Unassociated Document
 


 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C.  20549

FORM 10-Q
(Mark One)
[X]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2007

OR

[  ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the transition period from
 
to
 

Commission
Registrant; State of Incorporation;
I.R.S. Employer
File Number
Address; and Telephone Number
Identification No.
     
333-21011
FIRSTENERGY CORP.
34-1843785
 
(An Ohio Corporation)
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 
     
333-145140-01
FIRSTENERGY SOLUTIONS CORP.
31-1560186
 
(An Ohio Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH 44308
 
 
Telephone (800)736-3402
 
     
1-2578
OHIO EDISON COMPANY
34-0437786
 
(An Ohio Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 
     
1-2323
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
34-0150020
 
(An Ohio Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 
     
1-3583
THE TOLEDO EDISON COMPANY
34-4375005
 
(An Ohio Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 
     
1-3141
JERSEY CENTRAL POWER & LIGHT COMPANY
21-0485010
 
(A New Jersey Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 
     
1-446
METROPOLITAN EDISON COMPANY
23-0870160
 
(A Pennsylvania Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 
     
1-3522
PENNSYLVANIA ELECTRIC COMPANY
25-0718085
 
(A Pennsylvania Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 



Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

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

Indicate by check mark whether any of the registrants is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer  (X)
FirstEnergy Corp.
Accelerated Filer  (  )
N/A
Non-accelerated Filer  (X)
 
 
FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company

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

Yes (  )  No (X)

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

 
OUTSTANDING
CLASS
AS OF OCTOBER 31, 2007
FirstEnergy Corp., $.10 par value
304,835,407
FirstEnergy Solutions Corp., no par value
7
Ohio Edison Company, no par value
60
The Cleveland Electric Illuminating Company, no par value
67,930,743
The Toledo Edison Company, $5 par value
29,402,054
Jersey Central Power & Light Company, $10 par value
14,421,637
Metropolitan Edison Company, no par value
859,500
Pennsylvania Electric Company, $20 par value
4,427,577

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

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

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



This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievement expressed or implied by such forward-looking statements. Actual results may differ materially due to the speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Ohio and Pennsylvania, 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 of FirstEnergy’s regulated utilities to collect transition and other charges or to recover increased transmission costs, maintenance costs being higher than anticipated, other legislative and regulatory changes including revised environmental requirements, the uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated) or levels of emission reductions related to the Consent Decree resolving the New Source Review litigation or other potential regulatory initiatives, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits and oversight) by the NRC (including, but not limited to, the Demand for Information issued to FENOC on May 14, 2007) as disclosed in the registrants’ SEC filings, the timing and outcome of various proceedings before the PUCO (including, but not limited to, the distribution rate cases and the generation supply plan filing for the Ohio Companies and the successful resolution of the issues remanded to the PUCO by the Ohio Supreme Court regarding the RSP and RCP, including the deferral of fuel costs) and the PPUC (including the resolution of the Petitions for Review filed with the Commonwealth Court of Pennsylvania with respect to the transition rate plan for Met-Ed and Penelec), the continuing availability of generating units and their the ability to operate at, or near full capacity, the ability to comply with applicable state and federal reliability standards, the inability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives), the ability to improve electric commodity margins and to experience growth in the distribution business, the 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 the registrants’ SEC filings, and other similar factors. The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible to predict all such factors, nor assess the impact of any such factor on the registrants’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. Also, a security rating is not a recommendation to buy, sell or hold securities, and it may be subject to revision or withdrawal at any time and each such rating should be evaluated independently of any other rating. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

 





TABLE OF CONTENTS



   
Pages
Glossary of Terms
iii-iv
     
Part I.     Financial Information
 
     
Items 1. and 2. - Financial Statements and Management’s Discussion and Analysis of Financial Condition and
                Results of Operations.
 
     
 
Notes to Consolidated Financial Statements
1-34
     
FirstEnergy Corp.
 
     
 
Consolidated Statements of Income
35
 
Consolidated Statements of Comprehensive Income
36
 
Consolidated Balance Sheets
37
 
Consolidated Statements of Cash Flows
38
 
Report of Independent Registered Public Accounting Firm
39
 
Management's Discussion and Analysis of Financial Condition and
40-80
 
Results of Operations
 
     
FirstEnergy Solutions Corp.
 
     
 
Consolidated Statements of Income and Comprehensive Income
81
 
Consolidated Balance Sheets
82
 
Consolidated Statements of Cash Flows
83
 
Report of Independent Registered Public Accounting Firm
84
 
Management's Narrative Analysis of Results of Operations
85-87
     
Ohio Edison Company
 
     
 
Consolidated Statements of Income and Comprehensive Income
88
 
Consolidated Balance Sheets
89
 
Consolidated Statements of Cash Flows
90
 
Report of Independent Registered Public Accounting Firm
91
 
Management's Narrative Analysis of Results of Operations
92-93
     
The Cleveland Electric Illuminating Company
 
     
 
Consolidated Statements of Income and Comprehensive Income
94
 
Consolidated Balance Sheets
95
 
Consolidated Statements of Cash Flows
96
 
Report of Independent Registered Public Accounting Firm
97
 
Management's Narrative Analysis of Results of Operations
98-99
     
The Toledo Edison Company
 
     
 
Consolidated Statements of Income and Comprehensive Income
100
 
Consolidated Balance Sheets
101
 
Consolidated Statements of Cash Flows
102
 
Report of Independent Registered Public Accounting Firm
103
 
Management's Narrative Analysis of Results of Operations
104-105
     

i


TABLE OF CONTENTS (Cont'd)



Jersey Central Power & Light Company
Pages
     
 
Consolidated Statements of Income and Comprehensive Income
106
 
Consolidated Balance Sheets
107
 
Consolidated Statements of Cash Flows
108
 
Report of Independent Registered Public Accounting Firm
109
 
Management's Narrative Analysis of Results of Operations
110-111
     
Metropolitan Edison Company
 
     
 
Consolidated Statements of Income and Comprehensive Income
112
 
Consolidated Balance Sheets
113
 
Consolidated Statements of Cash Flows
114
 
Report of Independent Registered Public Accounting Firm
115
 
Management's Narrative Analysis of Results of Operations
116-117
     
Pennsylvania Electric Company
 
     
 
Consolidated Statements of Income and Comprehensive Income
118
 
Consolidated Balance Sheets
119
 
Consolidated Statements of Cash Flows
120
 
Report of Independent Registered Public Accounting Firm
121
 
Management's Narrative Analysis of Results of Operations
122-123
     
Combined Management’s Discussion and Analysis of Registrant Subsidiaries
124-137
   
Item 3.                      Quantitative and Qualitative Disclosures About Market Risk.
138
     
Item 4.                      Controls and Procedures.
138
     
Part II.    Other Information
 
     
Item 1.                      Legal Proceedings.
139
     
Item 1A.                   Risk Factors.
139
   
Item 2.                      Unregistered Sales of Equity Securities and Use of Proceeds.
139
   
Item 6.                      Exhibits.
140





ii

      
GLOSSARY OF TERMS      
      
        
      
    

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

ATSI
American Transmission Systems, Inc., owns and operates transmission facilities
 
CEI
The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
 
Companies
OE, CEI, TE, JCP&L, Met-Ed and Penelec
 
FENOC
FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
 
FES
FirstEnergy Solutions Corp., provides energy-related products and services
 
FESC
FirstEnergy Service Company, provides legal, financial, and other corporate support services
 
FGCO
FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
 
FirstEnergy
FirstEnergy Corp., a public utility holding company
 
FSG
FirstEnergy Facilities Services Group, LLC, former parent company of several heating, ventilation,
air conditioning and energy management companies
 
GPU
GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on
November 7, 2001
 
JCP&L
Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
 
JCP&L Transition
   Funding
JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition
   bonds
 
JCP&L Transition
   Funding II
JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition
   bonds
 
Met-Ed
Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
 
MYR
MYR Group, Inc., a utility infrastructure construction service company
 
NGC
FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
 
OE
Ohio Edison Company, an Ohio electric utility operating subsidiary
 
Ohio Companies
CEI, OE and TE
 
Penelec
Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
 
Penn
Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
 
Pennsylvania Companies
Met-Ed, Penelec and Penn
 
PNBV
PNBV Capital Trust, a special purpose entity created by OE in 1996
 
Shippingport
Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
 
TE
The Toledo Edison Company, an Ohio electric utility operating subsidiary
 
TEBSA
Termobarranquilla S.A., Empresa de Servicios Publicos
 
     
The following abbreviations and acronyms are used to identify frequently used terms in this report:
 
     
ALJ
Administrative Law Judge
 
APIC
Additional Paid-In Capital
 
AOCL
Accumulated Other Comprehensive Loss
 
ARO
Asset Retirement Obligation
 
BGS
Basic Generation Service
 
CAIR
Clean Air Interstate Rule
 
CAL
Confirmatory Action Letter
 
CAMR
Clean Air Mercury Rule
 
CBP
Competitive Bid Process
 
CO2
Carbon Dioxide
 
DOJ
United States Department of Justice
DRA
Division of Ratepayer Advocate
ECAR
East Central Area Reliability Coordination Agreement
EIS
Energy Independence Strategy
EITF
Emerging Issues Task Force
EITF 06-11
EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends or Share-Based
   Payment Awards”
EMP
Energy Master Plan
EPA
Environmental Protection Agency
EPACT
Energy Policy Act of 2005
ERO
Electric Reliability Organization
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
FIN
FASB Interpretation
FIN 39-1
FIN 39-1, “Amendment of FASB Interpretation No. 39”
FIN 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"

iii

      
GLOSSARY OF TERMS, Cont’d.      
    

FIN 48
FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement
   No. 109”
FMB
First Mortgage Bonds
GAAP
Accounting Principles Generally Accepted in the United States
GHG
Greenhouse Gases
IRS
Internal Revenue Service
kV
Kilovolt
KWH
Kilowatt-hours
LOC
Letter of Credit
MEIUG
Met-Ed Industrial Users Group
MISO
Midwest Independent Transmission System Operator, Inc.
Moody’s
Moody’s Investors Service
MOU
Memorandum of Understanding
MW
Megawatts
NAAQS
National Ambient Air Quality Standards
NERC
North American Electric Reliability Corporation
NJBPU
New Jersey Board of Public Utilities
NOPR
Notice of Proposed Rulemaking
NOV
Notice of Violation
NOX
Nitrogen Oxide
NRC
Nuclear Regulatory Commission
NSR
New Source Review
NUG
Non-Utility Generation
NUGC
Non-Utility Generation Charge
OCA
Office of Consumer Advocate
OCC
Office of the Ohio Consumers’ Counsel
OVEC
Ohio Valley Electric Corporation
PICA
Penelec Industrial Customer Alliance
PJM
PJM Interconnection L. L. C.
PLR
Provider of Last Resort
PPUC
Pennsylvania Public Utility Commission
PRP
Potentially Responsible Party
PSA
Power Supply Agreement
PUCO
Public Utilities Commission of Ohio
PUHCA
Public Utility Holding Company Act of 1935
RCP
Rate Certainty Plan
 
RFP
Request for Proposal
 
RSP
Rate Stabilization Plan
 
RTO
Regional Transmission Organization
 
RTOR
Regional Through and Out Rates
 
S&P
Standard & Poor’s Ratings Service
 
SBC
Societal Benefits Charge
 
SEC
U.S. Securities and Exchange Commission
 
SECA
Seams Elimination Cost Adjustment
 
SFAS
Statement of Financial Accounting Standards
 
SFAS 107
SFAS No. 107, “Disclosure about Fair Value of Financial Instruments”
 
SFAS 109
SFAS No. 109, “Accounting for Income Taxes”
 
SFAS 123(R)
SFAS No. 123(R), "Share-Based Payment"
 
SFAS 133
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
 
SFAS 142
SFAS No. 142, “Goodwill and Other Intangible Assets”
 
SFAS 143
SFAS No. 143, “Accounting for Asset Retirement Obligations”
 
SFAS 157
SFAS No. 157, “Fair Value Measurements”
 
SFAS 159
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an
   Amendment of FASB Statement No. 115”
 
SIP
State Implementation Plan(s) Under the Clean Air Act
 
SNCR
Selective Non-Catalytic Reduction
 
SO2
Sulfur Dioxide
 
SRM
Special Reliability Master
 
TBC
Transition Bond Charge
 
TMI-2
Three Mile Island Unit 2
 
VIE
Variable Interest Entity
 

iv


PART I. FINANCIAL INFORMATION

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

FIRSTENERGY CORP. AND SUBSIDIARIES
FIRSTENERGY SOLUTIONS CORP. AND SUBSIDIARIES
OHIO EDISON COMPANY AND SUBSIDIARIES
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
THE TOLEDO EDISON COMPANY AND SUBSIDIARY
JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES
METROPOLITAN EDISON COMPANY AND SUBSIDIARIES
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


1.  ORGANIZATION AND BASIS OF PRESENTATION

FirstEnergy's principal business is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly owned subsidiary of OE. FirstEnergy’s consolidated financial statements also include its other subsidiaries: FENOC, FES and its subsidiaries FGCO and NGC, and FESC.

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

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2006 for FirstEnergy and the Companies. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain businesses divested in 2006 have been classified as discontinued operations on the Consolidated Statements of Income (see Note 4). As discussed in Note 14, interim period segment reporting in 2006 was reclassified to conform with the current year business segment organizations and operations. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 8) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.

The consolidated financial statements as of September 30, 2007 and for the three-month and nine-month periods ended September 30, 2007 and 2006 have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated October 31, 2007) is included on page 39. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of the registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Exchange Act of 1934.


1


2.  EARNINGS PER SHARE

Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The pool of stock-based compensation tax benefits is calculated in accordance with SFAS 123(R). On August 10, 2006, FirstEnergy repurchased 10.6 million shares, approximately 3.2%, of its outstanding common stock through an accelerated share repurchase program. The initial purchase price was $600 million, or $56.44 per share. A final purchase price adjustment of $27 million was settled in cash on April 2, 2007. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an additional accelerated share repurchase program at an initial price of $62.63 per share, or a total initial purchase price of approximately $900 million. The final purchase price for this program will be adjusted to reflect the volume-weighted average price of FirstEnergy’s common stock during the period of time that the bank will acquire shares to cover its short position, which is expected to be by the end of 2007. The basic and diluted earnings per share calculations shown below reflect the impact associated with these accelerated share repurchase programs. FirstEnergy intends to settle, in cash or shares, any obligation on its part to pay the difference between the average of the daily volume-weighted average price of the shares as calculated under the March 2007 program and the initial price of the shares.

 
 
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
Reconciliation of Basic and Diluted Earnings per Share
 
2007
 
2006
 
2007
 
2006
 
 
 
(In millions, except per share amounts)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income from continuing operations
 
$
413
 
$
452
 
$
1,041
 
$
983
 
Discontinued operations
   
-
   
2
   
-
   
(4
)
Redemption premium on subsidiary preferred stock
   
-
   
-
   
-
   
(3
)
Net earnings available for common shareholders
 
$
413
 
$
454
 
$
1,041
 
$
976
 
 
 
         
 
         
 
Average shares of common stock outstanding – Basic
 
 
304
   
322
 
 
307
   
326
 
Assumed exercise of dilutive stock options and awards
 
 
3
   
3
 
 
4
   
3
 
Average shares of common stock outstanding – Dilutive
 
 
307
   
325
 
 
311
   
329
 
 
 
         
 
         
 
Earnings per share:
 
         
 
         
 
Basic earnings per share:
 
         
 
         
 
Earnings from continuing operations
 
$
1.36
 
$
1.40
 
$
3.39
 
$
3.00
 
Discontinued operations
   
-
   
0.01
   
-
   
(0.01
)
Net earnings per basic share
 
$
1.36
 
$
1.41
 
$
3.39
 
$
2.99
 
                           
Diluted earnings per share:
                         
Earnings from continuing operations
 
$
1.34
 
$
1.39
 
$
3.35
 
$
2.98
 
Discontinued operations
   
-
   
0.01
   
-
   
(0.01
)
Net earnings per diluted share
 
$
1.34
 
$
1.40
 
$
3.35
 
$
2.97
 

3.  GOODWILL

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and more frequently as indicators of impairment arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment is indicated, FirstEnergy recognizes a loss – calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. FirstEnergy's 2007 annual review was completed in the third quarter of 2007 with no impairment indicated.

FirstEnergy's goodwill primarily relates to its energy delivery services segment. In the third quarter of 2007, FirstEnergy adjusted goodwill for the former GPU companies due to the realization of tax benefits that had been reserved in purchase accounting. See Note 12 for a discussion of the tax implications related to the Bruce Mansfield Unit 1 sale and leaseback transaction. The following tables reconcile changes to goodwill for the three months and nine months ended September 30, 2007.

2



Three Months Ended
 
FirstEnergy
 
FES
 
CEI
 
TE
 
JCP&L
 
Met-Ed
 
Penelec
 
   
                 (In millions)                   
 
Balance as of July 1, 2007
 
$
5,898
 
$
24
 
$
1,689
 
$
501
 
$
1,962
 
$
496
 
$
861
 
Adjustments related to GPU acquisition
   
(289
)
 
-
   
-
   
-
   
(136
)
 
(70
)
 
(83
)
Balance as of September 30, 2007
 
$
5,609
 
$
24
 
$
1,689
 
$
501
 
$
1,826
 
$
426
 
$
778
 

Nine Months Ended
 
FirstEnergy
 
FES
 
CEI
 
TE
 
JCP&L
 
Met-Ed
 
Penelec
 
   
(In millions)
 
Balance as of January 1, 2007
 
$
5,898
 
$
24
 
$
1,689
 
$
501
 
$
1,962
 
$
496
 
$
861
 
Adjustments related to GPU acquisition
   
(289
)
 
-
   
-
   
-
   
(136
)
 
(70
)
 
(83
)
Balance as of September 30, 2007
 
$
5,609
 
$
24
 
$
1,689
 
$
501
 
$
1,826
 
$
426
 
$
778
 


4.  DIVESTITURES AND DISCONTINUED OPERATIONS

In 2006, FirstEnergy sold its remaining FSG subsidiaries (Roth Bros., Hattenbach, Dunbar, Edwards and RPC) for an aggregate net after-tax gain of $2.2 million. Hattenbach, Dunbar, Edwards, and RPC are included in discontinued operations for the third quarter and nine months ended September 30, 2006; Roth Bros. did not meet the criteria for that classification.

In March 2006, FirstEnergy sold 60% of its interest in MYR for an after-tax gain of $0.2 million. In June 2006, as part of the March agreement, FirstEnergy sold an additional 1.67% interest. As a result of the March sale, FirstEnergy deconsolidated MYR in the first quarter of 2006 and accounted for its remaining 38.33% interest under the equity method.  In the fourth quarter of 2006, FirstEnergy sold its remaining MYR interest for an after-tax gain of $8.6 million.

The income for the period that MYR was accounted for as an equity method investment has not been included in discontinued operations; however, results prior to the initial sale in March 2006, including the gain on the sale, are reported as discontinued operations.

Revenues associated with discontinued operations were $36 million and $211 million in the third quarter and first nine months of 2006, respectively. The following table summarizes the net income (loss) included in "Discontinued Operations" on the Consolidated Statements of Income for the three months and nine months ended September 30, 2006:

 
 
Three Months
 
 
Nine Months
 
   
(In millions)
 
 
 
 
 
 
 
 
FSG subsidiaries
 
$
2
 
$
(6
)
MYR
 
 
-
   
2
 
Total
 
$
2
 
$
(4
)

5.  DERIVATIVE INSTRUMENTS

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

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criterion. Derivatives that meet that criterion are accounted for using traditional accrual accounting. The changes in the fair value of derivative instruments that do not meet the normal purchase and normal sales criterion are recorded as other expense, as AOCL, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness.

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

3



The net deferred losses of $52 million included in AOCL as of September 30, 2007, for derivative hedging activity, as compared to $58 million as of December 31, 2006, resulted from a net $10 million increase related to current hedging activity and a $16 million decrease due to net hedge losses reclassified to earnings during the nine months ended September 30, 2007. Based on current estimates, approximately $14 million (after tax) of the net deferred losses on derivative instruments in AOCL as of September 30, 2007 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.

FirstEnergy has entered into swaps that have been designated as fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. During the first nine months of 2007, FirstEnergy unwound swaps with a total notional value of $150 million, for which it incurred $8 million in cash losses that will be recognized as interest expense over the remaining maturity of each hedged security. As of September 30, 2007, FirstEnergy had interest rate swaps with an aggregate notional value of $600 million and a fair value of $(14) million.

During 2006 and the first nine months of 2007, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated issuances of fixed-rate, long-term debt securities for one or more of its subsidiaries as outstanding debt matures during 2007 and 2008. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first nine months of 2007, FirstEnergy terminated swaps with a notional value of $1.6 billion for which it paid $20 million, all of which were deemed effective. FirstEnergy will recognize the $20 million loss over the life of the associated future debt. As of September 30, 2007, FirstEnergy had forward swaps with an aggregate notional amount of $400 million and a fair value of $5 million.

6.  ASSET RETIREMENT OBLIGATIONS

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

The ARO liability of $1.2 billion as of September 30, 2007 is primarily related to the nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of September 30, 2007, the fair value of the decommissioning trust assets was approximately $2.1 billion.

The following tables analyze changes to the ARO balances during the three months and nine months ended September 30, 2007 and 2006, respectively.

Three Months Ended
 
FirstEnergy
 
FES
 
OE
 
CEI
 
TE
 
JCP&L
 
Met-Ed
 
Penelec
 
   
(In millions)
 
ARO Reconciliation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
     
Balance, July 1, 2007
 
$
1,228
 
$
784
 
$
91
 
$
2
 
$
27
 
$
87
 
$
156
 
$
79
 
Liabilities incurred
 
 
-
   
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Liabilities settled
 
 
-
   
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Accretion
 
 
19
   
13
 
 
1
 
 
-
 
 
1
 
 
1
 
 
2
 
 
2
 
Revisions in estimated
 
 
                                             
cashflows
 
 
-
   
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Balance, September 30, 2007
 
$
1,247
 
$
797
 
$
92
 
$
2
 
$
28
 
$
88
 
$
158
 
$
81
 
 
 
 
 
 
     
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, July 1, 2006
 
$
1,160
 
$
743
 
$
85
 
$
2
 
$
26
 
$
82
 
$
146
 
$
74
 
Liabilities incurred
 
 
-
   
-
   
-
   
-
   
-
   
-
   
-
   
-
 
Liabilities settled
 
 
-
   
-
   
-
   
-
   
-
   
-
   
-
   
-
 
Accretion
 
 
19
   
13
   
2
   
-
   
-
   
1
   
3
   
2
 
Revisions in estimated
 
 
                                             
cashflows
 
 
-
   
-
   
-
   
-
   
-
   
-
   
-
   
-
 
Balance, September 30, 2006
 
$
1,179
 
$
756
 
$
87
 
$
2
 
$
26
 
$
83
 
$
149
 
$
76
 
 
 
 
 
 
     
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


4



 Nine Months Ended  
  FirstEnergy 
 
  FES
 
  OE
 
  CEI
 
  TE
 
  JCP&L
 
  Met-Ed
    Penelec  
   
                          (In millions)                      
 
ARO Reconciliation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
     
Balance, January 1, 2007
 
$
1,190
 
$
760
 
$
88
 
$
2
 
$
27
 
$
84
 
$
151
 
$
77
 
Liabilities incurred
 
 
-
   
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Liabilities settled
 
 
(2
)
 
(1
)
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Accretion
 
 
59
   
38
 
 
4
 
 
-
 
 
1
 
 
4
 
 
7
 
 
4
 
Revisions in estimated
 
 
                                             
cashflows
 
 
-
   
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Balance, September 30, 2007
 
$
1,247
 
$
797
 
$
92
 
$
2
 
$
28
 
$
88
 
$
158
 
$
81
 
 
 
 
 
 
     
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, January 1, 2006
 
$
1,126
 
$
716
 
$
83
 
$
8
 
$
25
 
$
80
 
$
142
 
$
72
 
Liabilities incurred
 
 
-
   
-
   
-
   
-
   
-
   
-
   
-
   
-
 
Liabilities settled
 
 
(6
)
 
-
   
-
   
(6
)
 
-
   
-
   
-
   
-
 
Accretion
 
 
55
   
36
   
4
   
-
   
1
   
3
   
7
   
4
 
Revisions in estimated
 
 
                                             
cashflows
 
 
4
 
 
4
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Balance, September 30, 2006
 
$
1,179
 
$
756
 
$
87
 
$
2
 
$
26
 
$
83
 
$
149
 
$
76
 


7.  PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its and its subsidiaries’ employees. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December 31, 2006. On January 2, 2007, FirstEnergy made a $300 million voluntary cash contribution to its qualified pension plan. Projections indicate that additional cash contributions are not expected to be required before 2016. FirstEnergy also provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. During 2006, FirstEnergy amended the health care plan effective in 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized health care coverage. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

The components of FirstEnergy's net periodic pension and other postretirement benefit costs (including amounts capitalized) for the three months and nine months ended September 30, 2007 and 2006 consisted of the following:

 
 
           Three Months Ended
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Pension Benefits
 
2007
 
2006
 
2007
 
2006
 
 
 
(In millions)
 
Service cost
 
$
21
 
$
21
 
$
63
 
$
63
 
Interest cost
 
 
71
 
 
66
 
 
213
 
 
199
 
Expected return on plan assets
 
 
(112
)
 
(99
)
 
(337
)
 
(297
)
Amortization of prior service cost
 
 
2
 
 
2
 
 
7
 
 
7
 
Recognized net actuarial loss
 
 
10
 
 
15
 
 
31
 
 
44
 
Net periodic cost (credit)
 
$
(8
)
$
5
 
$
(23
)
$
16
 

 
 
           Three Months Ended
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Other Postretirement Benefits
 
2007
 
2006
 
2007
 
2006
 
 
 
(In millions)
 
Service cost
 
$
5
 
$
9
 
$
16
 
$
26
 
Interest cost
 
 
17
 
 
26
 
 
52
 
 
79
 
Expected return on plan assets
 
 
(12
)
 
(12
)
 
(38
)
 
(35
)
Amortization of prior service cost
 
 
(37
)
 
(19
)
 
(112
)
 
(57
)
Recognized net actuarial loss
 
 
11
 
 
14
 
 
34
 
 
42
 
Net periodic cost (credit)
 
$
(16
)
$
18
 
$
(48
)
$
55
 


5



Pension and other postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. FirstEnergy’s subsidiaries capitalize employee benefit costs related to construction projects. The net periodic pension and other postretirement benefit costs (including amounts capitalized) recognized by FES and each of the Companies for the three months and nine months ended September 30, 2007 and 2006 were as follows:

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Pension Benefit Cost (Credit)
 
2007
 
2006
 
2007
 
2006
 
 
 
(In millions)
 
FES
 
$
5.2
 
$
9.9
 
$
15.7
 
$
29.9
 
OE
 
 
(4.0
)
 
(1.5
)
 
(11.9
)
 
(4.5
)
CEI
 
 
0.3
 
 
1.0
 
 
0.9
 
 
2.9
 
TE
 
 
-
 
 
0.2
 
 
(0.1
)
 
0.7
 
JCP&L
 
 
(2.1
)
 
(1.4
)
 
(6.4
)
 
(4.1
)
Met-Ed
 
 
(1.7
)
 
(1.7
)
 
(5.1
)
 
(5.2
)
Penelec
 
 
(2.6
)
 
(1.3
)
 
(7.7
)
 
(4.0
)
Other FirstEnergy subsidiaries
   
(2.7
)
 
-
   
(8.1
)
 
-
 
   
$
(7.6
)
$
5.2
 
$
(22.7
)
$
15.7
 


 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Other Postretirement Benefit Cost (Credit)
 
2007
 
2006
 
2007
 
2006
 
 
 
(In millions)
 
FES
 
$
(2.4
)
$
3.4
 
$
(7.4
)
$
10.2
 
OE
 
 
(2.7
)
 
4.2
   
(8.0
)
 
12.6
 
CEI
 
 
1.0
 
 
2.8
 
 
2.9
 
 
8.3
 
TE
 
 
1.2
 
 
2.0
 
 
3.7
 
 
6.1
 
JCP&L
 
 
(4.0
)
 
0.6
 
 
(11.9
)
 
1.8
 
Met-Ed
 
 
(2.5
)
 
0.7
 
 
(7.7
)
 
2.2
 
Penelec
 
 
(3.2
)
 
1.8
 
 
(9.5
)
 
5.4
 
Other FirstEnergy subsidiaries
   
(3.3
)
 
2.7
   
(9.8
)
 
7.9
 
   
$
(15.9
)
$
18.2
 
$
(47.7
)
$
54.5
 

8.  VARIABLE INTEREST ENTITIES

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

Trusts

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

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

OE, CEI and TE are exposed to losses under the applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $827 million, $758 million and $758 million, respectively, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the applicable sale and leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $606 million, $73 million and $429 million, respectively, that would not be payable if the casualty value payments are made.

6



Effective October 16, 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. FGCO assumed all of CEI’s and TE’s obligations arising under those leases. However, CEI and TE will remain primarily liable on the leases and related agreements as to the lessors and other parties to the agreements. The assignment terminates automatically upon the termination of the underlying leases.

Power Purchase Agreements

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

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

Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it incurs for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. As of September 30, 2007, the net above-market loss liability projected for these eight NUG agreements was $158 million. Purchased power costs from these entities during the three months and nine months ended September 30, 2007 and 2006 are shown in the following table:

   
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 
 
2007
 
2006
 
2007
 
2006
 
   
(In millions)
 
JCP&L
 
$
30
 
$
29
 
$
71
 
$
63
 
Met-Ed
 
 
13
 
 
12
 
 
40
 
 
45
 
Penelec
 
 
7
 
 
8
 
 
22
 
 
22
 
Total
 
$
50
 
$
49
 
$
133
 
$
130
 


Transition Bonds

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

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of September 30, 2007, $404 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.

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

7



9.  INCOME TAXES

On January 1, 2007, FirstEnergy adopted FIN 48, which provides guidance for accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. This interpretation prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. FIN 48 also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation is a two-step process. The first step is to determine if it is more likely than not that a tax position will be sustained upon examination, based on the merits of the position, and should therefore be recognized. The second step is to measure a tax position that meets the more likely than not recognition threshold to determine the amount of income tax benefit to recognize in the financial statements.

As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits was $268 million. FirstEnergy recorded a $2.7 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate upon recognition. The majority of items that would not have affected the effective tax rate would be purchase accounting adjustments to goodwill upon recognition. During the first nine months of 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of September 30, 2007, the entire liability for uncertain tax positions is included in other non-current liabilities and changes to FirstEnergy’s tax contingencies that are reasonably possible in the next twelve months are not material.

FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. As of January 1, 2007, the net amount of interest accrued was $34 million. During the first nine months of 2007, there were no material changes to the amount of interest accrued.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2006. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audit for years 2004 and 2005 began in June 2006 and is not expected to close before December 2007. The IRS began auditing the year 2006 in April 2006 under its Compliance Assurance Process experimental program, which is not expected to close before December 2007. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity (see Note 12). This transaction generated tax capital gains of approximately $752 million, all of which were offset by existing tax capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowances in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 3).

10.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A)    GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of September 30, 2007, outstanding guarantees and other assurances aggregated approximately $4.7 billion, consisting of parental guarantees - $1.2  billion, subsidiaries’ guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $0.7  billion.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for subsidiary financings or refinancings of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.6 billion (included in the $1.2 billion discussed above) as of September 30, 2007 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

8



While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating-downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of September 30, 2007, FirstEnergy's maximum exposure under these collateral provisions was $442 million.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $75 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions.

The Companies, with the exception of TE and JCP&L, each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company.

       
Borrowing
 
Subsidiary Company
 
Parent Company
 
Capacity
 
 
 
 
 
(In millions)
 
OES Capital, Incorporated
 
 
OE
 
$
170
 
Centerior Funding Corp.
 
 
CEI
 
 
200
 
Penn Power Funding LLC
 
 
Penn
 
 
25
 
Met-Ed Funding LLC
 
 
Met-Ed
 
 
80
 
Penelec Funding LLC
 
 
Penelec
 
 
75
 
 
 
 
 
 
$
550
 

FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($27 million as of September 30, 2007), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. The LOC was reduced to $19 million on October 15, 2007.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1 (see Note 12). FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases.  The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.

(B)    ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy estimates capital expenditures for environmental compliance of approximately $1.8 billion for 2007 through 2011.

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

Clean Air Act Compliance

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

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

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

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act, alleging violations of air pollution laws at the Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 16, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. FirstEnergy is currently studying PennFuture’s complaint.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR allowed each affected state until 2006 to develop implementing regulations to achieve additional reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2). FirstEnergy's Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO2 and NOX emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on NOX emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOX emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOX cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

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The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FirstEnergy would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FirstEnergy will be disadvantaged if these model rules were implemented as proposed because FirstEnergy’s substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

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

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn, and is now owned by FGCO. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as the New Source Review, or NSR, cases.

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreement are currently estimated to be $1.7 billion for 2007 through 2011 ($400 million of which is expected to be spent during 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009).

The Sammis NSR Litigation consent decree also requires FirstEnergy to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. At the international level, efforts have begun to develop climate change agreements for post-2012 GHG reductions. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States.  State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

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On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the Clean Air Act. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the Clean Air Act to regulate “air pollutants” from those and other facilities. Also on April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, the EPA proposed to change the NSR regulations, on May 8, 2007, to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.

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

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. On January 26, 2007, the federal Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to EPA for further rulemaking and eliminated the restoration option from EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. FirstEnergy is evaluating various control options and their costs and effectiveness. Depending on the outcome of such studies, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future cost of compliance with these standards may require material capital expenditures.

Regulation of Hazardous Waste

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

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.  As of September 30, 2007, FirstEnergy had approximately $1.5 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry.  As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans to seek for these facilities.

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site 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 September 30, 2007, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $89 million (JCP&L - $60 million, TE - $3 million, CEI - $1 million, and FirstEnergy Corp. - $25 million) have been accrued through September 30, 2007.

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(C)   OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages.  JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007.  Proceedings are continuing in the Superior Court.  FirstEnergy is defending this class action but is unable to predict the outcome of this matter.  No liability has been accrued as of September 30, 2007.

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). FirstEnergy believes 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. FirstEnergy remains 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.

13


FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those 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. Two 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 cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc. (AEP), as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. 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. The four cases remaining were consolidated for hearing by the PUCO in an order dated March 7, 2006.  In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled 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 January 8, 2008.

FirstEnergy is 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 FirstEnergy is 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 FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Nuclear Plant Matters

On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information to FENOC following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for Information reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. The NRC held a public meeting on June 27, 2007 with FENOC to discuss FENOC’s response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC’s compliance with these commitments is subject to future NRC review.

Other Legal Matters

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

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

14


JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. The arbitration panel provided additional rulings regarding damages during a September 2007 hearing and it is anticipated that he will issue a final order in late 2007. JCP&L intends to re-file an appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

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

11.  REGULATORY MATTERS

(A) RELIABILITY INITIATIVES

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (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.

As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L’s ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a stipulation that incorporates the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L’s Planning and Operations and Maintenance programs and practices. On February 11, 2005, JCP&L met with the DRA to discuss reliability improvements. The SRM completed his work and issued his final report to the NJBPU on June 1, 2006. JCP&L filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L continues to file compliance reports reflecting activities associated with the MOU and stipulation.

The EPACT served, among other things, partly to amend the Federal Power Act by adding a new Section 215, which requires that a new ERO establish and enforce reliability standards for the bulk-power system, subject to review by the FERC. Subsequently, the FERC certified NERC as the ERO, approved NERC's Compliance Monitoring and Enforcement Program and approved a set of reliability standards, which became mandatory and enforceable on June 18, 2007 with penalties and sanctions for noncompliance. The FERC also approved a delegation agreement between NERC and ReliabilityFirst Corporation, one of eight Regional Entities that carry out enforcement for NERC.  All of FirstEnergy’s facilities are located within the ReliabilityFirst region.

To date, FERC has approved 83 of the 107 reliability standards proposed by NERC. Nevertheless, the FERC has directed NERC to submit improvements to 56 of the 83 approved standards and has endorsed NERC's process for developing reliability standards and its associated work plan. On May 4, 2007, NERC submitted 24 proposed Violation Risk Factors that would operate as a system of weighting the risk to the power grid associated with a particular reliability standard violation. The FERC issued an order approving 22 of those factors on June 26, 2007. Further, NERC adopted eight cyber security standards and filed them with the FERC for approval. On December 11, 2006, the FERC Staff provided its preliminary assessment of the cyber security standards and cited various deficiencies in the proposed standards. Numerous parties, including FirstEnergy, provided comments on the preliminary assessment. The standards remain pending before the FERC. Separately, on July 20, 2007, the FERC issued a NOPR proposing to adopt eight related Critical Infrastructure Protection Reliability Standards. On October 5, 2007, numerous parties, including FirstEnergy, provided comments on the proposed Critical Infrastructure Protection standards. These standards, and FirstEnergy’s comments thereon, are pending before FERC.

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FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the FERC's guidance to NERC in its March 16, 2007 Final Rule on Mandatory Reliability Standards, it appears that the FERC may eventually adopt stricter standards than those just approved. 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 April 18-20, 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy's bulk-power system within the Midwest ISO region and found FirstEnergy to be in full compliance with all audited reliability standards.  Similarly, ReliabilityFirst has scheduled a compliance audit of FirstEnergy's bulk-power system within the PJM region in 2008. FirstEnergy does not expect any material adverse impact to its financial condition as a result of these audits.

(B) OHIO

On September 9, 2005, the Ohio Companies filed their RCP with the PUCO. The filing included a stipulation and supplemental stipulation with several parties agreeing to the provisions set forth in the plan. On January 4, 2006, the PUCO issued an order which approved the stipulation on the RCP after clarifying certain provisions. Several parties subsequently filed appeals to the Supreme Court of Ohio in connection with certain portions of the RCP approved by the PUCO. In its order, the PUCO authorized the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs, all such costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a 25-year period through distribution rates, which was expected to begin on January 1, 2009 for OE and TE, and approximately May 2009 for CEI.  Through September 30, 2007, the deferred fuel costs, including interest, were $89 million, $61 million and $26 million for OE, CEI and TE, respectively.

On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated certain provisions of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” because fuel costs are a component of generation service, not distribution service, and because the Court concluded the PUCO did not address whether the deferral of fuel costs was anticompetitive.  The Court remanded the matter to the PUCO for further consideration consistent with the Court’s Opinion on this issue and affirmed the PUCO’s Order in all other respects. On September 7, 2007, the Ohio Companies filed a Motion for Reconsideration with the Court. On September 10, 2007 the Ohio Companies filed an Application with the PUCO that requests the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. The Ohio Companies requested the riders become effective in October 2007 and end in December 2008, subject to reconciliation which is expected to continue through the first quarter of 2009. This matter is currently pending before the PUCO. Although unable to predict the ultimate outcome of this matter, the Ohio Companies intend to continue deferring the fuel costs pursuant to the RCP, pending the Court’s disposition of the Motion for Reconsideration and the PUCO’s action with respect to the Ohio Companies’ Application.

On August 31, 2005, the PUCO approved a rider recovery mechanism through which the Ohio Companies may recover all MISO transmission and ancillary service related costs incurred during each year ending June 30. Pursuant to the PUCO’s order, the Ohio Companies, on May 1, 2007, filed revised riders, which became effective on July 1, 2007.  The revised riders represent an increase over the amounts collected through the 2006 riders of approximately $64 million annually.  If it is subsequently determined by the PUCO that adjustments to the rider as filed are necessary, such adjustments, with carrying costs, will be incorporated into the 2008 transmission rider filing.

On May 8, 2007, the Ohio Companies filed with the PUCO a notice of intent to file for an increase in electric distribution rates. The Ohio Companies filed the application and rate request with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the bill for most Ohio customers.  The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operating and maintenance expenses and recovery of regulatory assets created by deferrals that were approved in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million to the PUCO to establish the test period data that will be used as the basis for setting rates in that proceeding. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in early 2008. The PUCO order is expected to be issued in the second quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

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On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Comments by intervenors in the case were filed on September 5, 2007.  The PUCO Staff filed comments on September 21, 2007.  Parties filed reply comments on October 12, 2007. The Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process.

On September 25, 2007, the Ohio Governor’s proposed energy plan was officially introduced into the Ohio Senate. The bill proposes to revise state energy policy to address electric generation pricing after 2008, establish advanced energy portfolio standards and energy efficiency standards, and create GHG emissions reporting and carbon control planning requirements. The bill also proposes to move to a “hybrid” system for determining rates for PLR service in which electric utilities would provide regulated generation service unless they satisfy a statutory burden to demonstrate the existence of a competitive market for retail electricity. The Senate Energy & Public Utilities Committee has been conducting hearings on the bill and receiving testimony from interested parties, including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer groups, utility executives and others. Several proposed amendments to the bill have been submitted, including those from Ohio’s investor-owned electric utilities. A substitute version of the bill, which incorporated certain of the proposed amendments, was introduced into the Senate Energy & Public Utilities Committee on October 25, 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of the Ohio Companies.

(C) PENNSYLVANIA

Met-Ed and Penelec have been purchasing a portion of their PLR requirements from FES through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy requirements during the term of these agreements with FES.

On September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that were substantially higher than the fixed price in the partial requirements agreements.

Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.

If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.

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

The PPUC entered its Opinion and Order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, when new transmission rates were effective, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes in NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission expenses and the transmission deferral. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part the MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase.  The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. On June 19, 2007, initial briefs were filed and responsive briefs were filed through September 21, 2007.  Reply briefs were filed on October 5, 2007. Oral arguments are expected to take place in late 2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the financial condition and results of operations of Met-Ed, Penelec and FirstEnergy.

As of September 30, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $496 million and $58 million, respectively. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in February 2007 and briefing was completed on March 28, 2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.

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On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service will be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed.  On September 28, 2007, Penn filed a Joint Petition for Settlement resolving all but one issue in the case.  Briefs were also filed on September 28, 2007 on the unresolved issue of incremental uncollectible accounts expense.  The settlement is either supported, or not opposed, by all parties. The PPUC is expected to act on the settlement and the unresolved issue in late November or early December 2007 for the initial RFP to take place in January 2008.

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation programs to meet demand growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and an optional three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The final form of any legislation arising from the special legislative session is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

(D) NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2007, the accumulated deferred cost balance totaled approximately $330 million.

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

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L.  Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. Comments on the alternative proposal were submitted on June 15, 2006. On November 3, 2006, the Staff circulated a revised draft proposal to interested stakeholders. Another revised draft was circulated by the NJBPU Staff on February 8, 2007.

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated with the issuance of a proposed set of objectives which, as to electricity, included the following:

·   Reduce the total projected electricity demand by 20% by 2020;

·  
Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date;

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·   Reduce air pollution related to energy use;

·   Encourage and maintain economic growth and development;

·  
Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020;

·  
Maintain unit prices for electricity to no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia); and

·   Eliminate transmission congestion by 2020.

Comments on the objectives and participation in the development of the EMP have been solicited and a number of working groups have been formed to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing (1) energy efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing issues have completed their assigned tasks of data gathering and analysis and have provided reports to the EMP Committee. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected later in 2007. A final draft of the EMP is expected to be presented to the Governor in late 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of JCP&L.

On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards.  Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff.  On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments which were due on September 26, 2007.  At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such regulations may have on its operations or those of JCP&L.

(E) FERC MATTERS

On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the fourth quarter of 2007.

On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas & Electric Company (BG&E) and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. Hearings were held and numerous parties appeared and litigated various issues; including AEP, which filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. At the conclusion of the hearings, the ALJ issued an initial decision adopting the FERC Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate. The ALJ recommended an April 1, 2006 effective date for this change in rate design. Numerous parties, including FirstEnergy, submitted briefs opposing the ALJ’s decision and recommendations.  On April 19, 2007, the FERC issued an order rejecting the ALJ’s findings and recommendations in nearly every respect. The FERC found that the PJM transmission owners’ existing “license plate” rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be socialized throughout the PJM footprint by means of a postage-stamp rate.  Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis.  Nevertheless, the FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

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On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 Order.  Subsequently, FirstEnergy and other parties filed pleadings opposing the requests for rehearing. The FERC’s Orders on PJM rate design, if sustained on rehearing and appeal, will prevent the allocation of the cost of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec.  In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission costs shifting to the JCP&L, Met-Ed and Penelec zones.

    New FERC Transmission Rate Design Filings

On August 1, 2007, a number of filings were made with the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.

FirstEnergy joined in a filing made by the MISO transmission owners that would maintain the existing “license plate” rates for transmission service within MISO provided over existing transmission facilities.  FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to continue the elimination of transmission rates associated with service over existing transmission facilities between MISO and PJM.  If adopted by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities.  In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint be maintained (known as the RECB Process). Each of these filings was supported by the majority of transmission owners in either MISO or PJM, as applicable.

The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV and higher transmission facilities be spread throughout the entire MISO footprint.  Further, Indianapolis Power and Light Company separately moved the FERC to reopen the record to address the cost allocation for the RECB Process.  If either proposal is adopted by the FERC, it could shift a greater portion of the cost of new 345 kV and higher transmission facilities to the FirstEnergy footprint in MISO, and increase the transmission rates paid by load-serving FirstEnergy affiliates in MISO.

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “SuperRegion” that regionalizes the cost of new and existing transmission facilities operated at voltages of 345 kV and above.  Lower voltage facilities would continue to be recovered in the host utility transmission rate zone through a license plate rate.  AEP requests a refund effective October 1, 2007, or alternatively, February 1, 2008.  The effect of this proposal, if adopted by FERC, would be to shift significant costs to the FirstEnergy zones in MISO and PJM.  FirstEnergy believes that most of these costs would ultimately be recoverable in retail rates. On October 12, 2007, BG&E filed a motion to dismiss AEP’s complaint. On October 16, 2007, the Organization of MISO States filed comments urging the FERC to dismiss AEP’s complaint. Interventions and protests to AEP’s complaint and answers to BG&E’s motion to dismiss were due October 29, 2007. FirstEnergy and other transmission owners filed protests to AEP’s complaint and support for BG&E’s motion to dismiss. AEP has asked for consolidation of its complaint with the cases above, and FirstEnergy expects it to be resolved on the same timeline as those cases.

Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC.  All or some of these proceedings may be consolidated by the FERC and set for hearing.  The outcome of these cases cannot be predicted.  Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates.  FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates.  Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.

    MISO Ancillary Services Market and Balancing Area Consolidation Filing

MISO made a filing on September 14, 2007 to establish Ancillary Services markets for regulation, spinning and supplemental reserves to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region.  An effective date of June 1, 2008 was requested in the filing.

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MISO’s previous filing to establish an Ancillary Services market was rejected without prejudice by FERC on June 22, 2007, subject to MISO making certain modifications in its filing. FirstEnergy believes that MISO’s September 14 filing generally addresses the FERC’s directives.  FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas, but filed objections on specific aspects of the MISO proposal.  Interventions and protests to MISO’s filing were made with FERC on October 15, 2007.

    Order No. 890 on Open Access Transmission Tariffs

On February 16, 2007, the FERC issued a final rule (Order No. 890) 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 became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffs to comply with the FERC’s order. MISO, PJM and ATSI submitted tariff filings to the FERC on October 11, 2007. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.

12.  LEASES

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion (net after-tax proceeds of approximately $1.2 billion) for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034.  A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates.  The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. FES’ registration obligations under the registration rights agreement applicable to the $1.135 billion principal amount of pass through certificates issued in connection with the transaction were satisfied in September 2007, at which time the transaction was classified as an operating lease under GAAP for FES and FirstEnergy. This transaction generated tax capital gains of approximately $752 million, all of which were offset by existing tax capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowances in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 3).

The future minimum lease payments associated with the recently completed Bruce Mansfield Unit 1 sale and leaseback transaction as of September 30, 2007 are as follows (in millions):

2007
$
44
2008
 
89
2009
 
89
2010
 
89
2011
 
89
Years thereafter
 
2,286
Total minimum lease payments
$
2,686


13.  NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

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. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

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

In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value. This Statement 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 and SFAS 107. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

EITF 06-11 – “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”

In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R).  The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to APIC. This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement.  The consensus is effective for income tax benefits of dividends declared during fiscal years beginning after December 15, 2007.  EITF 06-11 is not expected to have a material effect on FirstEnergy’s financial statements.

FSP FIN 39-1 – “Amendment of FASB Interpretation No. 39”

In April 2007, the FASB issued Staff Position (FSP) FIN 39-1, which permits an entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement as the derivative instruments.  This FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. The effects of applying the guidance in this FSP should be recognized as a retrospective change in accounting principle for all financial statements presented. FirstEnergy is currently evaluating the impact of this FSP on its financial statements but it is not expected to have a material impact.

14.  SEGMENT INFORMATION

Effective January 1, 2007, FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. None of the aggregate “Other” segments individually meet the criteria to be considered a reportable segment. The energy delivery services segment consists of regulated transmission and distribution operations, including transition cost recovery, and PLR generation service for FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. The competitive energy services segment primarily consists of unregulated generation and commodity operations, including competitive electric sales, and generation sales to affiliated electric utilities. The Ohio transitional generation services segment represents PLR generation service by FirstEnergy’s Ohio electric utility subsidiaries. “Other” primarily consists of telecommunications services and other non-core assets. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”

The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. Its revenues are primarily derived from the delivery of electricity, cost recovery of regulatory assets and PLR electric generation sales to non-shopping customers in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under partial requirements purchased power agreements and non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.

The competitive energy services segment supplies electric power to its electric utility affiliates and competitive electric sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. The segment owns or leases and operates FirstEnergy’s generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from the affiliated company power sales and the non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment’s customers. The segment’s internal revenues represent the affiliated company power sales.

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The Ohio transitional generation services segment represents the regulated generation operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect the purchase of electric generation from the competitive energy services segment through full requirements PSA arrangements, the deferral and amortization of certain fuel costs authorized for recovery by the energy delivery services segment and the net MISO transmission revenues and expenses related to the delivery of its generation load. This segment’s total assets consist of accounts receivable for generation revenues from retail customers.

Segment reporting in 2006 has been revised to conform to the current year business segment organization and operations. Changes in the current year operations reporting and revised 2006 segment reporting primarily reflect the transfer from FES to the regulated utilities of the responsibility for obtaining PLR generation for the utilities’ non-shopping customers. This reflects FirstEnergy’s alignment of its business units to accommodate its retail strategy and participation in competitive electricity marketplaces in Ohio, Pennsylvania and New Jersey. The differentiation of the regulated generation commodity operations between the two regulated business segments recognizes that generation sourcing for the Ohio Companies is currently in a transitional state through 2008 as compared to the segregated commodity sourcing of their Pennsylvania and New Jersey utility affiliates. The results of the energy delivery services and the Ohio transitional generation services segments now include their electric generation revenues and the corresponding generation commodity costs under affiliated and non-affiliated purchased power arrangements and related net retail PJM/MISO transmission expenses associated with serving electricity load in their respective franchise areas.

FSG completed the sale of its five remaining subsidiaries in 2006. Its assets and results for 2006 are combined in the “Other” segments in this report, as the remaining business does not meet the criteria of a reportable segment. Interest expense on holding company debt and corporate support services revenues and expenses are included in "Reconciling Adjustments."

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Segment Financial Information
                               
               
Ohio
                   
   
Energy
   
Competitive
   
Transitional
                   
   
Delivery
   
Energy
   
Generation
         
Reconciling
       
Three Months Ended
 
Services
   
Services
   
Services
   
Other
   
Adjustments
   
Consolidated
 
   
(In millions)               
 
September 30, 2007
                                   
External revenues
  $
2,520
    $
370
    $
723
    $
9
    $
19
    $
3,641
 
Internal revenues
   
-
     
806
     
-
     
-
      (806 )    
-
 
Total revenues
   
2,520
     
1,176
     
723
     
9
      (787 )    
3,641
 
Depreciation and amortization
   
299
     
51
      (16 )    
1
     
8
     
343
 
Investment income
   
58
     
5
     
-
     
1
      (34 )    
30
 
Net interest charges
   
117
     
39
     
-
     
1
     
37
     
194
 
Income taxes
   
175
     
99
     
11
      (2 )     (10 )    
273
 
Net income
   
269
     
148
     
16
     
6
      (26 )    
413
 
Total assets
   
23,308
     
7,182
     
268
     
232
     
663
     
31,653
 
Total goodwill
   
5,585
     
24
     
-
     
-
     
-
     
5,609
 
Property additions
   
209
     
199
     
-
     
1
     
21
     
430
 
                                                 
September 30, 2006
                                               
External revenues
  $
2,306
    $
353
    $
690
    $
24
    $ (9 )   $
3,364
 
Internal revenues
   
-
     
762
     
-
     
-
      (762 )    
-
 
Total revenues
   
2,306
     
1,115
     
690
     
24
      (771 )    
3,364
 
Depreciation and amortization
   
227
     
49
      (40 )    
1
     
6
     
243
 
Investment income
   
80
     
18
     
-
     
-
      (52 )    
46
 
Net interest charges
   
107
     
49
     
-
     
2
     
22
     
180
 
Income taxes
   
187
     
112
     
18
      (14 )     (30 )    
273
 
Income from
                                               
continuing operations
   
280
     
169
     
27
     
25
      (49 )    
452
 
Discontinued operations
   
-
     
-
     
-
     
2
     
-
     
2
 
Net income
   
280
     
169
     
27
     
27
      (49 )    
454
 
Total assets
   
23,940
     
6,822
     
240
     
321
     
839
     
32,162
 
Total goodwill
   
5,911
     
24
     
-
     
-
     
-
     
5,935
 
Property additions
   
119
     
126
     
-
     
-
     
6
     
251
 
                                                 
Nine Months Ended
                                               
                                                 
September 30, 2007
                                               
External revenues
  $
6,655
    $
1,089