to 2005. Partially offsetting
the lower other operating costs were increased transmission expenses related to
MISO Day 2 operations that began on April 1, 2005.








6





Excluding the
effects of the generation asset transfers, the depreciation decrease in 2006
compared to 2005 was primarily attributable to a second quarter 2006 pretax
credit adjustment of $6.5 million ($4 million net of tax) applicable to prior
periods. Lower amortization of regulatory assets in 2006 reflected the
completion of generation-related transition cost amortization under our
transition plan, partially offset by the amortization of deferred MISO costs
that are being recovered in 2006. The decreased deferral of new regulatory
assets in 2006 compared with 2005 was primarily due to the termination of the
shopping incentive deferrals ($106 million) and lower MISO cost deferrals ($26
million), partially offset by the deferrals of distribution costs
($57 million) and fuel costs ($39 million) under the RCP. The deferral of
interest on the unamortized shopping incentive balances continues under the
RCP.





Higher fuel costs in
2005 compared to 2004 were primarily due to increased fossil fuel expenses
associated with higher fossil generation levels. Higher purchased power costs in
2005 compared to 2004 reflected higher KWH purchases, partially offset by lower
unit costs. Higher nuclear operating costs in 2005 compared with 2004, were due
to the 2005 nuclear refueling and maintenance outages at the Perry Plant, the
nuclear refueling outage at Beaver Valley Unit 2 (these units did not
experience outages in 2004) and a scheduled 23-day mid-cycle inspection outage
at the Davis-Besse nuclear plant. Higher other operating costs were primarily
due to transmission expenses related to MISO Day 2 transactions that began
on April 1, 2005.





The decrease in
depreciation in 2005 compared to 2004 was primarily due to the non-nuclear
generation transfer that occurred on October 24,
2005 (see Note 13). Higher amortization of regulatory assets in 2005
compared to the prior year was primarily due to increased amortization of
transition regulatory assets being recovered under the RSP. Increases in the
deferral of regulatory assets in 2005 from 2004 were primarily a result of
higher shopping incentive deferrals ($7 million) and associated interest
($9 million), and the PUCO-approved MISO cost deferrals ($29 million)
and associated interest ($1 million).





Excluding the
effects of the generation asset transfers, general taxes decreased
$3 million in 2006 primarily due to lower Ohio KWH tax. General taxes
increased $6 million in 2005 compared to 2004 primarily due to higher
property taxes.





*Other
Income*





The change in other
income in 2006 reflects the generation asset transfers discussed above.
Excluding the effects of the asset transf er, other income
decreased by $17 million in 2006 and was primarily the result of higher interest
expense due to the absence of refinancing cost reductions in 2006. Other income
increased by $13 million in 2005, primarily due to higher realized gains on
nuclear decommissioning trust investments. Net interest charges continued to
trend lower, decreasing by $4 million in 2005, due to our debt reduction
program. Interest on long-term debt was lower due to redemptions of
$2 million and the refinancing of $143 million of pollution control
notes during 2005.





*Cumulative
Effect of a Change in Accounting Principle* **





Results in 2005
include an after-tax charge of $4 million recorded upon the adoption of
FIN 47 in December 2005. We identified applicable legal obligations as
defined under the new standard at our retired generating units, substation
control rooms, service center buildings, line shops and office buildings,
identifying asbestos as the primary conditional ARO. We recorded a conditional
ARO liability of $7 million (including accumulated accretion for the period
from the date the liability was incurred to the date of adoption), an asset
retirement cost of $2 million (recorded as part of the carrying amount of
the related long-lived asset), and accumulated depreciation of $2 million.
We charged regulatory liabilities for $1 million upon adoption of
FIN 47 for the transition amounts related to establishing the ARO for
asbestos removal from substation control rooms and service center buildings. The
remaining cumulative effect adjustment for unrecognized depreciation and
accretion of $6 million was charged to income ($4 million, net of tax)
for the year ended December 31, 2005.





*Income
Taxes*





Income taxes
increased by $ 36 million in
2006 compared to 2005. Excluding the effects of the generation asset transfer,
income taxes increased by $15 million in 2006. The increase in 2006 was
primarily due to an increase in taxable income and by the absence in 2006 of $1
million of reduced income tax expenses from the implementation of Ohio tax
legislation changes in the second quarter of 2005. Income taxes increased $15
million in 2005 primarily due to a reserve for potential federal income tax
audit adjustments.








7





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 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 $4 million, which was partially offset by the initial
phase-out of the Ohio income-based franchise tax, which reduced income taxes by
approximately $5 million in 2005.





*Preferred Stock
Dividend Requirements*





Preferred stock
dividend requirements decreased by $3 million in 2006 compared to 2005, as a
result of the redemption of our remaining outstanding preferred stock in 2005.
Preferred stock dividend requirements decreased by $4 million in 2005 from
2004 principally due to optional preferred stock redemptions of
$100 million in 2005.





**Capital
Resources and Liquidity**





During 2007, we
expect to meet our contractual obligations with cash from operations, short-term
credit arrangements and funds from the capital markets. Thereafter, we expect to
use a combination of cash from operations and funds from the capital markets.





*Changes in Cash
Position*





As of December 31,
2006, we had $221,000 of cash and cash equivalents, compared with $207,000 as of
December 31, 2005. The major sources of changes in these balances are summarized
below.





*Cash Flows from
Operating Activities*





Our net cash
provided from operating activities was $419 million in 2006,
$148 million in 2005 and $222 million in 2004, summarized as follows:





**Operating
      Cash Flows**
    
    **2006**
    
    **2005**
    
    **2004****(In
      millions)**Net
      Income
    
    **$**
    306
    
    **$**
    227
    
    **$**
    237Net non-cash
      charges (credits)
    
    
    (43
    )
    
    197
    
    
    206Pension trust
      contribution*
    
    
    7
    
    
    (63
    )
    
    (19
    )Working
      capital and other
    
    
    149
    
    
    (213
    )
    
    (202
    )Net cash
      provided from operating activities
    
    **$**
    419
    
    **$**
    148
    
    **$**
    222





*  Pension trust
contributions in 2005 and 2004 are net of $30 million and $13 million of


related current year
cash income tax benefits, respectively. The $7 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 increased by $271 million in 2006 compared to 2005.
The increase of $79 million from net income and the decrease of
$240 million in net non-cash charges are described above under "Results of
Operations." The tax benefit in 2006 relating to the January 2007 pension
contribution and the absence in 2006 of the pension trust contribution in 2005
also contributed to the increase. The largest factors affecting the
$362 million increase in working capital and other operating cash flows for
2006 are changes in accounts payable of $376 million primarily for the
repurchase of $300 million in common stock from FirstEnergy in December 2006.
Partially offsetting the increase is the absence of funds received in 2005 for
prepaid electric service under the Energy for Education Program.





8








Net cash provided
from operating activities decreased by $74 million in 2005 compared to 2004. The
decreases of $10 million from net income and $9 million in net non-cash
charges are described above under "Results of Operations." There was a
$44 million decrease in after-tax voluntary pension plan contributions and
an $11 million decrease from working capital and other cash flows. The change in
working capital and other operating cash flows was principally due to a decrease
in cash provided from the settlement of receivables of $141 million, partially
offset by increases in cash of $65 million from reduced tax payments and $68
million of funds received in 2005 for prepaid electric service under the Energy
for Education Program.





*Cash Flows from
Financing Activities*





In 2006, 2005 and
2004, net cash used for financing activities was $704 million,
$71 million and $98 million, respectively, primarily reflecting the
new issues and redemptions shown below.





**Securities
      Issued or Redeemed**
    
    **2006**
    
    **2005**
    
    **2004*****(In
      millions)******New
      Issues:***Pollution
      Control Notes
    
    $
    -
    
    $
    141
    
    $
    125Unsecured
      Notes
    
    
    296
    
    
    -
    
    
    -***Redemptions:***Pollution
      Control Notes
    
    $
    376
    
    $
    147
    
    $
    46Secured
      Notes
    
    
    -
    
    
    -
    
    
    288Common
      Stock
    
    
    300
    
    
    -
    
    
    -Preferred
      Stock
    
    
    -
    
    
    102
    
    
    1Other
    
    
    -
    
    
    1
    
    
    1$
    676
    
    $
    250
    
    $
    336Short-term
      borrowings (repayments), net
    
    $
    (143
    )
    $
    156
    
    $
    290





Net cash used for
financing activities increased by $633 million in 2006 compared to 2005. The
increase in funds used for financing activities primarily resulted from a
$570 million increase in net preferred stock and debt redemptions and the
absence of a $75 million equity contribution from FirstEnergy in 2005, partially
offset by an $11 million decrease in common stock dividend payments to
FirstEnergy.





We had $27 million
of cash and temporary investments (which included short-term notes receivable
from associated companies) and approximately $218 million of short-term
indebtedness as of December 31, 2006. We have obtained authorization from the
PUCO to incur short-term debt of up to $600 million (including the bank
facility and utility money pool described below).





At the end of 2006,
we had the capability to issue $523 million of additional FMB on the basis of
property additions and retired bonds under the terms of our mortgage indenture.
The issuance of FMB is 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 under the indenture to
incur additional secured debt not otherwise permitted by a specified exception
of up to $491 million as of December 31, 2006. We have no restrictions on
the issuance of preferred stock.





CFC is our wholly
owned subsidiary whose borrowings are secured by customer accounts receivable
purchased from us and TE. CFC can borrow up to $200 million under a receivables
financing arrangement. As a separate legal entity with separate creditors, CFC
would have to satisfy its obligations to creditors before any of its remaining
assets could be made available to us. As of December 31, 2006, the facility was
undrawn.





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 amount, 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 during 2006 was 5.22%.





9








On August 24, 2006,
we, FirstEnergy, OE, Penn, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as
Borrowers, have 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
approvals.





Under the revolving
credit facility, borrowers may request the issuance of letters of credit
expiring up to one year from the date of issuance. The stated amount of
outstanding LOC will count against total commitments available under the
facility and against the applicable borrower's borrowing sub-limit. Total unused
borrowing capability under existing credit facilities and accounts receivable
financing facilities was $450 million as of December 31, 2006.





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
57%.





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





Our access to the
capital markets and the costs of financing are dependent on the ratings of its
securities and the securities of FirstEnergy. The ratings outlook from S&P
on all such 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**CEI**
    
    
    Senior
      secured
    
    
    BBB
    
    
    Baa2
    
    
    BBBSenior
      unsecured
    
    
    BBB-
    
    
    Baa3
    
    
    BBB-





In April, May and
December of 2006, pollution control notes totaling $376 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 $353
million of remaining pollution control notes are subject to transfer.





On December 11,
2006, we issued $300 million of 5.95% senior unsecured notes due 2036. The
proceeds of the offering were used to repurchase approximately $300 million of
our common stock from FirstEnergy.





*Cash Flows from
Investing Activities*





Net cash provided
from investing activities increased by $362 million in 2006 compared to 2005.
The change was primarily due to increased loan repayments from associated
companies, the absence of net investments in nuclear decommissioning trust funds
due to the nuclear generation asset transfer and lower expenditures for property
additions partially offset by decreased collection of principal on long-term
notes receivable.





Net cash used for
investing activities decreased $72 million in 2005 compared to 2004. This
decrease was primarily due to increased loan activity with associated companies.
The $466 million increase in collection of principal amounts on long-term notes
receivable in 2005 included a $375 million repayment from NGC and $91 million
from ATSI. The $375 million received from NGC related to the nuclear generation
asset transfer that occurred on December 16, 2005. This increase in collection
from associated companies was partially offset by $388 million in loan payments
to the money pool in 2005, compared to $10 million in loan repayments from
associated companies in 2004. Higher expenditures for property additions were
substantially offset by increased investments in lessor notes.





Our capital spending
for the period 2007-2011 is expected to be approximately $841 million of
which approximately $158 million applies to 2007. The capital spending is
primarily for property additions supporting the distribution of electricity. In
addition, there is capital spending for our leasehold interests in certain
generating plants retained after the generation assets transfers in
2005.





10








**Contractual
Obligations**





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





**2008-**
    
    **2010-****Contractual
      Obligations**
    
    **Total**
    
    **2007**
    
    **2009**
    
    **2011**
    
    **Thereafter*****(In
      millions)***Long-term debt(1)
    
    $
    1,919
    
    $
    120
    
    $
    302
    
    $
    38
    
    $
    1,459`Short-term
      borrowings
    
    
    218
    
    
    218
    
    
    -
    
    
    -
    
    
    -Interest on
      long-term debt
    
    
    1,480
    
    
    114
    
    
    202
    
    
    171
    
    
    993Capital
      leases
    
    
    6
    
    
    1
    
    
    2
    
    
    2
    
    
    1Operating
      leases(2)
    
    
    183
    
    
    14
    
    
    31
    
    
    21
    
    
    117Pension
      funding(3)
    
    
    25
    
    
    25
    
    
    -
    
    
    -
    
    
    -Purchases(4)
    
    
    607
    
    
    55
    
    
    134
    
    
    182
    
    
    236Total
    
    $
    4,438
    
    $
    547
    
    $
    671
    
    $
    414
    
    $
    2,806





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


(2)  Operating lease
payments are net of capital trust receipts of $441.5 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.





**Off-Balance
Sheet Arrangements**





We have obligations
not included on our Consolidated Balance Sheets related to sale and leaseback
arrangements involving the Bruce Mansfield Plant, which is 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 $97 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, debt obligations and preferred stock with mandatory
redemption provisions.





**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 Cashand Cash
      Equivalents-Fixed
      Income
    
    $
    36
    
    $
    38
    
    $
    40
    
    $
    52
    
    $
    57
    
    $
    787
    
    $
    1,010
    
    $
    1,076Average
      interest rate
    
    
    7.7
    %
    
    7.7
    %
    
    7.7
    %
    
    7.7
    %
    
    7.7
    %
    
    6.6
    %
    
    6.9
    %LiabilitiesLong-term Debt
      and OtherLong-Term
      Obligations:Fixed
      rate
    
    $
    120
    
    $
    140
    
    $
    162
    
    $
    18
    
    $
    20
    
    $
    1,324
    
    $
    1,784
    
    $
    1,864Average
      interest rate
    
    
    7.1
    %
    
    7.0
    %
    
    7.5
    %
    
    7.7
    %
    
    7.7
    %
    
    6.7
    %
    
    6.8
    %Variable
      rate
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    135
    
    $
    135
    
    $
    136Average
      interest rate
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3.7
    %
    
    3.7
    %Short-term
      Borrowings
    
    $
    218
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    218
    
    $
    218Average
      interest rate
    
    
    5.7
    %
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5.7
    %





**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.





11








*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.





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 April 30,
      2009;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,
      2010;Reducing 
      our deferred shopping incentive balances as of January 1, 2006 by up
      to $85 million by accelerating the application of our accumulated cost of
      removal regulatory liability; andDeferring and
      capitalizing (for recovery over a 25-year period) increased fuel costs
      above the amount collected through the Ohio Companies' fuel recovery
      mechanism.





The following table
provides our estimated net amortization of regulatory transition costs and
deferred shopping incentives (including associated carrying charges) under the
RCP for the period 2007 through 2010:


**Period**
    
    
    
    **Amortization*****(In
      millions)***2007
    
    
    **$**
    1082008
    
    
    
    1242009
    
    
    
    2162010
    
    
    
    273**Total
      Amortization**
    
    
    **$**
    721




























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.





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.








13





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 $1.8 million as of December 31, 2006.





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





14








*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 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.





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 Companies. 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(B)
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 other comprehensive income. 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.
FirstEnergy's underfunded status at 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. 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 $25 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.




**Increase
      in Costs from Adverse Changes in Key Assumptions****Assumption**
    
    **Adverse
      Change**
    
    **Pension**
    
    **OPEB**
    
    **Total*****(In
      millions)***Discount
      rate
    
    
    Decrease by
      0.25%
    
    $
    0.8
    
    $
    0.2
    
    $
    1Long-term
      return on assets
    
    
    Decrease by
      0.25%
    
    $
    1
    
    $
    -
    
    $
    1Health care
      trend rate
    
    
    Increase by
      1%
    
    
    na
    
    $
    0.5
    
    $
    0.5





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 our portion of pension and OPEB costs from changes in key
assumptions are as follows:




*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 had 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 judgment 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 $1.7 billion 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
      CLEVELAND ELECTRIC ILLUMINATING
      COMPANY****CONSOLIDATED
      STATEMENTS OF
      INCOME****For
      the Years Ended December 31,**
    
    **2006**
    
    **2005**
    
    **2004*****(In
      thousands)*****REVENUES
      (Note 2(I))**Electric
      sales
    
    $
    1,702,089
    
    
    1,799,211
    
    
    1,741,511Excise tax
      collections
    
    
    67,619
    
    
    68,950
    
    
    66,9741,769,708
    
    
    1,868,161
    
    
    1,808,485**EXPENSES
      (Note 2(I)):**Fuel
    
    
    50,291
    
    
    85,993
    
    
    78,072Purchased
      power
    
    
    704,517
    
    
    557,593
    
    
    543,949Nuclear
      operating costs
    
    
    -
    
    
    142,698
    
    
    117,091Other
      operating costs
    
    
    290,904
    
    
    301,366
    
    
    272,303Provision for
      depreciation
    
    
    63,589
    
    
    127,959
    
    
    131,854Amortization
      of regulatory assets
    
    
    127,403
    
    
    227,221
    
    
    196,501Deferral of
      new regulatory assets
    
    
    (128,220
    )
    
    (163,245
    )
    
    (117,466
    )General
      taxes
    
    
    134,663
    
    
    152,678
    
    
    146,276Total
      expenses
    
    
    1,243,147
    
    
    1,432,263
    
    
    1,368,580**OPERATING
      INCOME**
    
    
    526,561
    
    
    435,898
    
    
    439,905**OTHER
      INCOME (EXPENSE) (Notes 2(I) and 7):**Investment
      income
    
    
    100,816
    
    
    86,898
    
    
    77,090Miscellaneous
      income (expense)
    
    
    6,428
    
    
    (9,031
    )
    
    (8,041
    )Interest
      expense
    
    
    (141,710
    )
    
    (132,226
    )
    
    (138,678
    )Capitalized
      interest
    
    
    2,618
    
    
    2,533
    
    
    5,110Total other
      expense
    
    
    (31,848
    )
    
    (51,826
    )
    
    (64,519
    )**INCOME
      BEFORE INCOME TAXES AND CUMULATIVE****EFFECT
      OF A CHANGE IN ACCOUNTING PRINCIPLE**
    
    
    494,713
    
    
    384,072
    
    
    375,386**INCOME
      TAXES**
    
    
    188,662
    
    
    153,014
    
    
    138,855**INCOME
      BEFORE CUMULATIVE EFFECT OF****A
      CHANGE IN ACCOUNTING PRINCIPLE**
    
    
    306,051
    
    
    231,058
    
    
    236,531Cumulative
      effect of a change in accounting principle (net of incometax benefit of
      $2,101,000) (Note 2(G))
    
    
    -
    
    
    (3,724
    )
    
    -**NET
      INCOME**
    
    
    306,051
    
    
    227,334
    
    
    236,531**PREFERRED
      STOCK DIVIDEND REQUIREMENTS**
    
    
    -
    
    
    2,918
    
    
    7,008**EARNINGS
      ON COMMON STOCK**
    
    $
    306,051
    
    $
    224,416
    
    $
    229,523The
      accompanying Notes to Consolidated Financial Statements are an integral
      part of these statements.
   20
   **THE
      CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
      BALANCE SHEETS****As of
      December 31,**
    
    **2006**
    
    **2005*****(In
      thousands)*****ASSETS****CURRENT
      ASSETS:**Cash and cash
      equivalents
    
    
    
    
    $
    221
    
    
    
    
    $
    207Receivables-Customers
      (less accumulated provisions of $6,783,000 and
    
    
    
    
    
    245,193
    
    
    
    
    
    268,427$5,180,000,
      respectively, for uncollectible accounts)Associated
      companies
    
    
    
    
    
    249,735
    
    
    
    
    
    86,564Other
    
    
    
    
    
    14,240
    
    
    
    
    
    16,466Notes
      receivable from associated companies
    
    
    
    
    
    27,191
    
    
    
    
    
    19,378Prepayments
      and other
    
    
    
    
    
    2,314
    
    
    
    
    
    1,903538,894
    
    
    
    
    
    392,945**UTILITY
      PLANT:**In
      service
    
    
    
    
    
    2,136,766
    
    
    
    
    
    2,030,935Less -
      Accumulated provision for depreciation
    
    
    
    
    
    819,633
    
    
    
    
    
    788,9671,317,133
    
    
    
    
    
    1,241,968Construction
      work in progress
    
    
    
    
    
    46,385
    
    
    
    
    
    51,1291,363,518
    
    
    
    
    
    1,293,097**OTHER
      PROPERTY AND INVESTMENTS:**Long-term
      notes receivable from associated companies
    
    
    
    
    
    486,634
    
    
    
    
    
    1,057,337Investment in
      lessor notes (Note 6)
    
    
    
    
    
    519,611
    
    
    
    
    
    564,166Other
    
    
    
    
    
    13,426
    
    
    
    
    
    12,8401,019,671
    
    
    
    
    
    1,634,343**DEFERRED
      CHARGES AND OTHER ASSETS:**Goodwill
    
    
    
    
    
    1,688,521
    
    
    
    
    
    1,688,966Regulatory
      assets
    
    
    
    
    
    854,588
    
    
    
    
    
    862,193Prepaid
      pension costs (Note 3)
    
    
    
    
    
    -
    
    
    
    
    
    139,012Property
      taxes
    
    
    
    
    
    65,000
    
    
    
    
    
    63,500Other
    
    
    
    
    
    33,306
    
    
    
    
    
    27,6142,641,415
    
    
    
    
    
    2,781,285$
    5,563,498
    
    
    
    
    $
    6,101,670**LIABILITIES
      AND CAPITALIZATION****CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    
    
    
    $
    120,569
    
    
    
    
    $
    75,718Short-term
      borrowings-Associated
      companies
    
    
    
    
    
    218,134
    
    
    
    
    
    212,256Other
    
    
    
    
    
    -
    
    
    
    
    
    140,000Accounts
      payable-Associated
      companies
    
    
    
    
    
    365,678
    
    
    
    
    
    74,993Other
    
    
    
    
    
    7,194
    
    
    
    
    
    4,664Accrued
      taxes
    
    
    
    
    
    128,829
    
    
    
    
    
    121,487Accrued
      interest
    
    
    
    
    
    19,033
    
    
    
    
    
    18,886Lease market
      valuation liability
    
    
    
    
    
    60,200
    
    
    
    
    
    60,200Other
    
    
    
    
    
    52,101
    
    
    
    
    
    61,308971,738
    
    
    
    
    
    769,512**CAPITALIZATION**
      (See Consolidated Statements of Capitalization):Common
      stockholder's equity
    
    
    
    
    
    1,468,903
    
    
    
    
    
    1,942,074Long-term debt
      and other long-term obligations
    
    
    
    
    
    1,805,871
    
    
    
    
    
    1,939,3003,274,774
    
    
    
    
    
    3,881,374**NONCURRENT
      LIABILITIES:**Accumulated
      deferred income taxes
    
    
    
    
    
    470,707
    
    
    
    
    
    554,828Accumulated
      deferred investment tax credits
    
    
    
    
    
    20,277
    
    
    
    
    
    23,908Lease market
      valuation liability
    
    
    
    
    
    547,800
    
    
    
    
    
    608,000Retirement
      benefits
    
    
    
    
    
    123,072
    
    
    
    
    
    83,414Deferred
      revenues - electric service programs
    
    
    
    
    
    51,588
    
    
    
    
    
    71,261Other
    
    
    
    
    
    103,542
    
    
    
    
    
    109,3731,316,986
    
    
    
    
    
    1,450,784**COMMITMENTS
      AND CONTINGENCIES (Notes 5 and 12)**$
    5,563,498
    
    
    
    
    $
    6,101,670The
      accompanying Notes to Consolidated Financial Statements are an integral
      part of these balance sheets.
 
 21
 
  
 **THE
      CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
      STATEMENTS OF CAPITALIZATION****As of
      December 31,**
    
    **2006**
    
    **2005***(Dollars
      in thousands)***COMMON
      STOCKHOLDER'S EQUITY:**Common stock,
      without par value, 105,000,000 shares authorized
    
    
    
    
    $
    860,133
    
    $
    1,354,92467,930,743 and 79,590,689 shares outstanding, respectivelyAccumulated
      other comprehensive loss (Note 2(F))
    
    
    
    
    
    (104,431
    )
    
    -Retained
      earnings (Note 9(A))
    
    
    
    
    
    713,201
    
    
    587,150Total
    
    
    
    
    
    1,468,903
    
    
    1,942,074**LONG-TERM
      DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 9(C)):**First mortgage
      bonds-6.860% due
      2008
    
    
    
    
    
    125,000
    
    
    125,000Total
    
    
    
    
    
    125,000
    
    
    125,000Secured
      notes-7.130% due
      2007
    
    
    
    
    
    120,000
    
    
    120,0007.430% due
      2009
    
    
    
    
    
    150,000
    
    
    150,000*  3.150%
      due 2015
    
    
    -
    
    
    39,8357.880% due
      2017
    
    
    
    
    
    300,000
    
    
    300,000*  3.150%
      due 2018
    
    
    -
    
    
    72,795*  3.580%
      due 2020
    
    
    -
    
    
    47,5006.000% due
      2020
    
    
    
    
    
    62,560
    
    
    62,5606.100% due
      2020
    
    
    
    
    
    70,500
    
    
    70,5005.375% due
      2028
    
    
    
    
    
    5,993
    
    
    5,993*  3.350%
      due 2030
    
    
    -
    
    
    23,255*  3.750%
      due 2030
    
    
    81,640
    
    
    81,640*  3.150%
      due 2033
    
    
    -
    
    
    30,000*  3.150%
      due 2033
    
    
    -
    
    
    46,100*  3.050%
      due 2034
    
    
    -
    
    
    40,900*  3.500%
      due 2034
    
    
    -
    
    
    2,900*  3.650%
      due 2035
    
    
    53,900
    
    
    53,900*3.500%
      due 2035
    
    
    -
    
    
    45,150Total
    
    
    
    
    
    844,593
    
    
    1,193,028Unsecured
      notes-6.000% due
      2013
    
    
    
    
    
    78,700
    
    
    78,7005.650% due
      2013
    
    
    
    
    
    300,000
    
    
    300,0009.000% due
      2031
    
    
    
    
    
    103,093
    
    
    103,093*  3.670%
      due 2033
    
    
    -
    
    
    27,7005.950% due
      2036
    
    
    
    
    
    300,000
    
    
    -7.742% due to
      associated companies 2008-2016 (Note 6)
    
    
    
    
    
    167,696
    
    
    176,847Total
    
    
    
    
    
    949,489
    
    
    686,340Capital lease
      obligations (Note 5)
    
    
    
    
    
    4,371
    
    
    4,939Net
      unamortized premium on debt
    
    
    
    
    
    2,987
    
    
    5,711Long-term debt
      due within one year
    
    
    
    
    
    (120,569
    )
    
    (75,718
    )Total
      long-term debt and other long-term obligations
    
    
    
    
    
    1,805,871
    
    
    1,939,300**TOTAL
      CAPITALIZATION**
    $
    3,274,774
    
    $
    3,881,374* Denotes
      variable rate issue with applicable year-end interest rate
      shown.The
      accompanying Notes to Conslidated Financial Statements are an integral
      part of these statements.
   22
  **THE
      CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
      STATEMENTS OF COMMON STOCKHOLDER'S EQUITY****Accumulated****Other****Comprehensive**
    
    **Number**
    
    **Carrying**
    
    **Comprehensive**
    
    **Retained****Income**
    
    **of
      Shares**
    
    **Value**
    
    **Income
      (Loss)**
    
    **Earnings*****(Dollars
      in thousands)***Balance,
      January 1, 2004
    
    
    
    
    
    79,590,689
    
    $
    1,281,962
    
    $
    2,653
    
    $
    494,212Net
      income
    
    $
    236,531
    
    
    
    
    
    
    
    
    
    
    
    236,531Unrealized
      gain on investments, net of$8,294,000 of income taxes
    
    
    11,450
    
    
    
    
    
    
    
    
    11,450Minimum
      liability for unfunded retirement benefits,net of $2,413,000 of income taxes
    
    
    3,756
    
    
    
    
    
    
    
    
    3,756Comprehensive
      income
    
    $
    251,737Cash dividends
      on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (7,003
    )Cash dividends
      on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (170,000
    )Balance,
      December 31, 2004
    
    
    
    
    
    79,590,689
    
    
    1,281,962
    
    
    17,859
    
    
    553,740Net
      income
    
    $
    227,334
    
    
    
    
    
    
    
    
    
    
    
    227,334Unrealized
      loss on investments, net of$27,734,000 of income tax benefits
    
    
    (39,472
    )
    
    
    
    
    
    
    
    (39,472
    )Minimum
      liability for unfunded retirement benefits,net of $15,186,000 of income taxes
    
    
    21,613
    
    
    
    
    
    
    
    
    21,613Comprehensive
      income
    
    $
    209,475Equity
      contribution from parent
    
    
    
    
    
    
    
    
    75,000Affiliated
      company asset transfers
    
    
    
    
    
    
    
    
    (2,086
    )Restricted
      stock units
    
    
    
    
    
    
    
    
    48Cash dividends
      on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,924
    )Cash dividends
      on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (191,000
    )Balance,
      December 31, 2005
    
    
    
    
    
    79,590,689
    
    
    1,354,924
    
    
    -
    
    
    587,150Net
      income
    
    $
    306,051
    
    
    
    
    
    
    
    
    
    
    
    306,051Net liability
      for unfunded retirement benefitsdue to the implementation of SFAS 158, netof $69,609,000 of income tax benefits
    
    
    
    
    
    
    
    
    
    
    
    (104,431
    )Repurchase of
      common stock
    
    
    
    
    
    (11,659,946
    )
    
    (300,000
    )Affiliated
      company asset transfers (see Note 13)
    
    
    
    
    
    
    
    
    (194,910
    )Restricted
      stock units
    
    
    
    
    
    
    
    
    86Stock based
      compensation
    
    
    
    
    
    
    
    
    33Cash dividends
      on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (180,000
    )Balance,
      December 31, 2006
    
    
    
    
    
    67,930,743
    
    $
    860,133
    
    $
    (104,431
    )
    $
    713,201
   **CONSOLIDATED
      STATEMENTS OF PREFERRED STOCK****Not
      Subject to**
    
    **Subject
      to****Mandatory
      Redemption**
    
    **Mandatory
      Redemption*****Number**
    
    **Carrying**
    
    **Number**
    
    **Carrying****of
      Shares**
    
    **Value**
    
    **of
      Shares**
    
    **Value*****(Dollars
      in thousands)***Balance,
      January 1, 2004
    
    
    974,000
    
    $
    96,404
    
    
    50,000
    
    $
    5,014Redemptions-$7.35 Series
      C
    
    
    
    
    
    
    
    
    (10,000
    )
    
    (1,000
    )Amortization
      of fair marketvalue
      adjustments-$7.35 Series
      C
    
    
    
    
    
    
    
    
    
    
    
    (5
    )Balance,
      December 31, 2004
    
    
    974,000
    
    
    96,404
    
    
    40,000
    
    
    4,009Redemptions-$7.40 Series
      A
    
    
    (500,000
    )
    
    (50,000
    )Adjustable
      Series L
    
    
    (474,000
    )
    
    (46,404
    )$7.35 Series
      C
    
    
    
    
    
    
    
    
    (40,000
    )
    
    (4,000
    )Amortization
      of fair marketvalue
      adjustments-$7.35 Series
      C
    
    
    
    
    
    
    
    
    
    
    
    (9
    )Balance,
      December 31, 2005
    
    
    -
    
    
    -
    
    
    -
    
    
    -Balance,
      December 31, 2006
    
    
    -
    
    $
    -
    
    
    -
    
    $
    -* Preferred
      stock subject to mandatory redemption is classified as debt under SFAS
      150.The
      accompanying Notes to Consolidated Financial Statements are an integral
      part of these statements.
   23
  **THE
      CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
      STATEMENTS OF CASH FLOWS****For
      the Years Ended December 31,**
    
    **2006**
    
    **2005**
    
    **2004*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      income
    
    $
    306,051
    
    $
    227,334
    
    $
    236,531Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
    
    
    63,589
    
    
    127,959
    
    
    131,854Amortization
      of regulatory assets
    
    
    127,403
    
    
    227,221
    
    
    196,501Deferral of
      new regulatory assets
    
    
    (128,220
    )
    
    (163,245
    )
    
    (117,466
    )Nuclear fuel
      and capital lease amortization
    
    
    239
    
    
    25,803
    
    
    28,239Deferred rents
      and lease market valuation liability
    
    
    (71,943
    )
    
    (67,353
    )
    
    (56,405
    )Deferred
      income taxes and investment tax credits, net
    
    
    (17,093
    )
    
    42,024
    
    
    39,129Accrued
      compensation and retirement benefits
    
    
    2,367
    
    
    4,624
    
    
    15,678Cumulative
      effect of a change in accounting principle
    
    
    -
    
    
    3,724
    
    
    -Pension trust
      contribution
    
    
    -
    
    
    (93,269
    )
    
    (31,718
    )Tax refund
      related to pre-merger period
    
    
    -
    
    
    9,636
    
    
    -Decrease
      (increase) in operating assets-Receivables
    
    
    (137,711
    )
    
    (103,018
    )
    
    38,297Materials and
      supplies
    
    
    -
    
    
    (12,934
    )
    
    (8,306
    )Prepayments
      and other current assets
    
    
    160
    
    
    233
    
    
    2,375Increase
      (decrease) in operating liabilities-Accounts
      payable
    
    
    293,214
    
    
    (82,434
    )
    
    (93,745
    )Accrued
      taxes
    
    
    7,342
    
    
    (7,967
    )
    
    (73,068
    )Accrued
      interest
    
    
    147
    
    
    (3,216
    )
    
    (15,770
    )Electric
      service prepayment programs
    
    
    (19,673
    )
    
    53,447
    
    
    (18,386
    )Other
    
    
    (6,626
    )
    
    (40,878
    )
    
    (51,617
    )Net cash
      provided from operating activities
    
    
    419,246
    
    
    147,691
    
    
    222,123**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Long-term
      debt
    
    
    295,662
    
    
    141,004
    
    
    124,977Short-term
      borrowings, net
    
    
    -
    
    
    155,883
    
    
    290,263Equity
      contribution from parent
    
    
    -
    
    
    75,000
    
    
    -Redemptions
      and Repayments-Common
      stock
    
    
    (300,000
    )
    
    -
    
    
    -Preferred
      stock
    
    
    -
    
    
    (101,900
    )
    
    (1,000
    )Long-term
      debt
    
    
    (376,702
    )
    
    (147,923
    )
    
    (335,393
    )Short-term
      borrowings, net
    
    
    (143,272
    )
    
    -
    
    
    -Dividend
      Payments-Common
      stock
    
    
    (180,000
    )
    
    (191,000
    )
    
    (170,000
    )Preferred
      stock
    
    
    -
    
    
    (2,260
    )
    
    (7,008
    )Net cash used
      for financing activities
    
    
    (704,312
    )
    
    (71,196
    )
    
    (98,161
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    (119,795
    )
    
    (148,783
    )
    
    (121,316
    )Loan
      repayments from (loans to) associated companies, net
    
    
    (7,813
    )
    
    (387,746
    )
    
    9,936Collection of
      principal on long-term notes receivable
    
    
    376,135
    
    
    466,378
    
    
    482Investments in
      lessor notes
    
    
    44,556
    
    
    32,479
    
    
    9,270Proceeds from
      nuclear decommissioning trust fund sales
    
    
    -
    
    
    490,958
    
    
    406,375Investments in
      nuclear decommissioning trust funds
    
    
    -
    
    
    (519,982
    )
    
    (435,399
    )Other
    
    
    (8,003
    )
    
    (9,789
    )
    
    (17,895
    )Net cash
      provided from (used for) investing activities
    
    
    285,080
    
    
    (76,485
    )
    
    (148,547
    )Net increase
      (decrease) in cash and cash equivalents
    
    
    14
    
    
    10
    
    
    (24,585
    )Cash and cash
      equivalents at beginning of year
    
    
    207
    
    
    197
    
    
    24,782Cash and cash
      equivalents at end of year
    
    $
    221
    
    $
    207
    
    $
    197**SUPPLEMENTAL
      CASH FLOW INFORMATION:**Cash Paid
      During the Year-Interest (net
      of amounts capitalized)
    
    $
    135,276
    
    $
    144,730
    
    $
    152,373Income
      taxes
    
    $
    180,941
    
    $
    116,323
    
    $
    144,277The
      accompanying Notes to Consolidated Financial Statements are an integral
      part of these statements.
   24
  **THE
      CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
      STATEMENTS OF TAXES****For
      the Years Ended December 31,**
    
    **2006**
    
    **2005**
    
    **2004*****(In
      thousands)*****GENERAL
      TAXES:**Real and
      personal property
    $
    61,289
    
    $
    77,822
    
    $
    74,206Ohio
      kilowatt-hour excise*
    
    67,619
    
    
    68,950
    
    
    66,974Social
      security and unemployment
    
    5,179
    
    
    5,282
    
    
    4,496Other
    
    576
    
    
    624
    
    
    600Total general
      taxes
    
    
    
    
    $
    134,663
    
    $
    152,678
    
    $
    146,276**PROVISION
      FOR INCOME TAXES:**Currently
      payable-Federal
    
    
    
    
    $
    173,520
    
    $
    90,152
    
    $
    72,264State
    
    
    
    
    
    32,235
    
    
    22,939
    
    
    27,463205,755
    
    
    113,091
    
    
    99,727Deferred, net-Federal
    
    
    
    
    
    (14,624
    )
    
    28,310
    
    
    34,450State
    
    
    
    
    
    1,162
    
    
    16,350
    
    
    9,774(13,462
    )
    
    44,660
    
    
    44,224Investment tax
      credit amortization
    
    (3,631
    )
    
    (4,737
    )
    
    (5,096
    )Total
      provision for income taxes
    
    
    
    
    $
    188,662
    
    $
    153,014
    
    $
    138,855**RECONCILIATION
      OF FEDERAL INCOME TAX****EXPENSE
      AT STATUTORY RATE TO TOTAL****PROVISION
      FOR INCOME TAXES:**Book income
      before provision for income taxes
    $
    494,713
    
    $
    384,072
    
    $
    375,386Federal income
      tax expense at statutory rate
    $
    173,150
    
    $
    134,425
    
    $
    131,385Increases
      (reductions) in taxes resulting from-State income
      taxes, net of federal income tax benefit
    
    
    
    
    
    21,708
    
    
    25,537
    
    
    24,205Amortization
      of investment tax credits
    
    
    
    
    
    (3,631
    )
    
    (4,737
    )
    
    (5,096
    )Other,
      net
    
    
    
    
    
    (2,565
    )
    
    (2,211
    )
    
    (11,639
    )Total
      provision for income taxes
    
    
    
    
    $
    188,662
    
    $
    153,014
    
    $
    138,855**ACCUMULATED
      DEFERRED INCOME TAXES AS OF****DECEMBER
      31:**Property basis
      differences
    $
    533,682
    
    $
    498,079
    
    $
    502,625Regulatory
      transition charge
    
    116,229
    
    
    159,535
    
    
    221,386Asset
      retirement obligations
    
    2,045
    
    
    -
    
    
    24,638Unamortized
      investment tax credits
    
    (8,839
    )
    
    (10,150
    )
    
    (23,208
    )Deferred gain
      on asset sales to affiliated companies
    
    30,730
    
    
    33,329
    
    
    33,841Other
      comprehensive income
    
    (69,609
    )
    
    -
    
    
    12,548Above market
      leases
    
    (234,572
    )
    
    (256,297
    )
    
    (300,000
    )Retirement
      benefits
    
    11,048
    
    
    12,005
    
    
    (21,674
    )Deferred
      customer shopping incentive
    
    132,343
    
    
    153,750
    
    
    121,778Other
    
    (42,350
    )
    
    (35,423
    )
    
    (31,723
    )Net deferred
      income tax liability
    
    
    
    
    $
    470,707
    
    $
    554,828
    
    $
    540,211*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 CEI (Company) and its wholly owned subsidiaries,
CFC and Shippingport (see Note 6). 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 OE, TE, 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 the 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;
  and
- can 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 recovered 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 are expected 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 will remain regulated; accordingly, it is appropriate that the
Company continues 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
    
    $360
    
    $479Customer
      shopping incentives
    
    
    368
    
    
    427Employee
      postretirement benefit costs
    
    
    10
    
    
    12Asset removal
      costs
    
    
    (12
    )
    
    (90
    )MISO
      transmission costs
    
    
    26
    
    
    30Fuel costs'RCP
    
    
    39
    
    
    -Distribution
      costs'RCP
    
    
    57
    
    
    -Other
    
    
    7
    
    
    4Total
    
    $
    855
    
    $
    862





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 balance
($427 million as of December 31, 2005) was reduced on January 1,
2006 by $85 million by accelerating the application of the Company's
accumulated cost of removal regulatory liability against the Extended RTC
balance. In accordance with the RCP, the recovery periods for the aggregate of
the regulatory transition costs were adjusted so that recovery of these
aggregate amounts through the Company's RTC rate component began on
January 1, 2006. The Company's recovery of its RTC is projected to be
completed by April 2009 at which time recovery of its Extended RTC will begin,
with recovery estimated to be completed as of December 31, 2010. 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 balance; any remaining regulatory
transition costs and Extended RTC balances would be written off. In addition,
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 Company 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 will be equal to the related revenue recovery that is
recognized beginning in 2009. The following table provides the estimated net
amortization of regulatory transition costs and Extended RTC amounts (including
associated carrying charges) under the RCP for the period 2007 through
2010:





**Period**
    
    **Amortization*****(In
      millions)***2007
    
    $
    1082008
    
    
    1242009
    
    
    2162010
    
    
    273**Total
      Amortization**
    
    **$**
    **721**





**(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 estimated historical customer usage, load
profiles, 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 were $245 million (billed - $137 million and unbilled -
$108 million) and $268 million (billed - $157 million and
unbilled - $111 million) as of December 31, 2006 and 2005,
respectively.





The Company and TE
sell substantially all of their retail customer receivables to CFC, a wholly
owned subsidiary of the Company. In June 2005, the CFC receivables 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 the Company'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 nuclear
leasehold interests 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 3.2% in 2006, 2.9% 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. As of
December 31, 2006, the Company had approximately $1.7 billion 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. The impairment analysis
includes a significant source of cash representing the Company's recovery of
transition costs as described below under "Regulatory Matters." The Company
estimates that completion of transition cost recovery will not result in an
impairment of goodwill.








28





**(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 $104 million. As of
December 31, 2005, the Company did not have an accumulated other
comprehensive balance.





**(G)**  **CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE-**





Results in 2005
include an after-tax charge of $ 4 million
recorded upon the adoption of FIN 47 in December 2005. The Company
identified applicable legal obligations as defined under the new standard at its
retired generating units, substation control rooms, service center buildings,
line shops and office buildings, identifying asbestos as the primary conditional
ARO. The Company recorded a conditional ARO liability of $7 million
(including accumulated accretion for the period from the date the liability was
incurred to the date of adoption), an asset retirement cost of $2 million
(recorded as part of the carrying amount of the related long-lived asset), and
accumulated depreciation of $2 million. T he Company charged a
regulatory liability for $1 million upon adoption of FIN 47 for the
transition amounts related to establishing the ARO for asbestos removal from
substation control rooms and service center buildings. The remaining cumulative
effect adjustment for unrecognized depreciation and accretion of $6 million
was charged to income ($4 million, net of tax).





**(H)**  **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 each Company
recognizing any tax losses or credits the Company contributes to the
consolidated return (see Note 7 for Ohio Tax Legislation
discussion).





**(I)**  **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, TE, OE and Penn
completed the intra-system transfers of their generation assets 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 company's
transactions are as follows:








**2006**
    
    **2005**
    
    **2004*****(In
      millions)*****Revenues:**PSA revenues
      from FES
    
    $
    95
    
    $
    362
    
    $
    387Generating
      units rent from FES
    
    
    -
    
    
    49
    
    
    59Ground lease
      with ATSI
    
    
    7
    
    
    7
    
    
    7**Expenses:**Purchased
      power under PSA
    
    
    625
    
    
    452
    
    
    444Purchased
      power from TE
    
    
    102
    
    
    105
    
    
    101FESC support
      services
    
    
    63
    
    
    60
    
    
    65**Other
      Income:**Interest
      income from ATSI
    
    
    -
    
    
    1
    
    
    7Interest
      income from FES and NGC
    
    
    57
    
    
    6
    
    
    -











29





The Company is
buying 150 MW of TE's Beaver Valley Unit 2 leased capacity
entitlement. Purchased power expenses for this transaction were
$102 million, $105 million and $101 million in 2006, 2005 and
2004, respectively. This purchase agreement is expected to continue through the
end of the lease period (see Note 5).





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.





**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 $25 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 an employer 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. CEI's incremental impact of adopting SFAS 158 was a decrease of $135
million in pension assets, an increase of $39 million in pension liabilities and
a decrease in AOCL of $104 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.








**Obligations
      and Funded Status**
    
    **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
    
    $
    (13
    )
    $
    139
    
    $
    (110
    )
    $
    (83
    )**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**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
    
    $
    4
    
    $
    1
    
    $
    6
    
    $
    11
    
    $
    15
    
    $
    18**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 AND OTHER LONG-TERM OBLIGATIONS-**





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 and other
long-term obligations 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
    
    $
    1,816
    
    $
    1,895
    
    $
    1,901
    
    $
    2,016Subordinated
      debentures to affiliated trusts
    
    
    103
    
    
    105
    
    
    103
    
    
    140$
    1,919
    
    $
    2,000
    
    $
    2,004
    
    $
    2,156





The fair values of
long-term debt and other long-term obligations reflect the present value of the
cash outflows relating to those securities based on the current call price, the
yield to maturity or the yield to call, as deemed appropriate at the end of each
respective 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-**





Investments other
than cash and cash equivalents include held-to-maturity securities and
available-for-sale securities. The Company periodically evaluates its
investments for other-than-temporary impairment. They first consider their
intent and ability to hold the investment until recovery and then consider,
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. The following table
provides the approximate fair value and related carrying amounts of investments
excluding investments of $9 million for both 2006 and 2005 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
    
    $
    487
    
    $
    487
    
    $
    1,058
    
    $
    1,058Debt
      securities:-Corporate
      debt securities
    
    
    3
    
    
    5
    
    
    3
    
    
    40-Lease
      obligation bonds
    
    
    520
    
    
    583
    
    
    564
    
    
    630523
    
    
    588
    
    
    567
    
    
    670$
    1,010
    
    $
    1,075
    
    $
    1,625
    
    $
    1,728










33








The table above
includes notes receivable, lease obligation bonds, and corporate debt. The 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 2025. The investments in lease obligation bonds and
corporate debt are accounted for as held-to-maturity securities and the fair
value is based on present value of the cash inflows based on the yield to
maturity similar to the notes receivable. With maturity dates ranging from the
2007 to 2015.





The following table
provides the amortized cost basis, unrealized gains and losses and fair values
for the investments debt securities and lease obligation bonds above, which
excludes the notes receivable:





**2006**
    
    **2005****Cost**
    
    **Unrealized**
    
    **Unrealized**
    
    **Fair**
    
    **Cost**
    
    **Unrealized**
    
    **Unrealized**
    
    **Fair****Basis**
    
    **Gains**
    
    **Losses**
    
    **Value**
    
    **Basis**
    
    **Gains**
    
    **Losses**
    
    **Value*****(In
      millions)***Debt
      securities
    
    $
    523
    
    $
    65
    
    $
    -
    
    $
    588
    
    $
    567
    
    $
    103
    
    $
    -
    
    $
    670





Prior to their
transfer to NGC in December 2005 (see Note 10), the Company's decommissioning
trust investments were classified as available-for-sale. The Company has no
securities held for trading purposes. The unrealized gains and losses applicable
to the Company's decommissioning trusts were recognized in OCI in accordance
with SFAS 115.





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





**2005**
    
    
    **2004*****(In
      millions)***Proceeds from
      sales
    
    $
    475
    
    $
    411Realized
      gains
    
    
    49
    
    
    35Realized
      losses
    
    
    20
    
    
    21Interest and
      dividend income
    
    
    12
    
    
    11





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





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





The Company and TE
sold their ownership int erests in Bruce
Mansfield Units 1, 2 and 3 and TE 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 TE entered into operating leases for lease
terms of approximately 30 years as co-lessees. During the terms of the leases,
the Company and TE continue to be responsible, to the extent of their leasehold
interest, for costs associated with the units including construction
expenditures, operation and maintenance expenses, insurance, nuclear fuel,
property taxes and decommissioning. The Company and TE have the right, at the
end of the respective basic lease terms, to renew the leases. The Company and TE
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
TE, the Company is also obligated for TE's lease payments. If TE is unable to
make its payments under the Beaver Valley Unit 2 and Bruce Mansfield Plant
leases, the Company would be obligated to make such payments. No such payments
have been made on behalf of TE. (TE's future minimum lease payments as of
December 31, 2006 were approximately $0.8 billion, net of trust cash
receipts.)





Consistent with the
regulatory treatment, the rentals for capital and 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:





**2006**
    
    **2005**
    
    **2004*****(In
      millions)***Operating
      leasesInterest
      element
    
    $
    26.3
    
    $
    28.4
    
    $
    29.1Other
    
    
    48.2
    
    
    40.9
    
    
    29.4Capital
      leasesInterest
      element
    
    
    0.4
    
    
    0.5
    
    
    0.5Other
    
    
    0.6
    
    
    0.5
    
    
    0.5Total
      rentals
    
    $
    75.5
    
    $
    70.3
    
    $
    59.5








34








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





**Operating
      Leases****Capital**
    
    **Lease**
    
    **Capital****Leases**
    
    **Payments**
    
    **Trust**
    
    **Net*****(In
      millions)***2007
    
    $
    1.0
    
    $
    62.3
    
    $
    48.2
    
    $
    14.12008
    
    
    1.0
    
    
    59.0
    
    
    42.9
    
    
    16.12009
    
    
    1.0
    
    
    60.7
    
    
    46.1
    
    
    14.62010
    
    
    1.0
    
    
    61.2
    
    
    49.0
    
    
    12.22011
    
    
    1.0
    
    
    57.9
    
    
    49.0
    
    
    8.9Years
      thereafter
    
    
    0.7
    
    
    323.2
    
    
    206.3
    
    
    116.9Total minimum
      lease payments
    
    
    5.7
    
    $
    624.3
    
    $
    441.5
    
    $
    182.8Interest
      portion
    
    
    1.3Present value
      of net minimum lease payments
    
    
    4.4Less current
      portion
    
    
    0.6Noncurrent
      portion
    
    $
    3.8





The Company has
recorded above-market lease liabilities for Beaver Valley Unit 2 and the
Bruce Mansfield Plant associated with the 1997 merger creating FirstEnergy. The
total above-market lease obligation of $611 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 $31 million per year). The total
above-market lease obligation of $457 million associated with the Bruce
Mansfield Plant is being amortized on a straight-line basis through the end of
2016 (approximately $29 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 $608 million, of which
$60 million is payable within one year.





The Company and TE
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, the two companies pledged
$720 million aggregate principal amount ($575 million for the Company
and $145 million for TE) 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 ($570 million
for the Company and $337 million for TE) 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 obligation 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.





**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.





Included in the
Company's consolidated financial statements is Shippingport, a VIE created in
1997, to refinance debt originally issued in connection with the Bruce Mansfield
Plant sale and leaseback transaction.





Shippingport was
established to purchase all of the lease obligation bonds issued in connection
with the Company's and TE's Bruce Mansfield Plant sale and leaseback transaction
in 1987. The Company and TE used debt and available funds to purchase the notes
issued by Shippingport. Shippingport's note payable to TE of $177million
($9 million current) and $189 million ($12 million current) as of
December 31, 2006 and December 31, 2005, respectively, is included in
long-term debt on the Company's Consolidated Balance Sheets.





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 has
concluded that it was not the primary beneficiary of the owner trusts and was
therefore not required to consolidate these entities. The leases are accounted
for as operating leases in accordance with GAAP.





The Company is
exposed to losses under the sale-leaseback agreements upon the occurrence of
certain contingent events that it considers unlikely to occur. The Company has a
maximum exposure to loss under these provisions of $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 agreement, the Company has net minimum discounted lease
payments of $97 million, that would not be payable if the casualty value
payments are made.





35








**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 $4 million, which was partially
offset by the initial phase-out of the Ohio income-based franchise tax, which
reduced income taxes by approximately $5 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.





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.





36





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. We, 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.





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.





37








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 April 30, 2009
      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, 2010 for
      the Company;Reducing the
      deferred shopping incentive balances as of January 1, 2006 by up to
      $85 million for the Company by accelerating the application of the
      Company's accumulated cost of removal regulatory liability;
      andDeferring and
      capitalizing (for recovery over a 25-year period) increased fuel costs
      above the amount collected through the Ohio Companies'  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.





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.





38








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.





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.











39





**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 four
million authorized and unissued shares of preferred stock having no par
value.





The Company has
three million authorized and unissued shares of preference stock having no
par value.





**(C)**  **LONG-TERM
DEBT AND OTHER LONG-TERM OBLIGATIONS-**





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 covenants. There also exist cross-default provisions among financing
agreements of FirstEnergy and the Company.





Sinking fund
requirements for FMB and maturing long-term debt (excluding capital leases) for
the next five years are:




***(In
      millions)***2007
    $
    1202008
    
    2212009
    
    1622010
    
    182011
    
    20





Included in the 2008
amount are $82 million for variable interest rate pollution control revenue
bonds that have provisions by which individual debt holders are required to "put
back" the respective debt to the issuer for redemption prior to its maturity
date. This amount represents the next time debt holders may exercise this
provision.





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
$60 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 0.29% of the amount of the policy to the insurer. The Company is obligated to
reimburse the insurers for any drawings thereunder.





Certain secured
notes of the Company are entitled to the benefit of noncancelable municipal bond
insurance policies of $120 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 TE
have unsecured LOCs of approximately $194 million in connection with the
sale and leaseback of Beaver Valley Unit 2. The Company and TE are jointly
and severally liable for the LOCs (see Note 5).





**(D)**  **SUBORDINATED
DEBENTURES TO AFFILIATED TRUSTS-**





As of
December 31, 2006, the Company's wholly owned statutory business trust,
Cleveland Electric Financing Trust, had $100 million of outstanding 9.00%
preferred securities maturing in 2031. The sole assets of the trust are the
Company's subordinated debentures with the same rate and maturity date as the
preferred securities.





The Company formed
the trust to sell preferred securities and invest the gross proceeds in the
9.00% subordinated debentures of the Company. The sole assets of the trust are
the applicable subordinated debentures. Interest payment provisions of the
subordinated debentures match the distribution payment provisions of the trust's
preferred securities. In addition, upon redemption or payment at maturity of
subordinated debentures, the trust's preferred securities will be redeemed on a
pro rata basis at their liquidation value. Under certain circumstances, the
applicable subordinated debentures could be distributed to the holders of the
outstanding preferred securities of the trust in the event that the trust is
liquidated. The Company has effectively provided a full and unconditional
guarantee of payments due on the trust's preferred securities. The trust's
preferred securities are redeemable at 100% of their principal amount at the
Company's option beginning in December 2006. Interest on the subordinated
debentures (and therefore distributions on the trust's preferred securities) may
be deferred for up to 60 months, but the Company may not pay dividends on,
or redeem or acquire, any of its cumulative preferred or common stock until
deferred payments on its subordinated debentures are paid in full.








40





**10.**  **ASSET
RETIREMENT OBLIGATION:**





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.





In May 2006, the
Company sold its interest in the Ashtabula C Plant. As part of the transaction,
the Company settled the $6 million ARO that had been established with the
adoption of FIN 47.





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 the two coal ash
disposal sites and the sale and leaseback arrangements remain with the
Company.





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. The recognition requirement of the conditional ARO under FIN 47
is the same as SFAS 143.





The Company
identified applicable legal obligations as defined under the new standard at its
retired generating units,
substation control rooms, service center buildings, line shops and office
buildings, identifying asbestos as the primary conditional ARO. As a result of
adopting FIN 47 in December 2005, the Company recorded a conditional ARO
liability of $7 million (including accumulated accretion for the period
from the date the liability was incurred to the date of adoption), an asset
retirement cost of $2 million (recorded as part of the carrying amount of
the related long-lived asset), and accumulated depreciation of $2 million. T he Company
recognized a regulatory liability of $1 million upon adoption of
FIN 47 for the transition amounts related to establishing the ARO for
asbestos removal from substation control room and service center buildings,
therefore requiring a $6 million cumulative effect adjustment
($4 million, net of tax) for unrecognized depreciation and accretion to be
recorded as of December 31, 2005. The obligation to
remediate asbestos, lead paint abatement and other remediation costs at the
retired generating units was developed based on site specific studies performed
by an independent engineer. The costs of remediation at the substation control
rooms, service center buildings, line shops and office buildings were based on
costs incurred during recent remediation projects performed at each of these
locations, respectively. The conditional ARO liability was developed utilizing
an expected cash flow approach (as discussed in SFAC 7) to measure the fair
value of the ARO. The Company used a probability weighted analysis to estimate
when remediation payments would begin. 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.





**2006**
    
    **2005****ARO
      Reconciliation**
    
    ***(In
      millions)***Balance at
      beginning of year
    
    $
    8
    
    $
    272Liabilities
      settled
    
    
    (6
    )
    
    -Transfers to
      FGCO and NCG
    
    
    -
    
    
    (247
    )Accretion
    
    
    -
    
    
    17Revisions in
      estimated cash flows
    
    
    -
    
    
    (41
    )FIN 47 ARO
      upon adoption
    
    
    -
    
    
    7Balance at end
      of year
    
    $
    2
    
    $
    8





**11.**  **SHORT-TERM
BORROWINGS:**





Short-term
borrowings outstanding as of December 31, 200 6, consisted of
$218 million of borrowings from affiliates. CFC is a wholly owned
subsidiary of the Company whose borrowings are secured by customer accounts
receivable purchased from the Company and TE. CFC can borrow up to
$200 million under a receivables financing arrangement at rates based on
certain bank commercial paper and is required to pay an annual fee of 0.15% on
the amount of the entire finance limit. 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 a separate
legal entity with separate creditors, CFC would have to satisfy its obligations
to creditors before any of its remaining assets could be made available to the
Company. As of December 31, 2006, the facility was undrawn.





41





On August 24, 2006,
the Company, FirstEnergy, OE, Penn, TE, JCP&L, Met-Ed, Penelec, FES and
ATSI, as Borrowers, have 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. Borrowings under the facility are available to each 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 approvals. The average interest rate on short-term borrowings
outstanding as of December 31, 2006 and 2005 was 5.7% and 4.2%,
respectively.





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





**(****A)**
    **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
$1.8 million have been accrued through December 31, 2006.





**(B)**
    **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 and its
subsidiaries. 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**





On May 18,
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 Ohio Companies 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 $33.7 million) between the purchase price specified in the Master
Facility Lease and the net book value at the date of transfer was charged 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 $383.1 million that is secured by a lien on the units
purchased, bears interest at a rate per annum based on the weighted cost of the
Company's long-term debt (5.99%) 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 the Company'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 $31.6 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 the Company's interest in associated decommissioning
trust funds, other related assets and other liabilities associated with the
transferred assets. In addition, the Company received a promissory note from NGC
in the principal amount of approximately $1.0 billion, 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 the
Company's weighted average cost of long-term debt (5.99%), 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 purchase price
adjustments totaling $195.9 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 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 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.





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 with 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 a fossil generation KWH sales
arrangement and the portion of expenses related to its retained leasehold
interests in the Bruce Mansfield Plant. 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
    
    $
    1,275Other property
      and investments
    
    
    446Current
      assets
    
    
    72Deferred
      charges
    
    
    -$
    1,793**Liabilities
      Related to Assets Transferred**Long-term
      debt
    
    $
    -Current
      liabilities
    
    
    -Noncurrent
      liabilities
    
    
    320$
    320**Net
      Assets Transferred**
    
    $
    1,473








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.








45





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





The following
summarizes certain consolidated operating results by quarter for 2006 and
2005.





**Three
      Months Ended**
    
    **March
      31,**
      **2006**
    
    **June
      30,**
      **2006**
    
    **September
      30, 2006**
    
    **December
      31, 2006*****(In
      millions)***Revenues
    
    $
    407.8
    
    $
    432.4
    
    $
    515.9
    
    $
    413.6Expenses
    
    
    283.5
    
    
    280.1
    
    
    375.6
    
    
    303.9Operating
      Income
    
    
    124.3
    
    
    152.3
    
    
    140.3
    
    
    109.7Other
      Expense
    
    
    (7.4
    )
    
    (3.5
    )
    
    (8.4
    )
    
    (12.6
    )Income Before
      Income Taxes
    
    
    116.9
    
    
    148.8
    
    
    131.9
    
    
    97.1Income
      Taxes
    
    
    44.5
    
    
    57.7
    
    
    48.5
    
    
    38.0Net
      Income
    
    $
    72.4
    
    $
    91.1
    
    $
    83.4
    
    $
    59.1








**Three
      Months Ended**
    
    **March
      31,**
      **2005**
    
    **June
      30,**
      **2005**
    
    **September
      30, 2005**
    
    **December
      31, 2005*****(In
      millions)***Revenues
    
    $
    433.2
    
    $
    448.7
    
    $
    526.4
    
    $
    459.8Expenses
    
    
    382.3
    
    
    355.8
    
    
    354.1
    
    
    340.1Operating
      Income
    
    
    50.9
    
    
    92.9
    
    
    172.3
    
    
    119.7Other Income
      (Expense)
    
    
    (26.2
    )
    
    (17.0
    )
    
    6.4
    
    
    (14.9
    )Income Before
      Income Taxes
    
    
    24.7
    
    
    75.9
    
    
    178.7
    
    
    104.8Income
      Taxes
    
    
    9.2
    
    
    37.2
    
    
    68.3
    
    
    38.3Income Before
      Cumulative Effect of a Change in
      Accounting
      Principle
    
    $
    15.5
    
    $
    38.7
    
    $
    110.4
    
    $
    66.5Cumulative
      Effect of a Change in Accounting Principle
      (Net of Income
      Taxes)
    
    
    -
    
    
    -
    
    
    -
    
    
    (3.7)Net
      Income
    
    $
    15.5
    
    $
    38.7
    
    $
    110.4
    
    $
    62.8Earnings on
      Common Stock
    
    $
    12.6
    
    $
    38.7
    
    $
    110.4
    
    $
    62.8









46