10-Q 1 main_10q.htm FORM 10-Q DATED SEPTEMBER 30, 2007 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.

23



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."

24


 
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
    $
1,968
    $
29
    $ (18 )   $
9,723
 
Internal revenues
   
-
     
2,210
     
-
     
-
      (2,210 )    
-
 
Total revenues
   
6,655
     
3,299
     
1,968
     
29
      (2,228 )    
9,723
 
Depreciation and amortization
   
767
     
153
      (80 )    
3
     
20
     
863
 
Investment income
   
190
     
13
     
1
     
1
      (112 )    
93
 
Net interest charges
   
340
     
131
     
1
     
3
     
97
     
572
 
Income taxes
   
464
     
259
     
46
     
-
      (74 )    
695
 
Net income
   
695
     
388
     
69
     
13
      (124 )    
1,041
 
Total assets
   
23,308
     
7,182
     
268
     
232
     
663
     
31,653
 
Total goodwill
   
5,585
     
24
     
-
     
-
     
-
     
5,609
 
Property additions
   
609
     
462
     
-
     
4
     
52
     
1,127
 
                                                 
September 30, 2006
                                               
External revenues
  $
5,876
    $
1,077
    $
1,808
    $
92
    $ (32 )   $
8,821
 
Internal revenues
   
14
     
1,997
     
-
     
-
      (2,011 )    
-
 
Total revenues
   
5,890
     
3,074
     
1,808
     
92
      (2,043 )    
8,821
 
Depreciation and amortization
   
657
     
143
      (89 )    
3
     
17
     
731
 
Investment income
   
244
     
35
     
-
     
1
      (160 )    
120
 
Net interest charges
   
308
     
139
     
1
     
5
     
60
     
513
 
Income taxes
   
468
     
201
     
58
      (17 )     (85 )    
625
 
Income from
                                               
continuing operations
   
702
     
302
     
88
     
30
      (139 )    
983
 
Discontinued operations
   
-
     
-
     
-
      (4 )    
-
      (4 )
Net income
   
702
     
302
     
88
     
26
      (139 )    
979
 
Total assets
   
23,940
     
6,822
     
240
     
321
     
839
     
32,162
 
Total goodwill
   
5,911
     
24
     
-
     
-
     
-
     
5,935
 
Property additions
   
489
     
473
     
-
     
-
     
28
     
990
 
 
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses and elimination of intersegment transactions.

25



15.  SUPPLEMENTAL GUARANTOR INFORMATION

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

The consolidating statements of income for the three months and nine months ended September 30, 2007 and 2006, consolidating balance sheets as of September 30, 2007 and December 31, 2006 and condensed consolidating statements of cash flows for the nine months ended September 30, 2007 and 2006 for FES (parent), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and reflect the consolidating entries associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

26


 
 

FIRSTENERGY SOLUTIONS CORP.              
 
                               
CONSOLIDATING STATEMENTS OF INCOME            
 
(Unaudited)              
 
                               
For the Three Months Ended September 30, 2007
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)         
 
                               
REVENUES
  $
1,180,449
    $
496,204
    $
280,072
    $ (785,817 )   $
1,170,908
 
                                         
EXPENSES:
                                       
Fuel
   
10,944
     
261,759
     
29,083
     
-
     
301,786
 
Purchased power from non-affiliates
   
228,755
     
-
     
-
     
-
     
228,755
 
Purchased power from affiliates
   
774,873
     
57,927
     
15,525
      (785,817 )    
62,508
 
Other operating expenses
   
41,828
     
75,985
     
117,220
     
-
     
235,033
 
Provision for depreciation
   
650
     
24,669
     
23,181
     
-
     
48,500
 
General taxes
   
5,406
     
11,788
     
5,048
     
-
     
22,242
 
Total expenses
   
1,062,456
     
432,128
     
190,057
      (785,817 )    
898,824
 
                                         
OPERATING INCOME
   
117,993
     
64,076
     
90,015
     
-
     
272,084
 
                                         
OTHER INCOME (EXPENSE):
                                       
Miscellaneous income (expense), including
                                       
net income from equity investees
   
82,870
     
2,375
     
3,935
      (76,525 )    
12,655
 
Interest expense to affiliates
    (676 )     (4,769 )     (4,196 )    
-
      (9,641 )
Interest expense - other
    (808 )     (21,274 )     (9,712 )    
-
      (31,794 )
Capitalized interest
   
9
     
3,889
     
1,233
     
-
     
5,131
 
Total other income (expense)
   
81,395
      (19,779 )     (8,740 )     (76,525 )     (23,649 )
                                         
INCOME BEFORE INCOME TAXES
   
199,388
     
44,297
     
81,275
      (76,525 )    
248,435
 
                                         
INCOME TAXES
   
44,624
     
19,850
     
29,197
     
-
     
93,671
 
                                         
NET INCOME
  $
154,764
    $
24,447
    $
52,078
    $ (76,525 )   $
154,764
 

27

 

FIRSTENERGY SOLUTIONS CORP.              
 
                               
CONSOLIDATING STATEMENTS OF INCOME            
 
(Unaudited)              
 
                               
For the Three Months Ended September 30, 2006
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)         
 
                               
REVENUES
  $
1,120,844
    $
466,628
    $
246,039
    $ (723,931 )   $
1,109,580
 
                                         
EXPENSES:
                                       
Fuel
   
12,632
     
273,398
     
29,491
     
-
     
315,521
 
Purchased power from non-affiliates
   
173,620
      -      
-
     
-
     
173,620
 
Purchased power from affiliates
   
711,298
     
52,062
     
16,218
      (723,931 )    
55,647
 
Other operating expenses
   
42,115
     
48,728
     
107,873
     
-
     
198,716
 
Provision for depreciation
   
456
     
24,656
     
21,782
     
-
     
46,894
 
General taxes
   
3,223
     
8,931
     
5,455
     
-
     
17,609
 
Total expenses
   
943,344
     
407,775
     
180,819
      (723,931 )    
808,007
 
                                         
OPERATING INCOME
   
177,500
     
58,853
     
65,220
     
-
     
301,573
 
                                         
OTHER INCOME (EXPENSE):
                                       
Miscellaneous income (expense), including
                                       
net income from equity investees
   
69,102
     
1,694
     
18,089
      (61,223 )    
27,662
 
Interest expense to affiliates
   
-
      (29,988 )     (11,428 )    
-
      (41,416 )
Interest expense - other
    (207 )     (2,749 )     (4,958 )    
-
      (7,914 )
Capitalized interest
   
5
     
1,217
     
1,167
     
-
     
2,389
 
Total other income (expense)
   
68,900
      (29,826 )    
2,870
      (61,223 )     (19,279 )
                                         
INCOME BEFORE INCOME TAXES
   
246,400
     
29,027
     
68,090
      (61,223 )    
282,294
 
                                         
INCOME TAXES
   
70,281
     
10,134
     
25,760
     
-
     
106,175
 
                                         
NET INCOME
  $
176,119
    $
18,893
    $
42,330
    $ (61,223 )   $
176,119
 

28


 
FIRSTENERGY SOLUTIONS CORP.              
 
                               
CONSOLIDATING STATEMENTS OF INCOME            
 
(Unaudited)              
 
                               
For the Nine Months Ended September 30, 2007
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)            
 
                               
REVENUES
  $
3,274,694
    $
1,501,112
    $
793,255
    $ (2,311,129 )   $
3,257,932
 
                                         
EXPENSES:
                                       
Fuel
   
20,824
     
698,643
     
84,734
     
-
     
804,201
 
Purchased power from non-affiliates
   
577,831
     
-
     
-
     
-
     
577,831
 
Purchased power from affiliates
   
2,290,305
     
176,654
     
53,746
      (2,311,129 )    
209,576
 
Other operating expenses
   
123,596
     
240,774
     
367,404
     
-
     
731,774
 
Provision for depreciation
   
1,572
     
74,844
     
68,614
     
-
     
145,030
 
General taxes
   
15,942
     
31,406
     
17,522
     
-
     
64,870
 
Total expenses
   
3,030,070
     
1,222,321
     
592,020
      (2,311,129 )    
2,533,282
 
                                         
OPERATING INCOME
   
244,624
     
278,791
     
201,235
     
-
     
724,650
 
                                         
OTHER INCOME (EXPENSE):
                                       
Miscellaneous income (expense), including
                                       
net income from equity investees
   
271,599
     
2,669
     
13,350
      (239,862 )    
47,756
 
Interest expense to affiliates
    (676 )     (47,090 )     (14,138 )    
-
      (61,904 )
Interest expense - other
    (7,966 )     (34,150 )     (28,729 )    
-
      (70,845 )
Capitalized interest
   
20
     
9,044
     
3,699
     
-
     
12,763
 
Total other income (expense)
   
262,977
      (69,527 )     (25,818 )     (239,862 )     (72,230 )
                                         
INCOME BEFORE INCOME TAXES
   
507,601
     
209,264
     
175,417
      (239,862 )    
652,420
 
                                         
INCOME TAXES
   
98,917
     
82,031
     
62,788
     
-
     
243,736
 
                                         
NET INCOME
  $
408,684
    $
127,233
    $
112,629
    $ (239,862 )   $
408,684
 

29



FIRSTENERGY SOLUTIONS CORP.              
 
                               
CONSOLIDATING STATEMENTS OF INCOME            
 
(Unaudited)              
 
                               
For the Nine Months Ended September 30, 2006
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)         
 
                               
REVENUES
  $
3,071,970
    $
1,336,076
    $
797,967
    $ (2,145,891 )   $
3,060,122
 
                                         
EXPENSES:
                                       
Fuel
   
16,650
     
752,229
     
76,034
     
-
     
844,913
 
Purchased power from non-affiliates
   
477,249
     
-
     
-
     
-
     
477,249
 
Purchased power from affiliates
   
2,143,509
     
141,974
     
49,106
      (2,145,891 )    
188,698
 
Other operating expenses
   
149,042
     
204,282
     
421,443
     
-
     
774,767
 
Provision for depreciation
   
1,314
     
72,778
     
61,322
     
-
     
135,414
 
General taxes
   
9,268
     
29,536
     
16,746
     
-
     
55,550
 
Total expenses
   
2,797,032
     
1,200,799
     
624,651
      (2,145,891 )    
2,476,591
 
                                         
OPERATING INCOME
   
274,938
     
135,277
     
173,316
     
-
     
583,531
 
                                         
OTHER INCOME (EXPENSE):
                                       
Miscellaneous income (expense), including
                                       
net income from equity investees
   
146,375
      (3,052 )    
35,518
      (133,998 )    
44,843
 
Interest expense to affiliates
    (241 )     (87,318 )     (35,105 )    
-
      (122,664 )
Interest expense - other
    (564 )     (5,650 )     (11,666 )    
-
      (17,880 )
Capitalized interest
    (3 )    
3,290
     
5,411
     
-
     
8,698
 
Total other income (expense)
   
145,567
      (92,730 )     (5,842 )     (133,998 )     (87,003 )
                                         
INCOME BEFORE INCOME TAXES
   
420,505
     
42,547
     
167,474
      (133,998 )    
496,528
 
                                         
INCOME TAXES
   
108,549
     
13,296
     
62,727
     
-
     
184,572
 
                                         
NET INCOME
  $
311,956
    $
29,251
    $
104,747
    $ (133,998 )   $
311,956
 

30

 

FIRSTENERGY SOLUTIONS CORP.              
 
                               
CONSOLIDATING BALANCE SHEETS              
 
(Unaudited)              
 
                               
As of September 30, 2007
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)            
 
ASSETS
                             
                               
CURRENT ASSETS:
                             
Cash and cash equivalents
  $
2
    $
-
    $
-
    $
-
    $
2
 
Receivables-
                                       
Customers
   
144,443
     
-
     
-
     
-
     
144,443
 
Associated companies
   
282,118
     
169,108
     
113,936
      (279,700 )    
285,462
 
Other
   
4,862
     
554
     
-
     
-
     
5,416
 
Notes receivable from associated companies
   
-
     
242,612
     
-
     
-
     
242,612
 
Materials and supplies, at average cost
   
195
     
224,149
     
216,722
     
-
     
441,066
 
Prepayments and other
   
67,892
     
13,693
     
2,240
     
-
     
83,825
 
     
499,512
     
650,116
     
332,898
      (279,700 )    
1,202,826
 
                                         
PROPERTY, PLANT AND EQUIPMENT:
                                       
In service
   
25,171
     
5,023,255
     
3,530,969
      (395,817 )    
8,183,578
 
Less - Accumulated provision for depreciation
   
6,807
     
2,539,192
     
1,476,051
      (169,154 )    
3,852,896
 
     
18,364
     
2,484,063
     
2,054,918
      (226,663 )    
4,330,682
 
Construction work in progress
   
1,034
     
414,243
     
181,602
     
-
     
596,879
 
     
19,398
     
2,898,306
     
2,236,520
      (226,663 )    
4,927,561
 
                                         
INVESTMENTS:
                                       
Nuclear plant decommissioning trusts
   
-
     
-
     
1,342,083
     
-
     
1,342,083
 
Long-term notes receivable from associated companies
   
-
     
-
     
62,900
     
-
     
62,900
 
Investment in associated companies
   
2,462,960
     
-
     
-
      (2,462,960 )    
-
 
Other
   
5,315
     
34,447
     
202
     
-
     
39,964
 
     
2,468,275
     
34,447
     
1,405,185
      (2,462,960 )    
1,444,947
 
                                         
DEFERRED CHARGES AND OTHER ASSETS:
                                       
Accumulated deferred income taxes
   
28,756
     
403,890
     
-
      (192,464 )    
240,182
 
Goodwill
   
24,248
     
-
     
-
     
-
     
24,248
 
Property taxes
   
-
     
20,946
     
23,165
     
-
     
44,111
 
Pension assets
   
1,154
     
8,295
     
-
     
-
     
9,449
 
Other
   
33,049
     
32,477
     
5,112
     
-
     
70,638
 
     
87,207
     
465,608
     
28,277
      (192,464 )    
388,628
 
    $
3,074,392
    $
4,048,477
    $
4,002,880
    $ (3,161,787 )   $
7,963,962
 
                                         
LIABILITIES AND CAPITALIZATION
                                       
                                         
CURRENT LIABILITIES:
                                       
Currently payable long-term debt
  $
-
    $
624,517
    $
861,265
    $ (16,061 )   $
1,469,721
 
Notes payable-
                                       
Associated companies
   
223,942
     
-
     
13,128
     
-
     
237,070
 
Other
   
-
     
-
     
-
     
-
     
-
 
Accounts payable-
                                       
Associated companies
   
279,976
     
158,500
     
273,919
      (279,700 )    
432,695
 
Other
   
65,782
     
112,038
     
-
     
-
     
177,820
 
Accrued taxes
   
44,995
     
461,635
     
30,430
     
-
     
537,060
 
Other
   
60,252
     
59,770
     
9,731
     
33,486
     
163,239
 
     
674,947
     
1,416,460
     
1,188,473
      (262,275 )    
3,017,605
 
                                         
CAPITALIZATION:
                                       
Common stockholder's equity
   
2,369,019
     
905,100
     
1,557,860
      (2,462,960 )    
2,369,019
 
Long-term debt
   
-
     
1,575,653
     
242,400
      (1,312,857 )    
505,196
 
     
2,369,019
     
2,480,753
     
1,800,260
      (3,775,817 )    
2,874,215
 
                                         
NONCURRENT LIABILITIES:
                                       
Deferred gain on sale and leaseback transaction
   
-
     
-
     
-
     
1,068,769
     
1,068,769
 
Accumulated deferred income taxes
   
-
     
-
     
192,464
      (192,464 )    
-
 
Accumulated deferred investment tax credits
   
-
     
36,764
     
25,511
     
-
     
62,275
 
Asset retirement obligations
   
-
     
24,350
     
773,007
     
-
     
797,357
 
Retirement benefits
   
7,843
     
45,662
     
-
     
-
     
53,505
 
Property taxes
   
-
     
21,268
     
23,165
     
-
     
44,433
 
Other
   
22,583
     
23,220
     
-
     
-
     
45,803
 
     
30,426
     
151,264
     
1,014,147
     
876,305
     
2,072,142
 
    $
3,074,392
    $
4,048,477
    $
4,002,880
    $ (3,161,787 )   $
7,963,962
 

31



 
FIRSTENERGY SOLUTIONS CORP.              
 
                               
CONSOLIDATING BALANCE SHEETS              
 
(Unaudited)              
 
                               
As of December 31, 2006
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)            
 
ASSETS
                             
                               
CURRENT ASSETS:
                             
Cash and cash equivalents
  $
2
    $
-
    $
-
    $
-
    $
2
 
Receivables-
                                       
Customers
   
129,843
     
-
     
-
     
-
     
129,843
 
Associated companies
   
201,281
     
160,965
     
69,751
      (196,465 )    
235,532
 
Other
   
2,383
     
1,702
     
-
     
-
     
4,085
 
Notes receivable from associated companies
   
460,023
     
-
     
292,896
     
-
     
752,919
 
Materials and supplies, at average cost
   
195
     
238,936
     
221,108
     
-
     
460,239
 
Prepayments and other
   
45,314
     
10,389
     
1,843
     
-
     
57,546
 
     
839,041
     
411,992
     
585,598
      (196,465 )    
1,640,166
 
                                         
PROPERTY, PLANT AND EQUIPMENT:
                                       
In service
   
16,261
     
4,960,453
     
3,378,630
     
-
     
8,355,344
 
Less - Accumulated provision for depreciation
   
5,738
     
2,477,004
     
1,335,526
     
-
     
3,818,268
 
     
10,523
     
2,483,449
     
2,043,104
     
-
     
4,537,076
 
Construction work in progress
   
345
     
170,063
     
169,478
     
-
     
339,886
 
     
10,868
     
2,653,512
     
2,212,582
     
-
     
4,876,962
 
                                         
INVESTMENTS:
                                       
Nuclear plant decommissioning trusts
   
-
     
-
     
1,238,272
     
-
     
1,238,272
 
Long-term notes receivable from associated companies
   
-
     
-
     
62,900
     
-
     
62,900
 
Investment in associated companies
   
1,471,184
     
-
     
-
      (1,471,184 )    
-
 
Other
   
6,474
     
65,833
     
202
     
-
     
72,509
 
     
1,477,658
     
65,833
     
1,301,374
      (1,471,184 )    
1,373,681
 
                                         
DEFERRED CHARGES AND OTHER ASSETS:
                                       
Goodwill
   
24,248
     
-
     
-
     
-
     
24,248
 
Property taxes
   
-
     
20,946
     
23,165
     
-
     
44,111
 
Accumulated deferred income taxes
   
32,939
     
-
     
-
      (32,939 )    
-
 
Other
   
23,544
     
11,542
     
4,753
     
-
     
39,839
 
     
80,731
     
32,488
     
27,918
      (32,939 )    
108,198
 
    $
2,408,298
    $
3,163,825
    $
4,127,472
    $ (1,700,588 )   $
7,999,007
 
                                         
LIABILITIES AND CAPITALIZATION
                                       
                                         
CURRENT LIABILITIES:
                                       
Currently payable long-term debt
  $
-
    $
608,395
    $
861,265
    $
-
    $
1,469,660
 
Notes payable to associated companies
   
-
     
1,022,197
     
-
     
-
     
1,022,197
 
Accounts payable-
                                       
Associated companies
   
375,328
     
11,964
     
365,222
      (196,465 )    
556,049
 
Other
   
32,864
     
103,767
     
-
     
-
     
136,631
 
Accrued taxes
   
54,537
     
32,028
     
26,666
     
-
     
113,231
 
Other
   
49,906
     
41,401
     
9,634
     
-
     
100,941
 
     
512,635
     
1,819,752
     
1,262,787
      (196,465 )    
3,398,709
 
                                         
CAPITALIZATION:
                                       
Common stockholder's equity
   
1,859,363
     
78,542
     
1,392,642
      (1,471,184 )    
1,859,363
 
Long-term debt
   
-
     
1,057,252
     
556,970
     
-
     
1,614,222
 
     
1,859,363
     
1,135,794
     
1,949,612
      (1,471,184 )    
3,473,585
 
                                         
NONCURRENT LIABILITIES:
                                       
Accumulated deferred income taxes
   
-
     
25,293
     
129,095
      (32,939 )    
121,449
 
Accumulated deferred investment tax credits
   
-
     
38,894
     
26,857
     
-
     
65,751
 
Asset retirement obligations
   
-
     
24,272
     
735,956
     
-
     
760,228
 
Retirement benefits
   
10,255
     
92,772
     
-
     
-
     
103,027
 
Property taxes
   
-
     
21,268
     
23,165
     
-
     
44,433
 
Other
   
26,045
     
5,780
     
-
     
-
     
31,825
 
     
36,300
     
208,279
     
915,073
      (32,939 )    
1,126,713
 
    $
2,408,298
    $
3,163,825
    $
4,127,472
    $ (1,700,588 )   $
7,999,007
 

32

 

FIRSTENERGY SOLUTIONS CORP.              
 
                               
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS         
 
(Unaudited)              
 
                               
For the Nine Months Ended September 30, 2007
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)         
 
                               
NET CASH PROVIDED FROM (USED FOR)
                             
OPERATING ACTIVITIES
  $ (17,080 )   $
350,927
    $
146,468
    $
-
    $
480,315
 
                                         
CASH FLOWS FROM FINANCING ACTIVITIES:
                                       
New Financing-
                                       
Long-term debt
   
-
     
1,328,919
     
-
      (1,328,919 )    
-
 
Equity contribution from parent
   
710,468
     
700,000
     
1,325
      (701,325 )    
710,468
 
Short-term borrowings, net
   
223,942
     
-
     
13,128
      (237,070 )    
-
 
Redemptions and Repayments-
                                       
Long-term debt
   
-
      (795,019 )     (315,155 )    
-
      (1,110,174 )
Short-term borrowings, net
   
-
      (1,022,197 )    
-
     
237,070
      (785,127 )
Common stock
    (600,000 )    
-
     
-
     
-
      (600,000 )
Common stock dividend payments
    (67,000 )    
-
     
-
     
-
      (67,000 )
Net cash provided from (used for) financing activities
   
267,410
     
211,703
      (300,702 )     (2,030,244 )     (1,851,833 )
                                         
CASH FLOWS FROM INVESTING ACTIVITIES:
                                       
Property additions
    (10,119 )     (332,499 )     (140,289 )    
-
      (482,907 )
Proceeds from asset sales
   
-
     
12,990
     
-
     
-
     
12,990
 
Proceeds from sale and leaseback transaction
   
-
     
-
     
-
     
1,328,919
     
1,328,919
 
Sales of investment securities held in trusts
   
-
     
-
     
521,535
     
-
     
521,535
 
Purchases of investment securities held in trusts
   
-
     
-
      (521,535 )    
-
      (521,535 )
Loan repayments from (loans to) associated companies, net
   
460,023
      (242,612 )    
292,896
     
-
     
510,307
 
Investment in subsidiary
    (701,325 )    
-
     
-
     
701,325
     
-
 
Other
   
1,091
      (509 )    
1,627
      -      
2,209
 
Net cash provided from (used for) investing activities
    (250,330 )     (562,630 )    
154,234
     
2,030,244
     
1,371,518
 
                                         
Net change in cash and cash equivalents
   
-
     
-
     
-
     
-
     
-
 
Cash and cash equivalents at beginning of period
   
2
     
-
     
-
     
-
     
2
 
Cash and cash equivalents at end of period
  $
2
    $
-
    $
-
    $
-
    $
2
 

33



 
FIRSTENERGY SOLUTIONS CORP.              
 
                               
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS      
 
(Unaudited)              
 
                               
For the Nine Months Ended September 30, 2006
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)         
 
                               
NET CASH PROVIDED FROM
                             
OPERATING ACTIVITIES
  $
145,390
    $
72,860
    $
239,855
    $
-
    $
458,105
 
                                         
CASH FLOWS FROM FINANCING ACTIVITIES:
                                       
New Financing-
                                       
Long-term debt
   
-
     
146,704
     
105,241
     
-
     
251,945
 
Short-term borrowings, net
   
-
     
66,817
      -      
-
     
66,817
 
Redemptions and Reyapments-                                        
Long-term debt
    -       (146,740 )     (106,500 )     -       (253,240 )
Net cash provided from financing activities
   
-
     
66,781
     
(1,259
)    
-
     
65,522
 
                                         
CASH FLOWS FROM INVESTING ACTIVITIES:
                                       
Property additions
    (699 )     (131,853 )     (294,746 )    
-
      (427,298 )
Proceeds from asset sales
   
-
     
20,437
     
-
     
-
     
20,437
 
Sales of investment securities held in trusts
   
-
     
-
     
886,863
     
-
     
886,863
 
Purchases of investment securities held in trusts
   
-
     
-
      (886,863 )    
-
      (886,863 )
Loans to associated companies
    (145,734 )     -       57,442      
-
      (88,292 )
Other
   
1,043
      (28,225 )     (1,292 )    
-
      (28,474 )
Net cash used for investing activities
    (145,390 )     (139,641 )     (238,596 )    
-
      (523,627 )
                                         
Net change in cash and cash equivalents
   
-
     
-
     
-
     
-
     
-
 
Cash and cash equivalents at beginning of period
   
2
     
-
     
-
     
-
     
2
 
Cash and cash equivalents at end of period
  $
2
    $
-
    $
-
    $
-
    $
2
 

34


 
FIRSTENERGY CORP.
 
                         
CONSOLIDATED STATEMENTS OF INCOME
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2007
   
2006
   
2007
   
2006
 
   
(In millions, except per share amounts)
 
REVENUES:
                       
Electric utilities
  $
3,260
    $
2,996
    $
8,685
    $
7,677
 
Unregulated businesses
   
381
     
368
     
1,038
     
1,144
 
Total revenues *
   
3,641
     
3,364
     
9,723
     
8,821
 
                                 
EXPENSES:
                               
Fuel and purchased power
   
1,495
     
1,317
     
3,801
     
3,306
 
Other operating expenses
   
756
     
758
     
2,255
     
2,230
 
Provision for depreciation
   
162
     
153
     
477
     
445
 
Amortization of regulatory assets
   
288
     
243
     
785
     
665
 
Deferral of new regulatory assets
    (107 )     (153 )     (399 )     (379 )
General taxes
   
197
     
187
     
589
     
553
 
Total expenses
   
2,791
     
2,505
     
7,508
     
6,820
 
                                 
OPERATING INCOME
   
850
     
859
     
2,215
     
2,001
 
                                 
OTHER INCOME (EXPENSE):
                               
Investment income
   
30
     
46
     
93
     
120
 
Interest expense
    (203 )     (185 )     (593 )     (528 )
Capitalized interest
   
9
     
7
     
21
     
21
 
Subsidiaries’ preferred stock dividends
   
-
      (2 )    
-
      (6 )
Total other expense
    (164 )     (134 )     (479 )     (393 )
                                 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
   
686
     
725
     
1,736
     
1,608
 
                                 
INCOME TAXES
   
273
     
273
     
695
     
625
 
                                 
INCOME FROM CONTINUING OPERATIONS
   
413
     
452
     
1,041
     
983
 
                                 
Discontinued operations (net of income tax benefits of
                         
$1 million and $2 million in the three months and
                               
nine months ended September 30, 2006, respectively) (Note 4)
   
-
     
2
     
-
      (4 )
                                 
NET INCOME
  $
413
    $
454
    $
1,041
    $
979
 
                                 
BASIC EARNINGS PER SHARE OF COMMON STOCK:
                         
Income 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
 
                                 
                                 
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
   
304
     
322
     
307
     
326
 
                                 
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
                         
Income 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
 
                                 
                                 
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
   
307
     
325
     
311
     
329
 
                                 
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
  $
1.00
    $
0.45
    $
1.50
    $
1.35
 
                                 
                                 
* Includes excise tax collections of $108 million in the third quarter of both 2007 and 2006, and $308 million and $297 million in the nine
   months ended September 2007 and 2006, respectively.
                         
                                 
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

35

 

FIRSTENERGY CORP.
 
                         
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2007
   
2006
   
2007
   
2006
 
   
(In millions)
 
                         
NET INCOME
  $
413
    $
454
    $
1,041
    $
979
 
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    (12 )    
-
      (34 )    
-
 
Unrealized gain (loss) on derivative hedges
    (10 )     (28 )    
10
     
45
 
Change in unrealized gain on available for sale securities
   
26
     
26
     
89
     
39
 
Other comprehensive income (loss)
   
4
      (2 )    
65
     
84
 
Income tax expense (benefit) related to other
                               
  comprehensive income
   
-
      (1 )    
19
     
30
 
Other comprehensive income (loss), net of tax
   
4
      (1 )    
46
     
54
 
                                 
COMPREHENSIVE INCOME
  $
417
    $
453
    $
1,087
    $
1,033
 
                                 
                                 
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
         
these statements.
                               

36



 
FIRSTENERGY CORP.
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
   
December 31,
 
   
2007
   
2006
 
   
(In millions)
 
ASSETS
           
             
CURRENT ASSETS:
           
Cash and cash equivalents
  $
30
    $
90
 
Receivables-
               
Customers (less accumulated provisions of $38 million and
               
$43 million, respectively, for uncollectible accounts)
   
1,432
     
1,135
 
Other (less accumulated provisions of $22 million and
               
$24 million, respectively, for uncollectible accounts)
   
194
     
132
 
Materials and supplies, at average cost
   
543
     
577
 
Prepayments and other
   
207
     
149
 
     
2,406
     
2,083
 
PROPERTY, PLANT AND EQUIPMENT:
               
In service
   
24,353
     
24,105
 
Less - Accumulated provision for depreciation
   
10,248
     
10,055
 
     
14,105
     
14,050
 
Construction work in progress
   
933
     
617
 
     
15,038
     
14,667
 
INVESTMENTS:
               
Nuclear plant decommissioning trusts
   
2,140
     
1,977
 
Investments in lease obligation bonds
   
738
     
811
 
Other
   
787
     
746
 
     
3,665
     
3,534
 
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
   
5,609
     
5,898
 
Regulatory assets
   
4,047
     
4,441
 
Pension assets
   
318
     
-
 
Other
   
570
     
573
 
     
10,544
     
10,912
 
    $
31,653
    $
31,196
 
LIABILITIES AND CAPITALIZATION
               
                 
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $
2,265
    $
1,867
 
Short-term borrowings
   
573
     
1,108
 
Accounts payable
   
760
     
726
 
Accrued taxes
   
671
     
598
 
Accrued interest
   
215
     
111
 
Other
   
894
     
845
 
     
5,378
     
5,255
 
CAPITALIZATION:
               
Common stockholders’ equity-
               
Common stock, $.10 par value, authorized 375,000,000 shares-
               
304,835,407 and 319,205,517 shares outstanding, respectively
   
30
     
32
 
Other paid-in capital
   
5,564
     
6,466
 
Accumulated other comprehensive loss
    (213 )     (259 )
Retained earnings
   
3,387
     
2,806
 
Unallocated employee stock ownership plan common stock-
               
521,818 shares
   
-
      (10 )
Total common stockholders' equity
   
8,768
     
9,035
 
Long-term debt and other long-term obligations
   
8,617
     
8,535
 
     
17,385
     
17,570
 
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
   
2,317
     
2,740
 
Asset retirement obligations
   
1,247
     
1,190
 
Deferred gain on sale and leaseback transaction
   
1,069
     
-
 
Power purchase contract loss liability
   
872
     
1,182
 
Retirement benefits
   
918
     
944
 
Lease market valuation liability
   
684
     
767
 
Other
   
1,783
     
1,548
 
     
8,890
     
8,371
 
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
               
    $
31,653
    $
31,196
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
 
balance sheets.
               

37



FIRSTENERGY CORP.
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30,
 
   
2007
   
2006
 
   
(In millions)
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $
1,041
    $
979
 
Adjustments to reconcile net income to net cash from operating activities-
               
Provision for depreciation
   
477
     
445
 
Amortization of regulatory assets
   
785
     
665
 
Deferral of new regulatory assets
    (399 )     (379 )
Nuclear fuel and lease amortization
   
75
     
67
 
Deferred purchased power and other costs
    (265 )     (323 )
Deferred income taxes and investment tax credits, net
    (158 )    
36
 
Investment impairment
   
16
     
13
 
Deferred rents and lease market valuation liability
    (41 )     (54 )
Accrued compensation and retirement benefits
    (50 )    
78
 
Commodity derivative transactions, net
   
5
     
28
 
Gain on asset sales
    (35 )     (38 )
Income from discontinued operations
   
-
     
4
 
Cash collateral
    (50 )     (98 )
Pension trust contribution
    (300 )    
-
 
Decrease (increase) in operating assets-
               
Receivables
    (329 )     (7 )
Materials and supplies
   
62
      (30 )
Prepayments and other current assets
    (39 )     (49 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (15 )     (93 )
Accrued taxes
   
355
      (32 )
Accrued interest
   
104
     
104
 
Electric service prepayment programs
    (52 )     (45 )
Other
    (36 )     (28 )
Net cash provided from operating activities
   
1,151
     
1,243
 
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
   
1,100
     
1,235
 
Short-term borrowings, net
   
-
     
482
 
Redemptions and Repayments-
               
Common stock
    (918 )     (600 )
Preferred stock
   
-
      (107 )
Long-term debt
    (647 )     (993 )
Short-term borrowings, net
    (535 )    
-
 
Net controlled disbursement activity
   
6
      (22 )
Stock-based compensation tax benefit
   
16
     
-
 
Common stock dividend payments
    (464 )     (439 )
Net cash used for financing activities
    (1,442 )     (444 )
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (1,127 )     (990 )
Proceeds from asset sales
   
37
     
83
 
Proceeds from sale and leaseback transaction
   
1,329
     
-
 
Sales of investment securities held in trusts
   
1,010
     
1,370
 
Purchases of investment securities held in trusts
    (1,067 )     (1,381 )
Cash investments
   
48
     
109
 
Other
   
1
      (13 )
Net cash provided from (used for) investing activities
   
231
      (822 )
                 
Net decrease in cash and cash equivalents
    (60 )     (23 )
Cash and cash equivalents at beginning of period
   
90
     
64
 
Cash and cash equivalents at end of period
  $
30
    $
41
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.
               

38



 
 
Report of Independent Registered Public Accounting Firm









To the Stockholders and Board of
Directors of FirstEnergy Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholders’ equity, preferred stock, and of cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(K) and Note 12 to the consolidated financial statements) dated February 27, 2007, except as to Note 2(H) and Note 16, which are as of September 14, 2007, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007

39


FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


EXECUTIVE SUMMARY

Net income in the third quarter of 2007 was $413 million, or basic earnings of $1.36 per share of common stock ($1.34 diluted), compared with net income of $454 million, or basic earnings of $1.41 per share of common stock ($1.40 diluted) in the third quarter of 2006. Net income in the first nine months of 2007 was $1.04 billion, or basic earnings of $3.39 per share of common stock ($3.35 diluted), compared with net income of $979 million, or basic earnings of $2.99 per share of common stock ($2.97 diluted) in the first nine months of 2006. The decrease in FirstEnergy’s third quarter earnings was driven primarily by higher fuel and purchased power costs and increased depreciation and amortization, partially offset by higher electric sales revenues.

Change in Basic Earnings Per Share
From Prior Year Periods
 
Three Months
Ended
September 30,
 
Nine Months
Ended
September 30,
 
               
Basic Earnings Per Share – 2006
 
$
1.41
 
$
2.99
 
Revenues
   
0.55
   
1.76
 
Fuel and purchased power
   
(0.37
)
 
(0.99
)
Depreciation and amortization
   
(0.11
)
 
(0.29
)
Deferral of new regulatory assets
   
(0.09
)
 
(0.01
)
Other expenses
   
(0.16
)
 
(0.36
)
Reduced common shares outstanding
   
0.08
   
0.18
 
Non-core asset sales/impairments – 2006
   
(0.01
)
 
0.03
 
PPUC NUG Accounting Adjustment – 2006
   
0.02
   
0.02
 
Non-core asset sales -- 2007
   
0.04
   
0.04
 
Saxton decommissioning regulatory asset – 2007
   
-
   
0.05
 
Trust securities impairment – 2007
   
-
   
(0.03
)
Basic Earnings Per Share – 2007
 
$
1.36
 
$
3.39
 

Regulatory Matters

Ohio

On August 15, 2007, the PUCO approved a stipulation that creates a green pricing option for customers of the Ohio Companies. The stipulation was filed on May 29, 2007 by the Ohio Companies, the PUCO Staff, and the OCC. The Green Resource Program will enable customers to support the development of alternative energy resources through their voluntary participation in this alternative to the Ohio Companies’ standard service offer for generation supply. The Green Resource Program will be established through the Ohio Companies’ purchase of Renewable Energy Certificates (RECs) at prices determined through a competitive bidding process monitored by the PUCO.

On August 16, 2007, the PUCO held a technical conference for interested parties to gain a better understanding of the Ohio Companies’ competitive generation supply plan proposal filed with the PUCO on July 10, 2007. The proposal seeks approval to conduct a competitive bidding process to provide generation service, beginning January 1, 2009, to customers who choose not to purchase electricity from an alternative supplier. The proposal is currently pending before the PUCO.

On August 29, 2007, the Supreme Court of Ohio upheld findings by the PUCO approving several provisions of the Ohio Companies’ RCP. The Court, however, remanded the portion of the order that authorized the Ohio Companies to collect deferred fuel costs through future distribution rates back to the PUCO for further consideration. The Court found recovery of competitive generation service costs through noncompetitive distribution rates unlawful. The PUCO’s order had authorized the Ohio Companies to defer increased fuel costs incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances, and to recover these deferred costs over a 25-year period beginning in 2009. On September 7, 2007, the Ohio Companies filed a Motion for Reconsideration with the Court on the issue of the deferred fuel costs. On September 10, 2007, the Ohio Companies filed an Application on remand with the PUCO proposing that the increased fuel costs be recovered through two generation-related fuel cost recovery riders during the period of October 2007 through 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 Ohio Companies’ Application.

40


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 emission 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 which 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. On October 4, 2007, FirstEnergy’s Chief Executive Officer provided testimony to the Committee citing several concerns with the current version of the bill, including its lack of context in which to establish prices. He recommended that the PUCO be provided the clear statutory authority to negotiate rate plans, and in the event that negotiations do not result in rate plan agreements, a competitive bidding process be utilized to establish generation prices for customers that do not choose alternative suppliers. He also proposed that the PUCO’s statutory authority be expanded to promote societal programs such as energy efficiency, demand response, renewable power, and infrastructure improvements. 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.

Pennsylvania

On September 21 and October 5, 2007, responsive and reply briefs, respectively, were filed by the parties in the appeal of the PPUC’s January 2007 transition rate plan order to the Pennsylvania Commonwealth Court. Met-Ed and Penelec have appealed the PPUC’s decision on the denial of generation rate relief and on a consolidated income tax adjustment related to the cost of capital, while other parties appealed the PPUC’s decision on transmission rate relief. Oral arguments are expected to take place in late 2007 or early 2008.

On September 28, 2007, a Joint Petition for Settlement was filed with the PPUC for approval of Penn’s Interim Default Service Supply Plan for the three-year period covering June 1, 2008, through May 31, 2011.  For customers who choose not to shop, the plan provides for Penn to obtain market-based generation supply through an RFP by rate class for residential and commercial customers, with industrial customers being supplied through short-term markets. The settlement agreement resolves all issues in the proceeding, except those regarding incremental uncollectible accounts expense, and is either supported, or not opposed, by all parties. A PPUC hearing was held on September 11, 2007 on the uncollectible expense issue. An ALJ recommended decision is expected shortly with a PPUC Order expected in late November or early December.

Generation

Perry

On August 21, 2007, FENOC announced plans to expand used nuclear fuel storage capacity at the Perry Nuclear Power Plant. The plan calls for installing above-ground, airtight steel and concrete cylindrical canisters, cooled by natural air circulation, to store used fuel assemblies.  Initially, six canisters will be installed, with the capability to add up to 74 additional canisters as needed. Construction of the new fuel storage system, which is expected to cost approximately $30 million, is scheduled to begin in the spring of 2008, with completion planned for 2010.

Beaver Valley

On October 24, 2007, Beaver Valley Unit 1 returned to service following completion of its scheduled refueling outage that began on September 24, 2007. During the outage several improvement projects were completed, including reinforcing welds on the pressurizer, spray lines and safety relief valves, increasing the size of the containment sump strainer, and replacing a reactor coolant pump motor. The ten-year in-service inspection of the reactor vessel was also completed with no significant issues identified. Beaver Valley Unit 1 operated for 378 consecutive days when it was taken off line for the outage. In late August 2007, FENOC filed applications with the NRC seeking renewal of the operating licenses for Beaver Valley Units 1 and 2 for an additional 20 years, which would extend the operating licenses to January 29, 2036 for Unit 1 and May 27, 2047 for Unit 2.

41



Financial Matters

On July 13, 2007, FGCO completed a $1.3 billion sale and leaseback transaction for its 779 MW interest in Unit 1 of the Bruce Mansfield Plant. The terms of the agreement provide for an approximate 33-year lease of the unit. FirstEnergy used the net, after-tax proceeds of approximately $1.2 billion to repay short-term debt that was used to fund its recent $900 million share repurchase program and $300 million pension contribution. FES’ registration obligations under the registration rights agreement applicable to the transaction were satisfied in September 2007, at which time the transaction was classified as an operating lease under GAAP for FES and FirstEnergy. The $1.1 billion book gain from the transaction was deferred and will be amortized ratably over the lease term. FGCO continues to operate the plant under the terms of the agreement.

On August 30, 2007, Penelec issued $300 million of 6.05% unsecured senior notes due 2017. A portion of the net proceeds from the issuance and sale of the senior notes was used to fund the repurchase of $200 million of Penelec’s common stock from FirstEnergy. The remainder was used to repay short-term borrowings and for general corporate purposes.

On October 4, 2007, FGCO and NGC closed on the issuance of $427 million of pollution control revenue bonds (PCRBs). Proceeds from the issuance will be used to redeem, during the fourth quarter of 2007, an equal amount of outstanding PCRBs originally issued on behalf of the Ohio Companies. This transaction brings the total amount of PCRBs transferred from the Ohio Companies and Penn to FGCO and NGC to approximately $1.9 billion, with approximately $265 million remaining to be transferred. The transfer of these PCRBs supports the intra-system generation asset transfer that was completed in 2005.

FIRSTENERGY’S BUSINESS

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

·  
Energy Delivery Services transmits and distributes electricity through FirstEnergy's eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR requirements in Pennsylvania and New Jersey. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to non-shopping retail customers under the PLR obligations in its Pennsylvania and New Jersey franchise areas.  Its net income reflects the commodity costs of securing electricity from the competitive energy services segment under partial requirements purchased power agreements with FES and non-affiliated power suppliers, including associated transmission costs.

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

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

RESULTS OF OPERATIONS

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

42




 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
 
 
 
Increase
 
 
 
Increase
 
 
 
2007
 
2006
 
(Decrease)
 
2007
 
2006
 
(Decrease)
 
 
 
(In millions, except per share amounts)
 
Net Income (Loss)
 
 
 
 
 
 
 
 
 
 
 
 
 
By Business Segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
Energy delivery services
 
$
269
 
$
280
 
$
(11
)
$
695
 
$
702
 
$
(7
)
Competitive energy services
 
 
148
   
169
 
 
(21
)
 
388
 
 
302
 
 
86
 
Ohio transitional generation services
   
16
   
27
   
(11
)
 
69
   
88
   
(19
)
Other and reconciling adjustments*
 
 
(20
)
 
(22
)
 
2
 
 
(111
)
 
(113
)
 
2
 
Total
 
$
413
 
$
454
 
$
(41
)
$
1,041
 
$
979
 
$
62
 
 
 
 
         
 
   
 
   
 
   
 
   
Basic Earnings Per Share:
 
 
         
 
   
 
   
 
   
 
   
Income from continuing operations
 
$
1.36
 
$
1.40
 
$
(0.04
)
$
3.39
 
$
3.00
 
$
0.39
 
Discontinued operations
 
 
-
   
0.01
   
(0.01
)
 
-
   
(0.01
)
 
0.01
 
Net earnings per basic share
 
$
1.36
 
$
1.41
 
$
(0.05
)
$
3.39
 
$
2.99
 
$
0.40
 
 
 
 
         
 
   
 
   
 
   
 
   
Diluted Earnings Per Share:
 
 
         
 
   
 
   
 
   
 
   
Income from continuing operations
 
$
1.34
 
$
1.39
 
$
(0.05
)
$
3.35
 
$
2.98
 
$
0.37
 
Discontinued operations
 
 
-
   
0.01
   
(0.01
)
 
-
   
(0.01
)
 
0.01
 
Net earnings per diluted share
 
$
1.34
 
$
1.40
 
$
(0.06
)
$
3.35
 
$
2.97
 
$
0.38
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

* Represents other operating segments and reconciling adjustments including interest expense on holding company debt and corporate support services revenues and expenses.

Summary of Results of Operations – Third Quarter of 2007 Compared with the Third Quarter of 2006

Financial results for FirstEnergy's major business segments in the third quarter of 2007 and 2006 were as follows:
 
               
Ohio
             
   
Energy
   
Competitive
   
Transitional
   
Other and
       
   
Delivery
   
Energy
   
Generation
   
Reconciling
   
FirstEnergy
 
Third Quarter 2007 Financial Results
 
Services
   
Services
   
Services
   
Adjustments
   
Consolidated
 
   
(In millions)
                         
Revenues:
                             
External
                             
Electric
  $
2,340
    $
338
    $
716
    $
-
    $
3,394
 
Other
   
180
     
32
     
7
     
28
     
247
 
Internal
   
-
     
806
     
-
      (806 )    
-
 
Total Revenues
   
2,520
     
1,176
     
723
      (778 )    
3,641
 
                                         
Expenses:
                                       
Fuel and purchased power
   
1,116
     
554
     
631
      (806 )    
1,495
 
Other operating expenses
   
436
     
264
     
80
      (24 )    
756
 
Provision for depreciation
   
102
     
51
     
-
     
9
     
162
 
Amortization of regulatory assets
   
279
     
-
     
9
     
-
     
288
 
Deferral of new regulatory assets
    (82 )    
-
      (25 )    
-
      (107 )
General taxes
   
166
     
26
     
1
     
4
     
197
 
Total Expenses
   
2,017
     
895
     
696
      (817 )    
2,791
 
                                         
Operating Income
   
503
     
281
     
27
     
39
     
850
 
Other Income (Expense):
                                       
Investment income
   
58
     
5
     
-
      (33 )    
30
 
Interest expense
    (120 )     (44 )    
-
      (39 )     (203 )
Capitalized interest
   
3
     
5
     
-
     
1
     
9
 
Total Other Expense
    (59 )     (34 )    
-
      (71 )     (164 )
                                         
Income From Continuing Operations
                                 
Before Income Taxes
   
444
     
247
     
27
      (32 )    
686
 
Income taxes
   
175
     
99
     
11
      (12 )    
273
 
Net Income
  $
269
    $
148
    $
16
    $ (20 )   $
413
 
 

43



 
               
Ohio
             
   
Energy
   
Competitive
   
Transitional
   
Other and
       
   
Delivery
   
Energy
   
Generation
   
Reconciling
   
FirstEnergy
 
Third Quarter 2006 Financial Results
 
Services
   
Services
   
Services
   
Adjustments
   
Consolidated
 
   
(In millions)            
 
Revenues:
                             
External
                             
Electric
  $
2,120
    $
313
    $
682
    $
-
    $
3,115
 
Other
   
186
     
40
     
8
     
15
     
249
 
Internal
   
-
     
762
     
-
      (762 )    
-
 
Total Revenues
   
2,306
     
1,115
     
690
      (747 )    
3,364
 
                                         
Expenses:
                                       
Fuel and purchased power
   
960
     
515
     
604
      (762 )    
1,317
 
Other operating expenses
   
468
     
218
     
76
      (4 )    
758
 
Provision for depreciation
   
97
     
49
     
-
     
7
     
153
 
Amortization of regulatory assets
   
237
     
-
     
6
     
-
     
243
 
Deferral of new regulatory assets
    (107 )    
-
      (46 )    
-
      (153 )
General taxes
   
157
     
21
     
5
     
4
     
187
 
Total Expenses
   
1,812
     
803
     
645
      (755 )    
2,505
 
                                         
Operating Income
   
494
     
312
     
45
     
8
     
859
 
Other Income (Expense):
                                       
Investment income
   
80
     
18
     
-
      (52 )    
46
 
Interest expense
    (109 )     (52 )    
-
      (24 )     (185 )
Capitalized interest
   
4
     
3
     
-
     
-
     
7
 
Subsidiaries' preferred stock dividends
    (2 )    
-
     
-
     
-
      (2 )
Total Other Expense
    (27 )     (31 )    
-
      (76 )     (134 )
                                         
Income From Continuing Operations
                                       
Before Income Taxes
   
467
     
281
     
45
      (68 )    
725
 
Income taxes
   
187
     
112
     
18
      (44 )    
273
 
Income from continuing operations
   
280
     
169
     
27
      (24 )    
452
 
Discontinued operations
   
-
     
-
     
-
     
2
     
2
 
Net Income
  $
280
    $
169
    $
27
    $ (22 )   $
454
 
                                         
                                         
Changes Between Third Quarter 2007 and
                                 
Third Quarter 2006 Financial Results
                                       
Increase (Decrease)
                                       
                                         
Revenues:
                                       
External
                                       
Electric
  $
220
    $
25
    $
34
    $
-
    $
279
 
Other
    (6 )     (8 )     (1 )    
13
      (2 )
Internal
   
-
     
44
     
-
      (44 )    
-
 
Total Revenues
   
214
     
61
     
33
      (31 )    
277
 
                                         
Expenses:
                                       
Fuel and purchased power
   
156
     
39
     
27
      (44 )    
178
 
Other operating expenses
    (32 )    
46
     
4
      (20 )     (2 )
Provision for depreciation
   
5
     
2
     
-
     
2
     
9
 
Amortization of regulatory assets
   
42
     
-
     
3
     
-
     
45
 
Deferral of new regulatory assets
   
25
     
-
     
21
     
-
     
46
 
General taxes
   
9
     
5
      (4 )    
-
     
10
 
Total Expenses
   
205
     
92
     
51
      (62 )    
286
 
                                         
Operating Income
   
9
      (31 )     (18 )    
31
      (9 )
Other Income (Expense):
                                       
Investment income
    (22 )     (13 )    
-
     
19
      (16 )
Interest expense
    (11 )    
8
     
-
      (15 )     (18 )
Capitalized interest
    (1 )    
2
     
-
     
1
     
2
 
Subsidiaries' preferred stock dividends
   
2
     
-
     
-
     
-
     
2
 
Total Other Expense
    (32 )     (3 )    
-
     
5
      (30 )
                                         
Income From Continuing Operations
                                       
Before Income Taxes
    (23 )     (34 )     (18 )    
36
      (39 )
Income taxes
    (12 )     (13 )     (7 )    
32
     
-
 
Income from continuing operations
    (11 )     (21 )     (11 )    
4
      (39 )
Discontinued operations
   
-
     
-
     
-
      (2 )     (2 )
Net Income
  $ (11 )   $ (21 )   $ (11 )   $
2
    $ (41 )

 
44



Energy Delivery Services – Third Quarter 2007 Compared to Third Quarter 2006

Net income decreased $11 million (or 4%) to $269 million in the third quarter of 2007 compared to $280 million in the third quarter of 2006, primarily due to increased purchased power costs and higher amortization of regulatory assets, partially offset by higher revenues and reduced other operating expenses.

Revenues –

The increase in total revenues resulted from the following sources:

   
Three Months Ended
     
   
September 30,
     
Revenues by Type of Service
 
2007
 
2006
 
Increase
(Decrease)
 
   
(In millions)
 
Distribution services
 
$
1,104
 
$
1,124
 
$
(20
)
Generation sales:
                   
   Retail
   
942
   
857
   
85
 
   Wholesale
   
207
   
91
   
116
 
Total generation sales
   
1,149
   
948
   
201
 
Transmission
   
219
   
177
   
42
 
Other
   
48
   
57
   
(9
)
Total Revenues
 
$
2,520
 
$
2,306
 
$
214
 

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

Electric Distribution KWH Deliveries
   
Residential
 
(1.7)
 %
Commercial
 
1.4
 %
Industrial
 
1.0
 %
Total Distribution KWH Deliveries
 
(0.5)
 %

The reduction in distribution services revenues was primarily due to distribution rate decreases for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).

The following table summarizes the price and volume factors contributing to the $201 million increase in generation revenues in the third quarter of 2007 compared to 2006:

Sources of Change in Generation Revenues
 
Increase
(Decrease)
 
   
(In millions)
 
Retail:
 
 
   
  Effect of 5.9% decrease in sales volumes
 
$
(50
)
  Change in prices
 
 
135
 
 
 
 
85
 
Wholesale:
 
 
   
  Effect of 95% increase in sales volumes
 
 
86
 
  Change in prices
 
 
30
 
 
 
 
116
 
Net Increase in Generation Sales
 
$
201
 

The increase in retail generation prices during the third quarter of 2007 compared to 2006 was primarily due to increased generation rates for JCP&L resulting from the New Jersey BGS auction and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market beginning in January 2007.

Transmission revenues increased $42 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred, with no material effect to current period earnings (see Outlook – State Regulatory Matters – Pennsylvania).

45



Expenses –

The net increases in revenues discussed above were offset by a $205 million increase in expenses due to the following:

 
·
Purchased power costs were $157 million higher in the third quarter of 2007 due to higher unit costs, increased volumes purchased and a decrease in purchased power cost deferrals. The increased unit costs reflected the effect of higher JCP&L purchased power unit prices resulting from the BGS auction. The increased KWH purchases in 2007 primarily resulted from more sales to the PJM wholesale market by Met-Ed and Penelec.  Deferred purchased power costs were lower due to higher generation charges to JCP&L customers.  The following table summarizes the sources of changes in purchased power costs:

Sources of Change in Purchased Power
 
Increase
 
   
(In millions)
 
         
Purchased Power:
 
 
   
   Change due to increased unit costs
 
$
97
 
   Change due to increased volume
 
 
42
 
   Decrease in NUG costs deferred
 
 
18
 
      Net Increase in Purchased Power Costs
 
$
157
 


 
·
Amortization of regulatory assets increased $42 million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC revenues for JCP&L as discussed above.

 
·
The deferral of new regulatory assets during the third quarter of 2007 was $25 million lower than in 2006 due in part to $40 million in reduced deferrals of transmission related PJM costs. The reduced deferral in the third quarter of 2007 was attributable to greater recovery of PJM costs in the 2007 period under the transmission service charge rider (see Outlook – State Regulatory Matters - Pennsylvania). The reduction in deferred PJM costs was partially offset by higher distribution deferrals under the RCP.

·      Other operating expenses decreased $32 million, partially offsetting the above increases, due to the net effects of:

-  
A decrease of $21 million in transmission expenses caused by the expiration of transmission hedging instruments and reduced financial transmission rights revenue.

-  A decrease in operation and maintenance expenses of $19 million primarily due to lower employee labor and benefit costs ($10 million) lower uncollectible
    expenses related to customer receivables ($4 million) and lower leased equipment costs ($3 million).

-   An increase in miscellaneous operating expenses ($9 million) resulting from increased corporate support billings from FESC.

Other Expense –

Other expense increased $32 million in 2007 compared to the third quarter of 2006 primarily due to lower investment income of $22 million resulting from the repayment of notes receivable from affiliates since the third quarter of 2006, and increased interest expense of $11 million related in part to new debt issuances by CEI, JCP&L and Penelec.

Competitive Energy Services – Third Quarter 2007 Compared to Third Quarter 2006

Net income for this segment was $148 million in the third quarter of 2007 compared to $169 million in the same period last year. Increased fuel and purchased power costs and other operating expenses, partially offset by higher revenues, led to the $21 million decrease.

46



Revenues –

Total revenues increased $61 million in the third quarter of 2007 compared to the same period in 2006. This increase primarily resulted from increased affiliated sales to the Ohio Companies, Met-Ed and Penelec as well as higher unit prices from the Ohio Companies. These increases were partially offset by lower sales to Penn as a result of the implementation of its competitive solicitation process in 2007. Higher retail revenues resulted from increased KWH sales in the MISO market, partially offset by reduced volume in the PJM market.

Increased non-affiliated wholesale revenues primarily reflected capacity revenues earned in PJM’s new capacity market. The capacity market was initiated in June 2007 to encourage the development of capacity resources in PJM. Lower wholesale sales to non-affiliates partially offset these increases due to decreased generation available for the non-affiliated wholesale market.

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

   
Three Months Ended
     
   
September 30,
 
Increase
 
Revenues By Type of Service
 
2007
 
2006
 
(Decrease)
 
   
(In millions)
 
Non-Affiliated Generation Sales:
             
Retail
 
$
189
 
$
178
 
$
11
 
Wholesale
   
149
   
134
   
15
 
Total Non-Affiliated Generation Sales
   
338
   
312
   
26
 
Affiliated Generation Sales
   
806
   
762
   
44
 
Transmission
   
26
   
32
   
(6
)
Other
   
6
   
9
   
(3
)
Total Revenues
 
$
1,176
 
$
1,115
 
$
61
 


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

   
Increase
 
Source of Change in Non-Affiliated Generation Sales
 
(Decrease)
 
   
(In millions)
 
Retail:
 
 
   
Effect of 0.2% increase in sales volumes
 
$
1
 
Change in prices
 
 
10
 
 
 
 
11
 
Wholesale:
 
 
   
Effect of 11% decrease in sales volumes
 
 
(15
)
Change in prices
 
 
30
 
 
 
 
15
 
Net Increase in Non-Affiliated Generation Sales
 
$
26
 
       
       
Source of Change in Affiliated Generation Sales
 
Increase
 
   
(In millions)
 
Ohio Companies:
 
 
   
Effect of 2% increase in sales volumes
 
$
12
 
Change in prices
 
 
14
 
 
 
 
26
 
Pennsylvania Companies:
 
 
   
Effect of 8% increase in sales volumes
 
 
13
 
Change in prices
 
 
5
 
 
 
 
18
 
Net Increase in Affiliated Generation Sales
 
$
44
 


47




Expenses -

Total expenses were $92 million higher in the third quarter of 2007 due to the net effect of the following factors:

 
·
Purchased power costs increased $55 million due primarily to higher volumes for replacement power related to a forced outage at Perry in the third quarter of 2007 and higher market prices. The sources of change in purchased power costs are summarized in the following table:

Source of Change in Purchased Power
 
Increase
 
 
 
(In millions)
 
         
Change due to increased unit costs
 
$
14
 
Change due to 18% increase in volume
 
 
31
 
    Change due to new PJM capacity market
   
10
 
       Total Increase in Purchased Power Costs
 
$
55
 


 
·
Fuel costs were $16 million lower primarily due to lower coal prices ($8 million), reduced emission allowance costs ($5 million) and a decrease in natural gas consumed resulting from reduced combustion turbine generation ($2 million).

 
·
Fossil operating costs were $32 million higher in 2007 primarily due to the absence of gains on the sales of emissions allowances recognized in 2006.

 
·
Miscellaneous operating expenses were $13 million higher primarily due to increased contractor expenses related to the Beaver Valley Unit 1 outage and corporate support billings from FESC.

 
·
Higher general taxes of $5 million resulted from increased gross receipts taxes and property taxes.

Ohio Transitional Generation Services – Third Quarter 2007 Compared to Third Quarter 2006

Net income decreased $11 million to $16 million in the third quarter of 2007 compared to $27 million in the same period last year. Higher purchased power costs were partially offset by higher generation revenues.

Revenues –

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

   
Three Months Ended
     
   
September 30,
     
Revenues by Type of Service
 
2007
 
2006
 
Increase
 
   
(In millions)
 
Generation sales:
             
Retail
 
$
622
 
$
605
 
$
17
 
Wholesale
   
3
   
3
   
-
 
Total generation sales
   
625
   
608
   
17
 
Transmission
   
98
   
82
   
16
 
Total Revenues
 
$
723
 
$
690
 
$
33
 

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

Source of Change in Generation Sales
 
Increase
 
   
(In millions)
 
Effect of 2% increase in sales volumes
 
$
10
 
Change in prices
 
 
7
 
    Total Increase in Retail Generation Sales
 
$
17
 
 
 
 
   


48



The increase in generation sales was primarily due to higher weather-related usage in the third quarter of 2007 resulting from slightly higher than normal cooling degree days during the period. Average prices increased slightly due to customer usage patterns and higher composite unit prices for returning customers.

Expenses -

Purchased power costs were $27 million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power
 
Increase
 
 
 
(In millions)
 
Purchases from non-affiliates:
       
Change due to increased unit costs
 
$
-
 
Change due to volume
 
 
1
 
     
1
 
Purchases from FES:
       
Change due to increased unit costs
 
 
14
 
Change due to volume
 
 
12
 
     
26
 
Total Increase in Purchased Power Costs
 
$
27
 


The increase in volumes purchased was due to the higher retail generation sales requirements.  The higher unit costs resulted from the provision of the full-requirements PSA with FES under which purchased power unit costs reflected the increases in the Ohio Companies’ retail generation sales unit prices.

The deferral of new regulatory assets decreased by $21 million in the third quarter of 2007 compared to 2006 due to reduced cost deferrals under the Ohio Companies’ RCP.

Other – Third Quarter 2007 Compared to Third Quarter 2006

FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $2 million increase in FirstEnergy’s net income in the third quarter of 2007 compared to the same quarter of 2006. The increase was primarily due to the sale of First Communications ($13 million, net of taxes) offset by higher financing costs of $14 million.


49



Summary of Results of Operations – First Nine Months of 2007 Compared with the First Nine Months of 2006

Financial results for FirstEnergy's major business segments in the first nine months of 2007 and 2006 were as follows:
 
               
Ohio
             
   
Energy
   
Competitive
   
Transitional
   
Other and
       
   
Delivery
   
Energy
   
Generation
   
Reconciling
   
FirstEnergy
 
First Nine Months 2007 Financial Results
 
Services
   
Services
   
Services
   
Adjustments
   
Consolidated
 
   
(In millions)            
 
Revenues:
                             
External
                             
Electric
  $
6,148
    $
973
    $
1,942
    $
-
    $
9,063
 
Other
   
507
     
116
     
26
     
11
     
660
 
Internal
   
-
     
2,210
     
-
      (2,210 )    
-
 
Total Revenues
   
6,655
     
3,299
     
1,968
      (2,199 )    
9,723
 
                                         
Expenses:
                                       
Fuel and purchased power
   
2,838
     
1,461
     
1,712
      (2,210 )    
3,801
 
Other operating expenses
   
1,255
     
839
     
218
      (57 )    
2,255
 
Provision for depreciation
   
301
     
153
     
-
     
23
     
477
 
Amortization of regulatory assets
   
765
     
-
     
20
     
-
     
785
 
Deferral of new regulatory assets
    (299 )    
-
      (100 )    
-
      (399 )
General taxes
   
486
     
81
     
3
     
19
     
589
 
Total Expenses
   
5,346
     
2,534
     
1,853
      (2,225 )    
7,508
 
                                         
Operating Income
   
1,309
     
765
     
115
     
26
     
2,215
 
Other Income (Expense):
                                       
Investment income
   
190
     
13
     
1
      (111 )    
93
 
Interest expense
    (347 )     (144 )     (1 )     (101 )     (593 )
Capitalized interest
   
7
     
13
     
-
     
1
     
21
 
Total Other Expense
    (150 )     (118 )    
-
      (211 )     (479 )
                                         
Income From Continuing Operations
                                       
Before Income Taxes
   
1,159
     
647
     
115
      (185 )    
1,736
 
Income taxes
   
464
     
259
     
46
      (74 )    
695
 
Net Income
  $
695
    $
388
    $
69
    $ (111 )   $
1,041
 


50

 
 
               
Ohio
             
   
Energy
   
Competitive
   
Transitional
   
Other and
       
   
Delivery
   
Energy
   
Generation
   
Reconciling
   
FirstEnergy
 
First Nine Months 2006 Financial Results
 
Services
   
Services
   
Services
   
Adjustments
   
Consolidated
 
   
(In millions)            
 
Revenues:
                             
External
                             
Electric
  $
5,434
    $
955
    $
1,790
    $
-
    $
8,179
 
Other
   
442
     
122
     
18
     
60
     
642
 
Internal
   
14
     
1,997
     
-
      (2,011 )    
-
 
Total Revenues
   
5,890
     
3,074
     
1,808
      (1,951 )    
8,821
 
                                         
Expenses:
                                       
Fuel and purchased power
   
2,343
     
1,416
     
1,558
      (2,011 )    
3,306
 
Other operating expenses
   
1,197
     
838
     
185
     
10
     
2,230
 
Provision for depreciation
   
282
     
143
     
-
     
20
     
445
 
Amortization of regulatory assets
   
650
     
-
     
15
     
-
     
665
 
Deferral of new regulatory assets
    (275 )    
-
      (104 )    
-
      (379 )
General taxes
   
459
     
70
     
7
     
17
     
553
 
Total Expenses
   
4,656
     
2,467
     
1,661
      (1,964 )    
6,820
 
                                         
Operating Income
   
1,234
     
607
     
147
     
13
     
2,001
 
Other Income (Expense):
                                       
Investment income
   
244
     
35
     
-
      (159 )    
120
 
Interest expense
    (310 )     (148 )     (1 )     (69 )     (528 )
Capitalized interest
   
11
     
9
     
-
     
1
     
21
 
Subsidiaries' preferred stock dividends
    (9 )    
-
     
-
     
3
      (6 )
Total Other Expense
    (64 )     (104 )     (1 )     (224 )     (393 )
                                         
Income From Continuing Operations
                                       
Before Income Taxes
   
1,170
     
503
     
146
      (211 )    
1,608
 
Income taxes
   
468
     
201
     
58
      (102 )    
625
 
Income from continuing operations
   
702
     
302
     
88
      (109 )    
983
 
Discontinued operations
   
-
     
-
     
-
      (4 )     (4 )
Net Income
  $
702
    $
302
    $
88
    $ (113 )   $
979
 
                                         
                                         
Changes Between First Nine Months 2007
                                 
and First Nine Months 2006
                                       
Financial Results Increase (Decrease)
                                     
                                         
Revenues:
                                       
External
                                       
Electric
  $
714
    $
18
    $
152
    $
-
    $
884
 
Other
   
65
      (6 )    
8
      (49 )    
18
 
Internal
    (14 )    
213
     
-
      (199 )    
-
 
Total Revenues
   
765
     
225
     
160
      (248 )    
902
 
                                         
Expenses:
                                       
Fuel and purchased power
   
495
     
45
     
154
      (199 )    
495
 
Other operating expenses
   
58
     
1
     
33
      (67 )    
25
 
Provision for depreciation
   
19
     
10
     
-
     
3
     
32
 
Amortization of regulatory assets
   
115
     
-
     
5
     
-
     
120
 
Deferral of new regulatory assets
    (24 )    
-
     
4
     
-
      (20 )
General taxes
   
27
     
11
      (4 )    
2
     
36
 
Total Expenses
   
690
     
67
     
192
      (261 )    
688
 
                                         
Operating Income
   
75
     
158
      (32 )    
13
     
214
 
Other Income (Expense):
                                       
Investment income
    (54 )     (22 )    
1
     
48
      (27 )
Interest expense
    (37 )    
4
     
-
      (32 )     (65 )
Capitalized interest
    (4 )    
4
     
-
     
-
     
-
 
Subsidiaries' preferred stock dividends
   
9
     
-
     
-
      (3 )    
6
 
Total Other Expense
    (86 )     (14 )    
1
     
13
      (86 )
                                         
Income From Continuing Operations
                                       
Before Income Taxes
    (11 )    
144
      (31 )    
26
     
128
 
Income taxes
    (4 )    
58
      (12 )    
28
     
70
 
Income from continuing operations
    (7 )    
86
      (19 )     (2 )    
58
 
Discontinued operations
   
-
     
-
     
-
     
4
     
4
 
Net Income
  $ (7 )   $
86
    $ (19 )   $
2
    $
62
 

51



Energy Delivery Services – First Nine Months of 2007 Compared to First Nine Months of 2006

Net income decreased $7 million (or 1%) to $695 million in the first nine months of 2007 compared to $702 million in the first nine months of 2006, primarily due to increased revenues partially offset by higher operating expenses and other expenses.

Revenues –

The increase in total revenues resulted from the following sources:

   
Nine Months Ended
     
   
September 30,
     
Revenues by Type of Service
 
2007
 
2006
 
Increase
 
   
(In millions)
 
Distribution services
 
$
2,996
 
$
2,972
 
$
24
 
Generation sales:
                   
   Retail
   
2,417
   
2,138
   
279
 
   Wholesale
   
489
   
196
   
293
 
Total generation sales
   
2,906
   
2,334
   
572
 
Transmission
   
595
   
426
   
169
 
Other
   
158
   
158
   
-
 
Total Revenues
 
$
6,655
 
$
5,890
 
$
765
 

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

Electric Distribution KWH Deliveries
     
Residential
   
4.4
 %
Commercial
   
3.4
 %
Industrial
   
(0.4
)%
Total Distribution KWH Deliveries
   
2.5
 %

The increase in electric distribution deliveries to customers was primarily due to higher weather-related usage during the first nine months of 2007 compared to the same period of 2006 (heating degree days increased by 13.7% and cooling degree days increased by 9.5%). The higher revenues from increased distribution deliveries were partially offset by distribution rate decreases for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).

The following table summarizes the price and volume factors contributing to the $572 million increase in non-affiliated generation sales revenues in 2007 compared to 2006:

Sources of Change in Generation Sales
 
Increase
(Decrease)
 
   
(In millions)
 
Retail:
 
 
   
  Effect of 2% decrease in sales volumes
 
$
(38
)
  Change in prices
   
317
 
 
   
279
 
Wholesale:
       
  Effect of 118% increase in sales volumes
   
232
 
  Change in prices
   
61
 
 
   
293
 
Net Increase in Generation Sales
 
$
572
 

The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in Penn’s service territory in the first nine months of 2007. The increase in retail generation prices during the first nine months of 2007 compared to 2006 was primarily due to increased generation rates for JCP&L resulting from the New Jersey BGS auction process and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market beginning in January 2007.

52



Transmission revenues increased $169 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred, with no material effect on current period earnings (see Outlook – State Regulatory Matters – Pennsylvania).

Expenses –

The increases in revenues discussed above were partially offset by a $690 million increase in expenses due to the following:

 
·
Purchased power costs were $495 million higher in the first nine months of 2007 due to higher unit costs and volumes purchased. The increased unit costs reflected the effect of higher JCP&L costs resulting from the BGS auction process. The increased purchases in 2007 were due primarily to higher sales to the wholesale market.  The following table summarizes the sources of changes in purchased power costs:

Sources of Change in Purchased Power
 
Increase
 
   
(In millions)
 
         
Purchased Power:
 
 
   
   Change due to increased unit costs
 
$
261
 
   Change due to increased volume
 
 
174
 
   Decrease in NUG costs deferred
 
 
60
 
      Net Increase in Purchased Power Costs
 
$
495
 

 
·
Other operating expenses increased $58 million due to the net effects of:

-  
  An increase of $80 million in MISO and PJM transmission expenses, resulting primarily from higher congestion costs.

-  
  A decrease in miscellaneous operating expenses of $10 million primarily due to changes in the assessment of regulatory fees and employee benefits
  from FESC.

-  
  A decrease in operation and maintenance expenses of $9 million primarily due to increased labor activities devoted to construction projects in 2007.

 
·
Amortization of regulatory assets increased $115 million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC rates for JCP&L as discussed above.

 
·
The deferral of new regulatory assets during the first nine months of 2007 was $24 million higher in 2007 primarily due to the deferral of previously expensed decommissioning costs of $27 million related to the Saxton nuclear research facility (see Outlook – State Regulatory Matters - Pennsylvania), increased RCP distribution deferrals of $23 million, offset by a reduction in deferred PJM transmission costs of $30 million.

·  
Depreciation expense increased $19 million and property taxes increased $27 million due primarily to property additions since the third quarter of 2006.

Other Expense –

Other expense increased $86 million in 2007 compared to the first nine months of 2006 primarily due to lower investment income of $54 million resulting from the repayment of notes receivable from affiliates since the third quarter of 2006 and increased interest expense of $37 million related to new debt issuances by CEI, JCP&L and Penelec.

Competitive Energy Services – First Nine Months of 2007 Compared to First Nine Months of 2006

Net income for this segment was $388 million in the first nine months of 2007 compared to $302 million in the same period last year. This increase reflects an improvement in gross generation margin and lower nuclear production costs, which were partially offset by increased depreciation and general taxes and reduced investment income.

53


Revenues –

Total revenues increased $225 million in the first nine months of 2007 compared to the same period in 2006. This increase primarily resulted from higher unit prices under affiliated generation sales to the Ohio Companies and increased retail sales, which were partially offset by lower non-affiliated wholesale sales.

The higher retail revenues resulted from increased sales in both the MISO and PJM markets. The increase in MISO retail sales primarily reflect FES’ increased sales to shopping customers in Penn’s service territory. Lower non-affiliated wholesale revenues reflected the effect of decreased generation available for the non-affiliated wholesale market due to increased affiliated company power sales under the Ohio Companies’ full-requirements PSA and the partial-requirements power sales agreement with Met-Ed and Penelec.

The increased affiliated company generation revenues were due to higher unit prices and increased sales volumes. The increase in PSA sales to the Ohio Companies was due to their higher retail generation sales requirements. The higher unit prices resulted from the provision of the full-requirements PSA under which PSA rates reflect the increases in the Ohio Companies’ retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn due to the implementation of its competitive solicitation process in 2007.

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

   
Nine Months Ended
     
   
September 30,
 
Increase
 
Revenues by Type of Service
 
2007
 
2006
 
(Decrease)
 
   
(In millions)
 
Non-Affiliated Generation Sales:
             
Retail
 
$
547
 
$
445
 
$
102
 
Wholesale
   
425
   
509
   
(84
)
Total Non-Affiliated Generation Sales
   
972
   
954
   
18
 
Affiliated Generation Sales
   
2,210
   
1,997
   
213
 
Transmission
   
71
   
96
   
(25
)
Other
   
46
   
27
   
19
 
Total Revenues
 
$
3,299
 
$
3,074
 
$
225
 

Transmission revenues decreased $25 million due to reduced retail load in the MISO market, lower transmission rates and reduced financial transmission rights auction revenue.

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

   
Increase
 
Source of Change in Non-Affiliated Generation Sales
 
(Decrease)
 
   
(In millions)
 
Retail:
 
 
   
Effect of 12% increase in sales volumes
 
$
52
 
Change in prices
 
 
50
 
 
 
 
102
 
Wholesale:
 
 
   
Effect of 26% decrease in sales volumes
 
 
(131
)
Change in prices
 
 
47
 
 
 
 
(84
)
Net Increase in Non-Affiliated Generation Sales
 
$
18
 
       
Source of Change in Affiliated Generation Sales
 
Increase
 
   
(In millions)
 
Ohio Companies:
 
 
   
Effect of 4% increase in sales volumes
 
$
56
 
Change in prices
 
 
89
 
 
 
 
145
 
Pennsylvania Companies:
 
 
   
Effect of 12% increase in sales volumes
 
 
54
 
Change in prices
 
 
14
 
 
 
 
68
 
Net Increase in Affiliated Generation Sales
 
$
213
 

54


Expenses -

Total expenses increased $67 million in the first nine months of 2007 due to the following factors:

 
·
Purchased power costs increased $86 million due principally to higher volumes for replacement power related to the forced outages at Bruce Mansfield and Perry.

 
·
Higher fossil operating costs of $43 million due to the absence of gains from the sale of emissions allowances recognized in 2006 ($24 million) and increased scheduled maintenance outages ($13 million).

 
·
Higher depreciation expenses of $10 million were due to property additions.

 
·
Higher general taxes of $11 million resulted from increased gross receipts taxes and property taxes.

Partially offsetting the higher costs were:

 
·
Fuel costs were $41 million lower primarily due to reduced coal costs and emission allowance costs offset by increases in nuclear fuel and natural gas costs. Coal costs were reduced due to a $14 million inventory adjustment and $23 million of reduced coal consumption reflecting lower generation. Reduced emission allowance costs ($18 million) were partially offset by increased natural gas costs ($4 million) due to increased consumption and nuclear fuel costs ($8 million) due to increased consumption and higher prices.

·        Nuclear operating costs were $54 million lower due to fewer outages in 2007 compared to 2006 and reduced employee benefit costs.

Other Expense –

Total other expense in the first nine months of 2007 was $14 million higher than the 2006 period primarily due to decreased earnings on nuclear decommissioning trust investments (including a $16 million impairment in 2007).

Ohio Transitional Generation Services – First Nine Months of 2007 Compared to First Nine Months of 2006

Net income for this segment decreased to $69 million in the first nine months of 2007 from $88 million in the same period last year. Higher operating expenses, primarily for purchased power, were partially offset by higher generation revenues.

Revenues –

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

   
Nine Months Ended
     
   
September 30,
 
Increase
 
Revenues by Type of Service
 
2007
 
2006
 
(Decrease)
 
   
(In millions)
 
Generation sales:
             
Retail
 
$
1,712
 
$
1,581
 
$
131
 
Wholesale
   
7
   
12
   
(5
)
Total generation sales
   
1,719
   
1,593
   
126
 
Transmission
   
248
   
213
   
35
 
Other
   
1
   
2
   
(1
)
Total Revenues
 
$
1,968
 
$
1,808
 
$
160
 

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

Source of Change in Generation Sales
 
Increase
 
   
(In millions)
 
Retail:
 
 
   
Effect of 4% increase in sales volumes
 
$
66
 
Change in prices
 
 
65
 
 Total Increase in Retail Generation Sales
 
$
131
 

55



The increase in generation sales was primarily due to higher weather-related usage in the first nine months of 2007 compared to the same period of 2006, as discussed above, and reduced customer shopping. Average prices increased primarily due to higher composite unit prices for returning customers. The percentage of generation services provided by alternative suppliers to total sales delivered by the Ohio Companies in their service areas decreased by 6.4 percentage points from the same period last year.

Expenses -

Purchased power costs were $153 million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power
 
Increase
 
 
 
(In millions)
 
Purchases from non-affiliates:
       
Change due to increased unit costs
 
$
6
 
Change due to volume purchased
 
 
2
 
     
8
 
Purchases from FES:
       
Change due to increased unit costs
 
 
89
 
Change due to volume purchased
 
 
56
 
     
145
 
Total Increase in Purchased Power Costs
 
$
153
 


The increase in purchases was due to the higher retail generation sales requirements.  The higher unit costs reflect the increases in the Ohio Companies’ retail generation rates, as provided for under the PSA with FES.

Other operating expenses increased $33 million primarily due to MISO transmission-related expenses. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.

Other – First Nine Months of 2007 Compared to First Nine Months of 2006

FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $2 million increase in FirstEnergy’s net income in the first nine months of 2007. The increase was primarily due to the sale of First Communications ($13 million, net of taxes), the absence of subsidiaries’ preferred stock dividends in 2007 ($6 million) and the absence of a $4 million loss included in 2006 results from discontinued operations (see Note 4).

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2007 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

Changes in Cash Position

FirstEnergy's primary source of cash required for continuing operations as a holding company is cash from the operations of its subsidiaries. FirstEnergy and certain of its subsidiaries also have access to $2.75 billion of short-term financing under a revolving credit facility which expires in 2011.  Under the terms of the facility, FirstEnergy is permitted to have up to $1.5 billion in outstanding borrowings at any time, subject to the facility cap of $2.75 billion of aggregate outstanding borrowings by it and its subsidiaries that are also parties to such facility. In the first nine months of 2007, FirstEnergy received $1.8 billion of cash dividends and return of capital from its subsidiaries and paid $464 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by the subsidiaries of FirstEnergy.

56



On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or approximately 4.5%, of its outstanding common stock at an initial price of approximately $900 million pursuant to an accelerated share repurchase program.  FirstEnergy acquired these shares under its previously announced authorization to repurchase up to 16 million shares of its common stock. The share repurchase was funded with short-term borrowings, which have since been repaid with the proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction.

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.  The notes and certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements. 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. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowances in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 3).

As of September 30, 2007, FirstEnergy had $30 million of cash and cash equivalents compared with $90 million as of December 31, 2006. The major sources of changes in these balances are summarized below.
 
Cash Flows From Operating Activities

FirstEnergy's consolidated net cash from operating activities is provided primarily by its energy delivery services and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $1.2 billion in the first nine months of 2007 and 2006 summarized as follows:

 
 
Nine Months Ended
 
 
 
September 30,
 
Operating Cash Flows
 
2007
 
2006
 
   
(In millions)
 
Net income
 
$
1,041
 
$
979
 
Non-cash charges
 
 
358
 
 
497
 
Pension trust contribution
 
 
(300
)
 
-
 
Working capital and other
 
 
52
   
(233
)
 
 
$
1,151
 
$
1,243
 

Net cash provided from operating activities decreased by $92 million in the first nine months of 2007 compared to the first nine months of 2006 primarily due to a $300 million pension trust contribution in 2007 and a $139 million change in non-cash charges, partially offset by a $285 million change in working capital and other and a $62 million increase in net income (see Results of Operations above). The decrease in non-cash charges and increase from working capital primarily reflects changes to deferred income taxes and accrued taxes related to the Bruce Mansfield Unit 1 sale and leaseback transaction discussed above. Excluding the tax effects of the sale and leaseback transaction, the changes in working capital and other primarily resulted from a $322 million increase in receivables due to higher sales, partially offset by $92 million from reduced materials and supplies inventories due primarily to lower coal inventory levels and $78 million of decreased payments for accounts payable, reflecting a change in the timing of payments from the first nine months of 2006.

57


 
Cash Flows From Financing Activities

In the first nine months of 2007, cash used for financing activities was $1.4 billion compared to $444 million in the first nine months of 2006. The increase was primarily due to more common shares repurchased in 2007 than in 2006 and the repayment of short-term borrowings in 2007. The following table summarizes security issuances and redemptions.

 
 
Nine Months Ended
 
 
 
September 30,
 
Securities Issued or Redeemed
 
2007
 
2006
 
   
(In millions)
 
New issues
 
 
 
 
 
Pollution control notes
 
$
-
 
$
253
 
Secured notes
 
 
-
 
 
382
 
Unsecured notes
 
 
1,100
 
 
600
 
 
 
$
1,100
 
$
1,235
 
Redemptions
 
 
   
 
   
First mortgage bonds
 
$
287
 
$
1
 
Pollution control notes
 
 
4
 
 
311
 
Senior secured notes
 
 
203
 
 
181
 
Unsecured notes
   
153
   
500
 
Common stock
 
 
918
 
 
600
 
Preferred stock
 
 
-
 
 
107
 
 
 
$
1,565
 
$
1,700
 
 
 
 
   
 
   
Short-term borrowings, net
 
$
(535
)
$
482
 

FirstEnergy had approximately $573 million of short-term indebtedness as of September 30, 2007 compared to approximately $1.1 billion as of December 31, 2006. Available bank borrowing capability as of September 30, 2007 included the following:

Borrowing Capability (In millions)
 
 
 
Short-term credit facilities(1)
 
$
2,870
 
Accounts receivable financing facilities
   
550
 
Utilized
 
 
(570
)
LOCs
 
 
(337
)
Net available capability
 
 $
2,513
 
 
 
 
 
 
   
(1) Includes the  $2.75 billion revolving credit facility described below, a $100 million revolving credit facility that expires in December 2009 and a $20 million uncommitted line of credit.

As of September 30, 2007, the Ohio Companies and Penn had the aggregate capability to issue approximately $3.1 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $543 million, $459 million and $112 million, respectively, as of September 30, 2007. JCP&L satisfied the provision of its senior note indenture for the release of all FMBs held as collateral for senior notes in May 2007, subsequently repaid its other remaining FMBs and, effective September 14, 2007, discharged and released its mortgage indenture.

The applicable earnings coverage tests in the respective charters of OE, TE, Penn and JCP&L are currently inoperative. In the event that any of them issues preferred stock in the future, the applicable earnings coverage test will govern the amount of preferred stock that may be issued. CEI, Met-Ed and Penelec do not have similar restrictions and could issue up to the number of preferred shares authorized under their respective charters.

58



As of September 30, 2007, approximately $1.0 billion of capacity remained unused under an existing FirstEnergy shelf registration statement filed with the SEC in 2003 to support future securities issuances. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units. As of September 30, 2007, OE had approximately $400 million of capacity remaining unused under a shelf registration for unsecured debt securities filed with the SEC in 2006.

FirstEnergy and certain of its subsidiaries are parties to a $2.75 billion five-year revolving credit facility (included in the borrowing capability table above). FirstEnergy may request an increase in the total commitments available under this facility up to a maximum of $3.25 billion. Commitments under the facility are available until August 24, 2011, unless the lenders agree, at the request of the Borrowers, to two additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each Borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.

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

 
 
Revolving
 
Regulatory and
 
 
 
Credit Facility
 
Other Short-Term
 
Borrower
 
Sub-Limit
 
Debt Limitations(1)
 
 
 
(In millions)
 
FirstEnergy
 
$
2,750
 
$
-
(2)
OE
 
 
500
 
 
500
 
Penn
 
 
50
 
 
41
 
CEI
 
 
250
(3)
 
500
 
TE
 
 
250
(3)
 
500
 
JCP&L
 
 
425
 
 
423
 
Met-Ed
 
 
250
 
 
250
(4)
Penelec
 
 
250
 
 
250
(4)
FES
 
 
250
 
 
-
(2)
ATSI
 
 
-
(5)
 
50
 

 
(1)
As of September 30, 2007.
 
(2)
No regulatory approvals, statutory or charter limitations applicable.
 
(3)
Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s.
 
(4)
Excluding amounts which may be borrowed under the regulated money pool.
 
(5)
The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) such borrower has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed the obligations of such borrower under the facility.

The revolving credit facility, combined with an aggregate $550 million ($255 million unused as of September 30, 2007) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet working capital requirements and for other general corporate purposes for FirstEnergy and its subsidiaries.

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

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of September 30, 2007, FirstEnergy and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
 
 
FirstEnergy
 
57
%
OE
 
47
%
Penn
 
21
%
CEI
 
60
%
TE
 
55
%
JCP&L
 
31
%
Met-Ed
 
46
%
Penelec
 
50
%
FES
 
48
%


59



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

FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first nine months of 2007 was 5.66% for the regulated companies’ money pool and 5.65% for the unregulated companies’ money pool.

FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities.  The following table displays FirstEnergy’s, FES’ and the Companies’ securities ratings as of October 18, 2007. The ratings outlook from Moody’s is stable for FES and positive for all other companies. The ratings outlook from S&P on all securities is negative.

Issuer
 
Securities
 
S&P
 
Moody’s
             
FirstEnergy
 
Senior unsecured
 
BBB-
 
Baa3
             
OE
 
Senior unsecured
 
BBB-
 
Baa2
             
CEI
 
Senior secured
 
BBB+
 
Baa2
   
Senior unsecured
 
BBB-
 
Baa3
             
TE
 
Senior unsecured
 
BBB-
 
Baa3
             
Penn
 
Senior secured
 
A-
 
Baa1
             
JCP&L
 
Senior unsecured
 
BBB
 
Baa2
             
Met-Ed
 
Senior unsecured
 
BBB
 
Baa2
             
Penelec
 
Senior unsecured
 
BBB
 
Baa2
             
FES
 
Corporate Credit/Issuer Rating
 
BBB
 
Baa2

On February 21, 2007, FirstEnergy made a $700 million equity investment in FES, all of which was subsequently contributed to FGCO and used to pay down generation asset transfer-related promissory notes owed to the Ohio Companies and Penn. OE used its $500 million of proceeds to repurchase shares of its common stock from FirstEnergy.

On March 27, 2007, CEI issued $250 million of 5.70% unsecured senior notes due 2017.  The proceeds of the offering were used to reduce CEI’s short-term borrowings and for general corporate purposes.

On May 21, 2007, JCP&L issued $550 million of senior unsecured debt securities, consisting of $250 million of 5.65% senior notes due 2017 and $300 million of 6.15% senior notes due 2037.  A portion of the proceeds of the offering were used to redeem outstanding FMB of JCP&L comprised of $125 million principal amount of 7.50% series and $150 million principal amount of 6.75% series.  On July 1, 2007, JCP&L also redeemed all $12.2 million outstanding principal amount of its remaining series of FMB. In addition, $125 million of proceeds were used to repurchase shares of its common stock from FirstEnergy.  The remaining proceeds were used for general corporate purposes.

As described above, on July 13, 2007, FGCO completed the sale and leaseback of a 93.825% undivided interest in Unit 1 of the Bruce Mansfield Generating Plant. Net after-tax proceeds of approximately $1.2 billion from the transaction were used to repay short-term borrowings from, and to invest in, the FirstEnergy non-utility money pool. The repayments and investment allowed FES to reduce its investment in that money pool in order to repay approximately $250 million of external bank borrowings and fund a $600 million equity repurchase from FirstEnergy. FirstEnergy used these funds to reduce its external short term borrowings as discussed above.

On August 30, 2007, Penelec issued $300 million of 6.05% unsecured senior notes due 2017. A portion of the net proceeds from the issuance and sale of the senior notes were used to fund the repurchase of $200 million of Penelec’s common stock from FirstEnergy. The remaining net proceeds were used to repay short-term borrowings and for general corporate purposes.

60


On October 4, 2007, FGCO and NGC closed on the issuance of $427 million of pollution control revenue bonds (PCRBs). Proceeds from the issuance will be used to redeem, during the fourth quarter of 2007, an equal amount of outstanding PCRBs originally issued on behalf of the Ohio Companies. This transaction brings the total amount of PCRBs transferred from the Ohio Companies and Penn to FGCO and NGC to approximately $1.9 billion, with approximately $265 million remaining to be transferred. The transfer of these PCRBs supports the intra-system generation asset transfer that was completed in 2005.

Cash Flows From Investing Activities

Net cash flows provided from investing activities resulted principally from the proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction, partially offset by property additions. Energy delivery services expenditures for property additions primarily include expenditures related to transmission and distribution facilities. Capital expenditures by the competitive energy services segment are principally generation-related. The following table summarizes investing activities for the nine months ended September 30, 2007 and 2006 by segment:

Summary of Cash Flows
 
Property
             
Provided from (Used for) Investing Activities
 
Additions
 
Investments
 
Other
 
Total
 
Sources (Uses)
 
(In millions)
 
Nine Months Ended September 30, 2007
                 
Energy delivery services
 
$
(609
)
$
34
 
$
(2
)
$
(577
)
Competitive energy services
   
(462
)
 
1,345
   
(1
)
 
882
 
Other
   
(56
)
 
(5
)
 
2
   
(59
)
Inter-Segment reconciling items
   
-
   
(15
)
 
-
   
(15
)
Total
 
$
(1,127
)
$
1,359
 
$
(1
)
$
231
 
                           
Nine Months Ended September 30, 2006
                         
Energy delivery services
 
$
(489
)
$
196
 
$
(8
)
$
(301
)
Competitive energy services
   
(473
)
 
(7
)
 
(1
)
 
(481
)
Other
   
(28
)
 
31
   
20
   
23
 
Inter-Segment reconciling items
   
-
   
(63
)
 
-
   
(63
)
Total
 
$
(990
)
$
157
 
$
11
 
$
(822
)

In the first nine months of 2007, net cash provided from investing activities was $231 million compared to $822 million used for investing activities in the first nine months of 2006. The change was principally due to $1.3 billion in proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction described above.  Partially offsetting the cash proceeds from the sale and leaseback transaction was a $137 million increase in property additions and a $61 million decrease in cash provided from cash investments, primarily from the use of restricted cash investments to repay debt during 2006.

During the remaining three months of 2007, capital requirements for property additions and capital leases are expected to be approximately $460 million. FirstEnergy and the Companies have additional requirements of approximately $10 million for maturing long-term debt during the remainder of 2007. These cash requirements are expected to be satisfied from a combination of internal cash, short-term credit arrangements, and funds raised in the capital markets.

FirstEnergy's capital spending for the period 2007-2011 is expected to be nearly $8.0 billion (excluding nuclear fuel), of which approximately $1.5 billion applies to 2007. Investments for additional nuclear fuel during the 2007-2011 period are estimated to be approximately $1.2 billion, of which about $95 million applies to 2007. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $810 million and $100 million, respectively, as the nuclear fuel is consumed.

GUARANTEES AND OTHER ASSURANCES

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

As of September 30, 2007, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.7 billion, as summarized below:

61



 
 
Maximum
 
Guarantees and Other Assurances
 
Exposure
 
 
 
(In millions)
 
FirstEnergy Guarantees of Subsidiaries
 
 
 
Energy and Energy-Related Contracts (1)
 
$
647
 
LOC (long-term debt) – interest coverage (2)
   
9
 
Other (3)
 
 
575
 
 
 
 
1,231
 
         
Subsidiaries’ Guarantees
       
Energy and Energy-Related Contracts
   
37
 
LOC (long-term debt) – interest coverage (2)
   
3
 
Other (4)
 
 
2,686
 
     
2,726
 
         
Surety Bonds
 
 
75
 
LOC (long-term debt) – interest coverage (2)
 
 
5
 
LOC (non-debt) (5)(6)
 
 
690
 
 
 
 
   
Total Guarantees and Other Assurances
 
$
4,727
 

 
(1)
Issued for open-ended terms, with a 10-day termination right by FirstEnergy.
 
(2)
Reflects the interest coverage portion of LOCs issued in support of floating-rate pollution control revenue bonds with various maturities. The principal amount of floating-rate pollution control revenue bonds of $1.6 billion is reflected in long-term debt on FirstEnergy’s consolidated balance sheets.
 
(3)
Includes guarantees of $300 million for OVEC obligations and $80 million for nuclear decommissioning funding assurances.
 
(4)
Includes FES’ guarantee of FGCO’s obligations under the sale and leaseback of Bruce Mansfield Unit 1.
 
(5)
Includes $71 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility.
 
(6)
Includes approximately $194 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE.

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

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 guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

FirstEnergy has 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.

62


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

OFF-BALANCE SHEET ARRANGEMENTS

FES and the Ohio Companies have obligations that are not included on FirstEnergy’s Consolidated Balance Sheets related to sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. As of September 30, 2007, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $2.0 billion.

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

MARKET RISK INFORMATION

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

Commodity Price Risk

FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the three months and nine months ended September 30, 2007 is summarized in the following table:

 
Three Months Ended
 
Nine Months Ended
 
Increase (Decrease) in the Fair Value
September 30, 2007
 
September 30, 2007
 
of Commodity Derivative Contracts
Non-Hedge
 
Hedge
 
Total
 
Non-Hedge
 
Hedge
 
Total
 
 
(In millions)
 
Change in the Fair Value of
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Derivative Contracts:
           
 
 
 
 
 
 
Outstanding net liability at beginning of period
$
(845
)
$
(12
)
$
(857
)
$
(1,140
)
$
(17
)
$
(1,157
)
Additions/change in value of existing contracts
 
(38
)
 
-
 
 
(38
)
 
69
 
 
(6
)
 
63
 
Settled contracts
 
47
   
5
   
52
   
235
   
16
   
251
 
Outstanding net liability at end of period (1)
 
(836
)
 
(7
)
 
(843
)
 
(836
)
 
(7
)
 
(843
)
 
 
   
 
   
 
   
 
   
 
   
 
   
Non-commodity Net Liabilities at End of Period:
 
   
 
   
 
   
 
   
 
   
 
   
Interest rate swaps (2)
 
-
 
 
(8
)
 
(8
)
 
-
 
 
(8
)
 
(8
)
Net Liabilities - Derivative Contracts
at End of Period
$
(836
)
$
(15
)
$
(851
)
$
(836
)
$
(15
)
$
(851
)
 
 
   
 
   
 
   
 
   
 
   
 
   
Impact of Changes in Commodity Derivative Contracts(3)
 
   
 
   
 
   
 
   
 
   
 
   
Income Statement effects (pre-tax)
$
4
 
$
-
 
$
4
 
$
4
 
$
-
 
$
4
 
Balance Sheet effects:
 
   
 
   
 
   
 
   
 
   
 
   
Other comprehensive income (pre-tax)
$
-
 
$
5
 
$
5
 
$
-
 
$
10
 
$
10
 
Regulatory assets (net)
$
(5
)
$
-
 
$
(5
)
$
(300
)
$
-
 
$
(300
)

(1)
Includes $836 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.
(2)
Interest rate swaps are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements below).
(3)
Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

63


Derivatives are included on the Consolidated Balance Sheet as of September 30, 2007 as follows:

Balance Sheet Classification
 
Non-Hedge
 
Hedge
 
Total
 
   
(In millions)
 
Current-
             
Other assets
 
$
-
 
$
42
 
$
42
 
Other liabilities
   
-
   
(51
)
 
(51
)
                     
Non-Current-
                   
Other deferred charges
   
36
   
16
   
52
 
Other non-current liabilities
   
(872
)
 
(22
)
 
(894
)
                     
Net liabilities
 
$
(836
)
$
(15
)
$
(851
)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of September 30, 2007 are summarized by year in the following table:

Source of Information
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
- Fair Value by Contract Year
 
2007(1)
 
2008
 
2009
 
2010
 
2011
 
Thereafter
 
Total
 
   
(In millions)
 
Prices actively quoted(2)
 
$
-
 
$
-
 
$
-
 
$
-
 
 $
-
 
$
-
 
$
-
 
Other external sources(3)
 
 
(60
)
 
(239
)
 
(173
)
 
(150
)
 
-
 
 
-
 
 
(622
)
Prices based on models
 
 
-
 
 
-
 
 
-
 
 
-
 
 
(114
)
 
(107
)
 
(221
)
Total(4)
 
$
(60
)
$
(239
)
$
(173
)
$
(150
)
$
(114
)
$
(107
)
$
(843
)

(1)     For the last quarter of 2007.
(2)     Exchange traded.
(3)     Broker quote sheets.
(4)    Includes $836 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of September 30, 2007. Based on derivative contracts held as of September 30, 2007, an adverse 10% change in commodity prices would decrease net income by approximately $6 million during the next 12 months.

Interest Rate Swap Agreements- Fair Value Hedges

FirstEnergy utilizes fixed-for-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk associated with its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues – protecting 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 and interest payment dates match those of the underlying obligations. During the first nine months of 2007, FirstEnergy paid $8 million to terminate swaps with a notional amount $150 million as its subsidiary redeemed the associated hedged debt.  The loss was recognized as interest expense during the nine-month period.  As of September 30, 2007, the debt underlying the $600 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.11%, which the swaps have converted to a current weighted average variable rate of 5.72%.

   
September 30, 2007
 
December 31, 2006
 
   
Notional
 
Maturity
 
Fair
 
Notional
 
Maturity
 
Fair
 
Interest Rate Swaps
 
Amount
 
Date
 
Value
 
Amount
 
Date
 
Value
 
   
(In millions)
 
Fair value hedges
 
$
100
   
2008
 
$
(1
)
$
100
   
2008
 
$
(2
)
     
50
   
2010
   
-
   
50
   
2010
   
(1
)
     
300
   
2013
   
(4
)
 
300
   
2013
   
(6
)
     
150
   
2015
   
(9
)
 
150
   
2015
   
(10
)
     
-
   
2025
   
-
   
50
   
2025
   
(2
)
     
-
   
2031
   
-
   
100
   
2031
   
(6
)
   
$
600
       
$
(14
)
$
750
       
$
(27
)

64



Forward Starting Swap Agreements - Cash Flow Hedges

FirstEnergy utilizes forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 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 forward swaps with an aggregate notional value of $1.6 billion. FirstEnergy paid $20 million in cash related to the terminations, which will be recognized over the terms of the associated future debt. There was no ineffective portion associated with the loss. As of September 30, 2007, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $400 million and an aggregate fair value of $5 million.

   
September 30, 2007
 
December 31, 2006
 
   
Notional
 
Maturity
 
Fair
 
Notional
 
Maturity
 
Fair
 
Forward Starting Swaps
 
Amount
 
Date
 
Value
 
Amount
 
Date
 
Value
 
   
(In millions)
 
Cash flow hedges
 
$
25
   
2015
 
$
-
 
$
25
   
2015
 
$
-
 
     
300
   
2017
   
5
   
200
   
2017
   
(4
)
     
25
   
2018
   
(1
)
 
25
   
2018
   
(1
)
     
50
   
2020
   
1
   
50
   
2020
   
1
 
   
$
400
       
$
5
 
$
300
       
$
(4
)


Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $1.4 billion as of September 30, 2007 and December 31, 2006. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $139 million reduction in fair value as of September 30, 2007.

CREDIT RISK

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

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB+ (S&P). As of September 30, 2007, the largest credit concentration with one party (currently rated investment grade) represented 10.9% of FirstEnergy‘s total credit risk. Within FirstEnergy’s unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserves, were with investment-grade counterparties as of September 30, 2007.

Outlook

State Regulatory Matters

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

·
restructuring the electric generation business and allowing the Companies' customers to select a competitive electric generation supplier other than the Companies;
   
·
establishing or defining the PLR obligations to customers in the Companies' service areas;
   
·
providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

65



   
·
itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges;
   
·
continuing regulation of the Companies' transmission and distribution systems; and
   
·
requiring corporate separation of regulated and unregulated business activities.

The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $227 million as of September 30, 2007 (JCP&L - $93 million, Met-Ed - $43 million and Penelec - $91 million). Regulatory assets not earning a current return will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets by company:

 
 
September 30,
 
December 31,
 
Increase
 
Regulatory Assets*
 
2007
 
2006
 
(Decrease)
 
 
 
(In millions)
 
OE
 
$
717
 
$
741
 
$
(24
)
CEI
 
 
856
 
 
855
 
 
1
 
TE
 
 
215
 
 
248
 
 
(33
)
JCP&L
 
 
1,758
 
 
2,152
 
 
(394
)
Met-Ed
 
 
459
 
 
409
 
 
50
 
ATSI
 
 
42
 
 
36
 
 
6
 
Total
 
$
4,047
 
$
4,441
 
$
(394
)

 *
Penelec had net regulatory liabilities of approximately $77 million
and $96 million as of September 30, 2007 and December 31,
2006, respectively. These net regulatory liabilities are included in
Other Non-current Liabilities on the Consolidated Balance Sheets.

Regulatory assets by source are as follows:

 
 
September 30,
 
December 31,
 
Increase
 
Regulatory Assets By Source
 
2007
 
2006
 
(Decrease)
 
 
 
(In millions)
 
Regulatory transition costs
 
 $
2,583
 
$
3,266
 
$
(683
)
Customer shopping incentives
 
 
537
 
 
603
 
 
(66
)
Customer receivables for future income taxes
 
 
257
 
 
217
 
 
40
 
Societal benefits charge
 
 
(11
)
 
11
 
 
(22
)
Loss on reacquired debt
 
 
58
 
 
43
 
 
15
 
Employee postretirement benefits
 
 
41
 
 
47
 
 
(6
)
Nuclear decommissioning, decontamination
 
 
   
 
 
 
 
   
and spent fuel disposal costs
 
 
(118
)
 
(145
)
 
27
 
Asset removal costs
 
 
(177
)
 
(168
)
 
(9
)
Property losses and unrecovered plant costs
 
 
11
 
 
19
 
 
(8
)
MISO/PJM transmission costs
 
 
309
 
 
213
 
 
96
 
Fuel costs - RCP
 
 
175
 
 
113
 
 
62
 
Distribution costs - RCP
 
 
298
 
 
155
 
 
143
 
Other
 
 
84
 
 
67
 
 
17
 
Total
 
$
4,047
 
$
4,441
 
$
(394
)


66



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.

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.

67



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.

Ohio

The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2007 through 2010:

Amortization
 
 
 
 
 
 
 
 
 Total
 
Period
 
OE
 
CEI
 
TE
 
 Ohio
 
 
 
(In millions)
 
2007
 
$
176
 
$
108
 
$
92
 
$
376
 
2008
 
 
209
 
 
126
 
 
113
 
 
448
 
2009
 
 
-
 
 
217
 
 
-
 
 
217
 
2010
 
 
-
 
 
269
 
 
-
 
 
269
 
Total Amortization
 
$
385
 
$
720
 
$
205
 
$
1,310
 

 
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.

68


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.

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.

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.

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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.

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.

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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.

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.

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.

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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;

·   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.

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.

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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, 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.

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.

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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.

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.

Environmental Matters

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.

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.

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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.

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.

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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 coal-fired Pennsylvania 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.

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.

76


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 have been accrued through September 30, 2007.

Other Legal Proceedings

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 material items not otherwise discussed above are described below.

77



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.

78



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 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.

79



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.

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.

 
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.


80


 
 

FIRSTENERGY SOLUTIONS CORP.
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2007
   
2006
   
2007
    2006  
   
(In thousands)         
 
                         
REVENUES:
                       
Electric sales to affiliates
  $
805,372
    $
762,106
    $
2,209,743
    $
1,997,096
 
Other
   
365,536
     
347,474
     
1,048,189
     
1,063,026
 
Total revenues
   
1,170,908
     
1,109,580
     
3,257,932
     
3,060,122
 
                                 
EXPENSES:
                               
Fuel
   
301,786
     
315,521
     
804,201
     
844,913
 
Purchased power from non-affiliates
   
228,755
     
173,620
     
577,831
     
477,249
 
Purchased power from affiliates
   
62,508
     
55,647
     
209,576
     
188,698
 
Other operating expenses
   
235,033
     
198,716
     
731,774
     
774,767
 
Provision for depreciation
   
48,500
     
46,894
     
145,030
     
135,414
 
General taxes
   
22,242
     
17,609
     
64,870
     
55,550
 
Total expenses
   
898,824
     
808,007
     
2,533,282
     
2,476,591
 
                                 
OPERATING INCOME
   
272,084
     
301,573
     
724,650
     
583,531
 
                                 
OTHER INCOME (EXPENSE):
                               
Miscellaneous income
   
12,655
     
27,662
     
47,756
     
44,843
 
Interest expense to affiliates
    (9,641 )     (41,416 )     (61,904 )     (122,664 )
Interest expense - other
    (31,794 )     (7,914 )     (70,845 )     (17,880 )
Capitalized interest
   
5,131
     
2,389
     
12,763
     
8,698
 
Total other expense
    (23,649 )     (19,279 )     (72,230 )     (87,003 )
                                 
INCOME BEFORE INCOME TAXES
   
248,435
     
282,294
     
652,420
     
496,528
 
                                 
INCOME TAXES
   
93,671
     
106,175
     
243,736
     
184,572
 
                                 
NET INCOME
   
154,764
     
176,119
     
408,684
     
311,956
 
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    (1,360 )    
-
      (4,080 )    
-
 
Unrealized gain (loss) on derivative hedges
   
4,863
      (6,257 )    
9,451
      (6,376 )
Change in unrealized gain on available for sale securities
   
21,263
     
20,945
     
80,053
     
29,266
 
Other comprehensive income
   
24,766
     
14,688
     
85,424
     
22,890
 
Income tax expense related to other
                               
  comprehensive income
   
8,915
     
5,453
     
30,474
     
8,548
 
Other comprehensive income, net of tax
   
15,851
     
9,235
     
54,950
     
14,342
 
                                 
TOTAL COMPREHENSIVE INCOME
  $
170,615
    $
185,354
    $
463,634
    $
326,298
 
                                 
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part of     
 
these statements.
                               

81

 

 
FIRSTENERGY SOLUTIONS CORP.
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
   
December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $
2
    $
2
 
Receivables-
               
Customers (less accumulated provisions of $8,007,000 and $7,938,000,
               
respectively, for uncollectible accounts)
   
144,443
     
129,843
 
Associated companies
   
285,462
     
235,532
 
Other (less accumulated provisions of $9,000 and $5,593,000,
               
respectively, for uncollectible accounts)
   
5,416
     
4,085
 
Notes receivable from associated companies
   
242,612
     
752,919
 
Materials and supplies, at average cost
   
441,066
     
460,239
 
Prepayments and other
   
83,825
     
57,546
 
     
1,202,826
     
1,640,166
 
PROPERTY, PLANT AND EQUIPMENT:
               
In service
   
8,183,578
     
8,355,344
 
Less - Accumulated provision for depreciation
   
3,852,896
     
3,818,268
 
     
4,330,682
     
4,537,076
 
Construction work in progress
   
596,879
     
339,886
 
     
4,927,561
     
4,876,962
 
OTHER PROPERTY AND INVESTMENTS:
               
Nuclear plant decommissioning trusts
   
1,342,083
     
1,238,272
 
Long-term notes receivable from associated companies
   
62,900
     
62,900
 
  Other
   
39,964
     
72,509
 
     
1,444,947
     
1,373,681
 
DEFERRED CHARGES AND OTHER ASSETS:
               
Accumulated deferred income taxes
   
240,182
     
-
 
Goodwill
   
24,248
     
24,248
 
Property taxes
   
44,111
     
44,111
 
Pension assets
   
9,449
     
-
 
  Other
   
70,638
     
39,839
 
     
388,628
     
108,198
 
    $
7,963,962
    $
7,999,007
 
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $
1,469,721
    $
1,469,660
 
Short-term borrowings-
               
Associated companies
   
237,070
     
1,022,197
 
Accounts payable-
               
Associated companies
   
432,695
     
556,049
 
Other
   
177,820
     
136,631
 
Accrued taxes
   
537,060
     
113,231
 
  Other
   
163,239
     
100,941
 
     
3,017,605
     
3,398,709
 
CAPITALIZATION:
               
Common stockholder's equity-
               
Common stock, without par value, authorized 750 shares-
               
7 and 8 shares outstanding, respectively
   
1,163,934
     
1,050,302
 
Accumulated other comprehensive income
   
166,673
     
111,723
 
Retained earnings
   
1,038,412
     
697,338
 
Total common stockholder's equity
   
2,369,019
     
1,859,363
 
Long-term debt
   
505,196
     
1,614,222
 
     
2,874,215
     
3,473,585
 
NONCURRENT LIABILITIES:
               
Deferred gain on sale and leaseback transaction
   
1,068,769
     
-
 
Accumulated deferred income taxes
   
-
     
121,449
 
Accumulated deferred investment tax credits
   
62,275
     
65,751
 
Asset retirement obligation
   
797,357
     
760,228
 
Retirement benefits
   
53,505
     
103,027
 
Property taxes
   
44,433
     
44,433
 
  Other
   
45,803
     
31,825
 
     
2,072,142
     
1,126,713
 
COMMITMENTS AND CONTINGENCIES (Note 10)
               
    $
7,963,962
    $
7,999,007
 
                 
The preceding Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral part of these
balance sheets.
               

82


 
FIRSTENERGY SOLUTIONS CORP.
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30,
 
   
2007
   
2006
 
   
(In thousands)
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $
408,684
    $
311,956
 
Adjustments to reconcile net income to net cash from operating activities-
         
Provision for depreciation
   
145,030
     
135,414
 
Nuclear fuel and lease amortization
   
75,102
     
66,360
 
Deferred income taxes and investment tax credits, net
    (381,042 )    
47,188
 
Investment impairment
   
14,296
     
-
 
Accrued compensation and retirement benefits
   
3,414
     
13,704
 
Commodity derivative transactions, net
   
4,913
     
46,500
 
Gain on asset sales
    (12,105 )     (35,973 )
Cash collateral, net
    (19,798 )    
20,643
 
Pension trust contribution
    (64,020 )    
-
 
Decrease (increase) in operating assets:
               
Receivables
    (30,172 )     (46,063 )
Materials and supplies
   
48,123
      (1,683 )
Prepayments and other current assets
    (5,118 )    
211
 
Increase (decrease) in operating liabilities:
               
Accounts payable
    (108,949 )     (162,502 )
Accrued taxes
   
424,100
     
77,524
 
Accrued interest
   
14,355
     
2,431
 
Other
    (36,498 )     (17,605 )
Net cash provided from operating activities
   
480,315
     
458,105
 
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
   
-
     
251,945
 
Equity contributions from parent
   
710,468
     
-
 
Short-term borrowings, net
   
-
     
66,817
 
Redemptions and Repayments-
               
Common stock
    (600,000 )    
-
 
Long-term debt
    (1,110,174 )    
(253,240
)
Short-term borrowings, net
    (785,127 )    
-
 
Common stock dividend payments
    (67,000 )    
-
 
Net cash provided from (used for) financing activities
    (1,851,833 )    
65,522
 
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (482,907 )     (427,298 )
Proceeds from asset sales
   
12,990
     
20,437
 
Proceeds from sale and leaseback transaction
   
1,328,919
     
-
 
Sales of investment securities held in trusts
   
521,535
     
886,863
 
Purchases of investment securities held in trusts
    (521,535 )     (886,863 )
Loan repayments from (loans to) associated companies, net
   
510,307
      (88,292 )
Other
   
2,209
      (28,474 )
Net cash provided from (used for) investing activities
   
1,371,518
      (523,627 )
                 
Net change in cash and cash equivalents
   
-
     
-
 
Cash and cash equivalents at beginning of period
   
2
     
2
 
Cash and cash equivalents at end of period
  $
2
    $
2
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an
integral part of these statements.
               

83


 
 


Report of Independent Registered Public Accounting Firm









To the Stockholder and Board of
Directors of FirstEnergy Solutions Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006 as discussed in Note 3 to those consolidated financial statements) dated April 11, 2007,except as to Note 12, which is as of August 6, 2007, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007


84



FIRSTENERGY SOLUTIONS CORP.

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


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

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

Results of Operations

In the first nine months of 2007, net income increased to $409 million from $312 million in the first nine months of 2006. The increase in net income was primarily due to higher revenues and lower fuel and other operating expenses, partially offset by higher purchased power costs.

Revenues

Revenues increased by $198 million in the first nine months of 2007 compared to the same period in 2006 due to increases in revenues from non-affiliated retail generation sales and affiliated wholesale sales, partially offset by lower non-affiliated wholesale sales. Retail generation sales revenues increased as a result of higher unit prices and increased KWH sales. Higher unit prices primarily reflected higher generation rates in the MISO and PJM markets where FES is an alternative supplier. Increased KWH sales to FES’ commercial and industrial customers during the first nine months of 2007 were partially offset by a decrease in sales to residential customers returning to FES’ Ohio utility affiliates for their generation requirements. Affiliated wholesale revenues were higher as a result of increased sales and higher unit prices for sales to the Ohio Companies.

Non-affiliated wholesale revenues decreased as a result of lower generation available for the non-affiliated market due to increased affiliated company power sales requirements under the Ohio Companies’ full-requirements PSA and the partial-requirements power sales agreement with Met-Ed and Penelec.

The increase in sales to the Ohio Companies was due to their higher retail generation sales requirements. Higher unit prices resulted from the provision of the full-requirements PSA under which PSA rates reflect the increase in the Ohio Companies’ retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn as a result of the implementation of its competitive solicitation process in 2007.

Transmission revenue decreased $25 million due to reduced retail load in the MISO market, lower transmission rates and reduced financial transmission rights auction revenue.

Changes in revenues in the first nine months of 2007 from the same period of 2006 are summarized below:

85



   
Nine  Months Ended
     
   
Sept 30,
 
Increase
 
Revenues by Type of Service
 
2007
 
2006
 
(Decrease)
 
   
(In millions)
 
Non-Affiliated Generation Sales:
             
Retail
 
$
547
 
$
445
 
$
102
 
Wholesale
   
425
   
509
   
(84
)
Total Non-Affiliated Generation Sales
   
972
   
954
   
18
 
Affiliated Generation Sales
   
2,210
   
1,997
   
213
 
Transmission
   
71
   
96
   
(25
)
Other
   
5
   
13
   
(8
)
Total Revenues
 
$
3,258
 
$
3,060
 
$
198
 

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated sales in the first nine months of 2007 compared to the same period last year:

   
Increase
 
Source of Change in Non-Affiliated Generation Revenues
 
(Decrease)
 
   
(In millions)
 
Retail:
 
 
   
Effect of 12% increase in sales volumes
 
$
52
 
Change in prices
 
 
50
 
 
 
 
102
 
Wholesale:
 
 
   
Effect of 26% decrease in sales volumes
 
 
(131
)
Change in prices
 
 
47
 
 
 
 
(84
)
Net Increase in Non-Affiliated Generation Revenues
 
$
18
 

Source of Change in Affiliated Generation Revenues
 
Increase
 
   
(In millions)
 
Ohio Companies:
 
 
   
Effect of 4% increase in sales volumes
 
$
56
 
Change in prices
 
 
89
 
 
 
 
145
 
Pennsylvania Companies:
 
 
   
Effect of 12% increase in sales volumes
 
 
54
 
Change in prices
 
 
14
 
 
 
 
68
 
Net Increase in Affiliated Generation Revenues
 
$
213
 

Expenses

Total expenses increased by $57 million in the first nine months of 2007 compared with the same period of 2006. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first nine months of 2007 from the same period last year:

Source of Change in Fuel and Purchased Power
 
Increase
 (Decrease)
 
   
(In millions)
 
Nuclear Fuel:
       
Change due to increased unit costs
 
 $
3
 
Change due to volume consumed
 
 
5
 
 
 
 
8
 
Fossil Fuel:
       
Change due to decreased unit costs
 
 
(4
)
Change due to volume consumed
 
 
(45
)
 
 
 
(49
)
Purchased Power:
       
Change due to increased unit costs
 
 
51
 
Change due to volume purchased
 
 
71
 
 
 
 
122
 
Net Increase in Fuel and Purchased Power Costs
 
$
81
 

86


Fossil fuel costs decreased $49 million in the first nine months of 2007 primarily as a result of reduced coal and emission allowance costs. Coal costs were lower due to a $14 million inventory adjustment as a result of an interim physical inventory and $23 million from reduced coal consumption reflecting lower generation as a result of planned maintenance outages at Sammis Units 6 and 7 and Eastlake Unit 5 and forced outage at Mansfield Unit 1.

The lower fossil fuel costs were partially offset by higher nuclear fuel costs of $8 million. Higher nuclear fuel costs were due to higher unit costs and increased nuclear generation in the first nine months of 2007 as compared to the same period of 2006.

Purchased power costs increased as a result of increased volumes purchased and higher unit prices. Volumes purchased in the first nine months of 2007 increased by 10.6% due to the outages at the Sammis, Eastlake, Mansfield and Perry plants.  Other operating expenses decreased by $43 million in the first nine months of 2007 from the same period of 2006 primarily due to lower nuclear operating costs as a result of fewer outages in 2007 compared to 2006 and reduced employee benefit costs.

Depreciation expense increased by $10 million in the first nine months of 2007 primarily due to fossil and nuclear property additions subsequent to the third quarter of 2006.

General taxes increased by $9 million in the first nine months of 2007 compared to the same period of 2006 as a result of higher property taxes and gross receipts taxes.

Other Expense

Other expense decreased by $15 million in the first nine months of 2007 from the same periods of 2006 primarily as a result of lower interest expense. Lower interest expense reflected the repayment of GAT-related notes to associated companies, partially offset by the issuance of lower-cost pollution control debt subsequent to October 1, 2006.

Legal Proceedings

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

New Accounting Standards and Interpretations

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

87



 
OHIO EDISON COMPANY
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2007
   
2006
   
2007
   
2006
 
                         
STATEMENTS OF INCOME
 
(In thousands)
 
                         
REVENUES:
                       
Electric sales
  $
638,336
    $
642,294
    $
1,802,110
    $
1,745,699
 
Excise tax collections
   
30,472
     
31,379
     
89,077
     
87,269
 
Total revenues
   
668,808
     
673,673
     
1,891,187
     
1,832,968
 
                                 
EXPENSES:
                               
   Fuel
   
2,821
     
2,954
     
8,148
     
8,726
 
Purchased power
   
364,709
     
395,560
     
1,037,200
     
971,613
 
Nuclear operating costs
   
41,783
     
44,995
     
130,951
     
129,585
 
Other operating costs
   
100,265
     
108,362
     
285,871
     
290,776
 
Provision for depreciation
   
19,482
     
18,399
     
57,440
     
53,962
 
Amortization of regulatory assets
   
53,026
     
49,717
     
144,569
     
147,022
 
Deferral of new regulatory assets
    (41,417 )     (44,962 )     (132,410 )     (123,285 )
General taxes
   
46,158
     
47,826
     
141,296
     
137,652
 
Total expenses
   
586,827
     
622,851
     
1,673,065
     
1,616,051
 
                                 
OPERATING INCOME
   
81,981
     
50,822
     
218,122
     
216,917
 
                                 
OTHER INCOME (EXPENSE):
                               
Investment income
   
19,827
     
32,993
     
67,803
     
98,853
 
Miscellaneous income
   
670
     
1,639
     
3,362
     
835
 
Interest expense
    (20,311 )     (24,597 )     (62,749 )     (60,195 )
Capitalized interest
   
136
     
698
     
398
     
1,832
 
Subsidiary's preferred stock dividend requirements
   
-
      (156 )    
-
      (467 )
Total other income
   
322
     
10,577
     
8,814
     
40,858
 
                                 
INCOME BEFORE INCOME TAXES
   
82,303
     
61,399
     
226,936
     
257,775
 
                                 
INCOME TAXES
   
34,089
     
17,902
     
79,074
     
91,239
 
                                 
NET INCOME
   
48,214
     
43,497
     
147,862
     
166,536
 
                                 
PREFERRED STOCK DIVIDEND REQUIREMENTS AND
                               
REDEMPTION PREMIUM
   
-
     
51
     
-
     
4,297
 
                                 
EARNINGS ON COMMON STOCK
  $
48,214
    $
43,446
    $
147,862
    $
162,239
 
                                 
                                 
STATEMENTS OF COMPREHENSIVE INCOME
                               
                                 
NET INCOME
  $
48,214
    $
43,497
    $
147,862
    $
166,536
 
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirment benefits
    (3,423 )    
-
      (10,270 )    
-
 
Change in unrealized gain on available for sale securities
   
2,442
     
3,795
     
7,415
     
5,467
 
Other comprehensive income (loss)
    (981 )    
3,795
      (2,855 )    
5,467
 
Income tax expense (benefit) related to other
                               
  comprehensive income
    (573 )    
1,369
      (1,688 )    
1,972
 
Other comprehensive income (loss), net of tax
    (408 )    
2,426
      (1,167 )    
3,495
 
                                 
TOTAL COMPREHENSIVE INCOME
  $
47,806
    $
45,923
    $
146,695
    $
170,031
 
                                 
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
 
statements.
                               

88

 

OHIO EDISON COMPANY     
 
CONSOLIDATED BALANCE SHEETS     
 
(Unaudited)     
 
   
September 30,
   
December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $
727
    $
712
 
Receivables-
               
Customers (less accumulated provisions of $8,518,000 and $15,033,000,
               
respectively, for uncollectible accounts)
   
271,680
     
234,781
 
Associated companies
   
167,686
     
141,084
 
Other (less accumulated provisions of $5,548,000 and $1,985,000,
               
respectively, for uncollectible accounts)
   
20,093
     
13,496
 
Notes receivable from associated companies
   
626,841
     
458,647
 
Prepayments and other
   
17,148
     
13,606
 
     
1,104,175
     
862,326
 
UTILITY PLANT:
               
In service
   
2,722,468
     
2,632,207
 
Less - Accumulated provision for depreciation
   
1,053,942
     
1,021,918
 
     
1,668,526
     
1,610,289
 
Construction work in progress
   
42,494
     
42,016
 
     
1,711,020
     
1,652,305
 
OTHER PROPERTY AND INVESTMENTS:
               
Long-term notes receivable from associated companies
   
365,767
     
1,219,325
 
Investment in lease obligation bonds
   
274,077
     
291,393
 
Nuclear plant decommissioning trusts
   
128,168
     
118,209
 
  Other
   
36,756
     
38,160
 
     
804,768
     
1,667,087
 
DEFERRED CHARGES AND OTHER ASSETS:
               
Regulatory assets
   
717,311
     
741,564
 
Pension assets
   
106,682
     
68,420
 
Property taxes
   
60,080
     
60,080
 
Unamortized sale and leaseback costs
   
46,384
     
50,136
 
  Other
   
44,457
     
18,696
 
     
974,914
     
938,896
 
    $
4,594,877
    $
5,120,614
 
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $
442,264
    $
159,852
 
Short-term borrowings-
               
Associated companies
   
-
     
113,987
 
Other
   
52,609
     
3,097
 
Accounts payable-
               
Associated companies
   
200,104
     
115,252
 
Other
   
17,766
     
13,068
 
Accrued taxes
   
141,516
     
187,306
 
Accrued interest
   
17,435
     
24,712
 
  Other
   
101,543
     
64,519
 
     
973,237
     
681,793
 
CAPITALIZATION:
               
Common stockholder's equity-
               
Common stock, without par value, authorized 175,000,000 shares -
               
60 and 80 shares outstanding, respectively
   
1,220,173
     
1,708,441
 
Accumulated other comprehensive income
   
2,041
     
3,208
 
Retained earnings
   
257,870
     
260,736
 
Total common stockholder's equity
   
1,480,084
     
1,972,385
 
Long-term debt and other long-term obligations
   
836,430
     
1,118,576
 
     
2,316,514
     
3,090,961
 
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
   
676,784
     
674,288
 
Accumulated deferred investment tax credits
   
17,856
     
20,532
 
Asset retirement obligations
   
92,157
     
88,223
 
Retirement benefits
   
159,096
     
167,379
 
Deferred revenues - electric service programs
   
59,255
     
86,710
 
  Other
   
299,978
     
310,728
 
     
1,305,126
     
1,347,860
 
COMMITMENTS AND CONTINGENCIES (Note 10)
               
    $
4,594,877
    $
5,120,614
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of
         
these balance sheets.
               

89



 
OHIO EDISON COMPANY
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30,
 
   
2007
   
2006
 
   
(In thousands)   
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $
147,862
    $
166,536
 
Adjustments to reconcile net income to net cash from operating activities-
               
Provision for depreciation
   
57,440
     
53,962
 
Amortization of regulatory assets
   
144,569
     
147,022
 
Deferral of new regulatory assets
    (132,410 )     (123,285 )
Amortization of lease costs
   
28,567
     
28,600
 
Deferred income taxes and investment tax credits, net
    (29,155 )     (27,850 )
Accrued compensation and retirement benefits
    (34,572 )    
2,985
 
Pension trust contribution
    (20,261 )    
-
 
Decrease (increase) in operating assets-
               
Receivables
    (70,098 )    
26,198
 
Prepayments and other current assets
    (3,542 )     (4,172 )
Increase (decrease) in operating liabilities-
               
Accounts payable
   
89,550
      (24,937 )
Accrued taxes
    (37,355 )     (27,826 )
Accrued interest
    (7,277 )    
12,839
 
Electric service prepayment programs
    (27,455 )     (24,975 )
  Other
   
7,260
     
2,570
 
Net cash provided from operating activities
   
113,123
     
207,667
 
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
   
-
     
592,763
 
Equity contributions from parent
   
11,621
     
-
 
Redemptions and Repayments-
               
Common stock
    (500,000 )     (500,000 )
Preferred stock
   
-
      (63,893 )
Long-term debt
    (1,190 )     (138,085 )
Short-term borrowings, net
    (64,475 )     (177,595 )
Dividend Payments-
               
Common stock
    (150,000 )     (73,000 )
Preferred stock
   
-
      (1,369 )
Net cash used for financing activities
    (704,044 )     (361,179 )
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (109,461 )     (94,278 )
Sales of investment securities held in trusts
   
31,624
     
32,826
 
Purchases of investment securities held in trusts
    (33,586 )     (34,209 )
Loan repayments from associated companies, net
   
685,364
     
148,199
 
Cash investments
   
17,316
     
93,900
 
Other
    (321 )    
6,848
 
Net cash provided from investing activities
   
590,936
     
153,286
 
                 
Net increase (decrease) in cash and cash equivalents
   
15
      (226 )
Cash and cash equivalents at beginning of period
   
712
     
929
 
Cash and cash equivalents at end of period
  $
727
    $
703
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral
 
part of these statements.
               
 
 

90



 



Report of Independent Registered Public Accounting Firm









To the Stockholder and Board of
Directors of Ohio Edison Company:

We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006,  and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 3, Note 2(G) and Note 11 to the consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007


91



OHIO EDISON COMPANY

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


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

Results of Operations

In the first nine months of 2007, earnings on common stock decreased to $148 million from $162 million in the same period of 2006. The decrease in earnings primarily resulted from higher purchased power costs and lower other income, partially offset by higher electric sales revenues.
 
Revenues

Revenues increased by $58 million or 3.2% in the first nine months of 2007 compared with the same period in 2006, primarily due to a $65 million increase in retail generation revenues, partially offset by decreases in revenues from distribution throughput of $16 million.

Higher retail generation revenues from residential customers reflected increased sales volume and the impact of higher average unit prices. Weather conditions in the  first nine months of 2007 compared to the same period in 2006 contributed to the higher KWH sales to residential customers (heating degree days increased 11.5% and 8.4% and cooling degree days increased by 26.9% and 25.2% in OE’s and Penn’s service territories, respectively). Commercial retail generation revenues increased primarily due to higher average unit prices, partially offset by reduced KWH sales. Average prices increased due to the higher generation prices that were effective in January 2007 under Penn’s competitive RFP process. Retail generation revenues from the industrial sector decreased primarily due to an increase in customer shopping in Penn’s service territory in the first nine months of 2007 as compared to the same period in 2006. The percentage of shopping customers increased to 27.7 percent in the first nine months of 2007 from 15.8 percent in the first nine months of 2006.

Changes in retail generation sales and revenues in the first nine months of 2007 from the corresponding period of 2006 are summarized in the following tables:

Retail Generation KWH Sales
 
Increase (Decrease)
 
         
Residential
 
 
7.4
 %
Commercial
 
 
(1.4
)%
Industrial
 
 
(16.0
)%
Net Decrease in Generation Sales
 
 
(3.7
)%

Retail Generation Revenues
 
Increase (Decrease)
 
   
(In millions)
 
Residential
 
$
80
 
Commercial
   
23
 
Industrial
   
(38
)
Net Increase in Generation Revenues
 
$
65
 

A small increase in distribution revenues from residential customers was more than offset by decreases in distribution revenues from commercial and industrial customers. The increase from residential customers reflected higher deliveries due to the favorable weather conditions described above in the first nine months of 2007 as compared to the same period in 2006, partially offset by lower composite unit prices. Reduced distribution revenues from commercial customers in the first nine months of 2007 resulted from lower unit prices, partially offset by increased KWH deliveries. Distribution revenues from industrial customers decreased in the first nine months of 2007 as a result of lower unit prices and reduced KWH deliveries.


92


Changes in distribution KWH deliveries and revenues in the first nine months of 2007 from the corresponding period of 2006 are summarized in the following tables.

Distribution KWH Deliveries
 
Increase (Decrease)
 
         
Residential
 
 
5.8
 %
Commercial
 
 
3.3
 %
Industrial
 
 
(2.2
)%
 Net Increase in Distribution Deliveries
 
 
2.2
 %

Distribution Revenues
 
Increase (Decrease)
 
   
(In millions)
 
Residential
 
$
2
 
Commercial
   
(5
)
Industrial
   
(13
)
 Net Decrease in Distribution Revenues
 
$
(16
)

Expenses

Total expenses increased by $57 million in the first nine months of 2007 from the same period of 2006. The following table presents changes from the prior year by expense category.

Expenses – Changes
 
Increase (Decrease)
 
     
(In millions)
 
Purchased power costs
 
$
65
 
Nuclear operating costs
   
1
 
Other operating costs
 
 
(5
)
Provision for depreciation
   
3
 
Amortization of regulatory assets
   
(2
)
Deferral of new regulatory assets
   
(9
)
General taxes
 
 
4
 
Net Increase in Expenses
 
$
57
 

Higher purchased power costs in the first nine months of 2007 primarily reflected higher unit prices under Penn’s competitive RFP process and OE’s PSA with FES. The decrease in other operating costs for the first nine months of 2007 was primarily due to lower employee benefit expenses, partially offset by higher transmission expenses related to MISO operations. Higher depreciation expense in the first nine months of 2007 reflected capital additions subsequent to the third quarter of 2006. The increase in the deferral of new regulatory assets for the first nine months of 2007 was primarily due to increases in MISO cost deferrals and RCP distribution cost deferrals, partially offset by lower RCP fuel cost deferrals. General taxes were higher in the first nine months of 2007 as compared to the same period last year as a result of higher real and personal property taxes and KWH excise taxes.

Other Income

Other income decreased $32 million in the first nine months of 2007 as compared with the same period of 2006 primarily due to reductions in interest income on notes receivable resulting from principal payments from associated companies since the third quarter of 2006. Higher interest expense also contributed to the decrease in other income in the first nine months of 2007, with interest expense associated with OE’s issuance of $600 million of long-term debt in June 2006 being partially offset by debt redemptions since the third quarter of 2006.

Legal Proceedings

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

New Accounting Standards and Interpretations

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


93


 
 

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
                         
   
2007
   
2006
   
2007
   
2006
 
   
(In thousands)
 
                         
REVENUES:
                       
Electric sales
  $
510,577
    $
497,336
    $
1,366,396
    $
1,304,525
 
Excise tax collections
   
18,514
     
18,587
     
53,009
     
51,579
 
Total revenues
   
529,091
     
515,923
     
1,419,405
     
1,356,104
 
                                 
EXPENSES:
                               
   Fuel
   
12,160
     
12,748
     
39,683
     
39,724
 
Purchased power
   
216,194
     
229,779
     
575,520
     
531,490
 
Other operating costs
   
85,114
     
81,510
     
243,140
     
222,841
 
Provision for depreciation
   
18,913
     
17,524
     
56,094
     
45,775
 
Amortization of regulatory assets
   
42,077
     
38,826
     
110,253
     
99,832
 
Deferral of new regulatory assets
    (37,692 )     (39,060 )     (114,708 )     (101,283 )
General taxes
   
37,930
     
34,228
     
110,922
     
100,808
 
Total expenses
   
374,696
     
375,555
     
1,020,904
     
939,187
 
                                 
OPERATING INCOME
   
154,395
     
140,368
     
398,501
     
416,917
 
                                 
OTHER INCOME (EXPENSE):
                               
Investment income
   
13,805
     
24,715
     
47,816
     
76,325
 
Miscellaneous income (expense)
    (760 )    
813
     
3,197
     
6,209
 
Interest expense
    (34,423 )     (34,774 )     (107,430 )     (104,140 )
Capitalized interest
   
309
     
836
     
655
     
2,346
 
Total other expense
    (21,069 )     (8,410 )     (55,762 )     (19,260 )
                                 
INCOME BEFORE INCOME TAXES
   
133,326
     
131,958
     
342,739
     
397,657
 
                                 
INCOME TAXES
   
54,610
     
48,496
     
131,525
     
150,730
 
                                 
NET INCOME
   
78,716
     
83,462
     
211,214
     
246,927
 
                                 
OTHER COMPREHENSIVE INCOME:
                               
Pension and other postretirement benefits
   
1,202
     
-
     
3,607
     
-
 
Income tax expense related to other comprehensive income
   
356
     
-
     
1,068
     
-
 
Other comprehensive income, net of tax
   
846
     
-
     
2,539
     
-
 
                                 
TOTAL COMPREHENSIVE INCOME
  $
79,562
    $
83,462
    $
213,753
    $
246,927
 
                                 
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral
 
part of these statements.
                               
 

94



THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
   
December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $
234
    $
221
 
Receivables-
               
Customers (less accumulated provisions of $8,057,000 and $6,783,000
         
respectively, for uncollectible accounts)
   
304,608
     
245,193
 
Associated companies
   
53,564
     
249,735
 
Other
   
21,331
     
14,240
 
Notes receivable from associated companies
   
41,054
     
27,191
 
Prepayments and other
   
1,510
     
2,314
 
     
422,301
     
538,894
 
UTILITY PLANT:
               
In service
   
2,199,913
     
2,136,766
 
Less - Accumulated provision for depreciation
   
844,600
     
819,633
 
     
1,355,313
     
1,317,133
 
Construction work in progress
   
55,382
     
46,385
 
     
1,410,695
     
1,363,518
 
OTHER PROPERTY AND INVESTMENTS:
               
Long-term notes receivable from associated companies
   
265,660
     
486,634
 
Investment in lessor notes
   
463,433
     
519,611
 
  Other
   
10,302
     
13,426
 
     
739,395
     
1,019,671
 
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
   
1,688,521
     
1,688,521
 
Regulatory assets
   
855,618
     
854,588
 
Pension assets
   
16,791
     
-
 
Property taxes
   
65,000
     
65,000
 
  Other
   
42,993
     
33,306
 
     
2,668,923
     
2,641,415
 
    $
5,241,314
    $
5,563,498
 
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $
266,271
    $
120,569
 
Short-term borrowings-
               
Associated companies
   
73,459
     
218,134
 
Other
   
100,000
     
-
 
Accounts payable-
               
Associated companies
   
237,072
     
365,678
 
Other
   
6,194
     
7,194
 
Accrued taxes
   
132,941
     
128,829
 
Accrued interest
   
41,393
     
19,033
 
Lease market valuation liability
   
58,750
     
60,200
 
  Other
   
44,931
     
52,101
 
     
961,011
     
971,738
 
                 
CAPITALIZATION:
               
Common stockholder's equity-
               
Common stock, without par value, authorized 105,000,000 shares -
               
67,930,743 shares outstanding
   
873,037
     
860,133
 
Accumulated other comprehensive loss
    (101,892 )     (104,431 )
Retained earnings
   
620,155
     
713,201
 
Total common stockholder's equity
   
1,391,300
     
1,468,903
 
Long-term debt and other long-term obligations
   
1,670,898
     
1,805,871
 
     
3,062,198
     
3,274,774
 
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
   
461,410
     
470,707
 
Accumulated deferred investment tax credits
   
18,994
     
20,277
 
Lease market valuation liability
   
491,085
     
547,800
 
Retirement benefits
   
110,620
     
122,862
 
Deferred revenues - electric service programs
   
34,768
     
51,588
 
  Other
   
101,228
     
103,752
 
     
1,218,105
     
1,316,986
 
COMMITMENTS AND CONTINGENCIES (Note 10)
               
    $
5,241,314
    $
5,563,498
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these balance sheets.
               
 

 
95


 
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30,
 
   
2007
   
2006
 
   
(In thousands)
 
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $
211,214
    $
246,927
 
Adjustments to reconcile net income to net cash from operating activities-
         
Provision for depreciation
   
56,094
     
45,775
 
Amortization of regulatory assets
   
110,253
     
99,832
 
Deferral of new regulatory assets
    (114,708 )     (101,283 )
Deferred rents and lease market valuation liability
    (46,327 )     (55,166 )
Deferred income taxes and investment tax credits, net
    (40,964 )     (9,513 )
Accrued compensation and retirement benefits
   
2,575
     
2,681
 
Pension trust contribution
    (24,800 )    
-
 
Decrease (increase) in operating assets-
               
Receivables
   
140,359
     
189
 
Prepayments and other current assets
   
661
      (387 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (143,210 )    
29,681
 
Accrued taxes
   
4,545
      (14,588 )
Accrued interest
   
22,360
     
12,427
 
Electric service prepayment programs
    (16,819 )     (13,623 )
Other
   
2,996
      (5,270 )
Net cash provided from operating activities
   
164,229
     
237,682
 
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
   
247,424
     
-
 
Equity contributions from parent
   
12,756
     
-
 
Redemptions and Repayments-
               
Long-term debt
    (223,555 )     (118,295 )
Short-term borrowings, net
    (59,328 )     (58,819 )
Dividend Payments-
               
Common stock
    (304,000 )     (118,000 )
Net cash used for financing activities
    (326,703 )     (295,114 )
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (100,583 )     (89,771 )
Loan repayments from (loans to) associated companies, net
    (13,863 )    
108,034
 
Collection of principal on long-term notes receivable
   
220,974
     
-
 
Redemption of lessor notes
   
56,177
     
44,553
 
Other
    (218 )     (5,368 )
Net cash provided from investing activities
   
162,487
     
57,448
 
                 
Net increase in cash and cash equivalents
   
13
     
16
 
Cash and cash equivalents at beginning of period
   
221
     
207
 
Cash and cash equivalents at end of period
  $
234
    $
223
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.
               
 

96


 
 

 


Report of Independent Registered Public Accounting Firm









To the Stockholder and Board of
Directors of The Cleveland Electric Illuminating Company:

We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 11 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007

97



THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


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

Results of Operations

Net income in the first nine months of 2007 decreased to $211 million from $247 million in the same period of 2006. The decrease resulted primarily from higher purchased power costs and other operating costs, partially offset by higher revenues.

Revenues

Revenues increased by $63 million or 5% in the first nine months of 2007 compared to the same period of 2006 primarily due to higher retail generation and wholesale revenues.  Retail generation revenues increased by $38 million due to increased KWH sales and higher composite unit prices for all customer classes.  More weather-related usage in the first nine months of 2007 compared to the same period of 2006 primarily contributed to the increased KWH sales in the residential and commercial sectors (cooling degree days increased 19% and heating degree days increased 15% from the same period in 2006).  Increased KWH sales in the industrial sector reflected a slight decrease in customer shopping.

Wholesale generation revenues increased by $17 million in the first nine months of 2007 compared to the corresponding period of 2006.  The increase was primarily due to higher unit prices for PSA sales. CEI sells power from its leasehold interests in the Bruce Mansfield plant to FGCO.

Increases in retail generation sales and revenues in the first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables:

Retail Generation KWH Sales
 
Increase
 
         
Residential
   
4.3
%
Commercial
   
6.0
%
Industrial
   
1.2
%
    Increase in Retail Generation Sales
   
3.2
%


Retail Generation Revenues
 
Increase
 
   
(In millions)
 
Residential
 
$
9
 
Commercial
   
15
 
Industrial
   
14
 
Increase in Generation Revenues
 
$
38
 

Revenues from distribution throughput increased by $5 million in the first nine months of 2007 compared to the same period of 2006 primarily due to increased KWH deliveries to all customer classes, partially offset by lower composite unit prices for the industrial sector. Increased KWH deliveries were primarily a result of the weather in 2007 as described above.

Changes in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables.

Distribution KWH Deliveries
 
Increase
 
         
Residential
   
4.5
%
Commercial
   
3.7
%
Industrial
   
0.7
%
Increase in Distribution Deliveries
   
2.5
%


98



Distribution Revenues
 
Increase
(Decrease)
 
   
(In millions)
 
Residential
 
$
6
 
Commercial
   
6
 
Industrial
   
(7
)
 Net Increase in Distribution Revenues
 
$
5
 


Expenses

Total expenses increased by $82 million in the first nine months of 2007 compared to the same period of 2006. The following table presents the change from the prior year by expense category:

Expenses  - Changes
 
Increase
(Decrease)
 
   
(in millions)
 
Purchased power costs
 
$
44
 
Other operating costs
   
20
 
Provision for depreciation
   
10
 
Amortization of regulatory assets
   
11
 
Deferral of new regulatory assets
   
(13
)
General taxes
   
10
 
Net Increase in Expenses
 
$
82
 


Higher purchased power costs in the first nine months of 2007 compared to the corresponding period of 2006 primarily reflect higher unit prices associated with the PSA with FES and an increase in purchased power to meet CEI’s higher retail generation sales requirements. Higher other operating costs in the first nine months of 2007 compared to the same period of 2006 reflect increases in MISO transmission related expenses due to increased transmission volumes. The increased depreciation in the first nine months of 2007 is primarily due to property additions since the third quarter of 2006 and the absence of a credit adjustment in the second quarter of 2006 that related to prior periods ($6.5 million pre-tax, $4 million net of tax).

The increased amortization of regulatory assets in the first nine months of 2007 compared to the corresponding period of 2006 was due to increased transition cost amortization reflecting the higher KWH sales discussed above.  The increase in the deferral of new regulatory assets in the first nine months of 2007 reflect a higher level of MISO costs that were deferred in excess of transmission revenues recognized and increased distribution cost deferrals under CEI’s RCP. General taxes were higher in the first nine months of 2007 compared to the same period of 2006 primarily as a result of higher real and personal property taxes.

Other Expense

Other expense increased by $37 million in the first nine months of 2007 compared to the corresponding period of 2006 primarily due to lower investment income on associated company notes receivable in 2007. CEI received principal repayments from FGCO and NGC subsequent to the third quarter of 2006 on notes receivable related to the generation asset transfers.

Legal Proceedings

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

New Accounting Standards and Interpretations

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



99



 
THE TOLEDO EDISON COMPANY
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2007
   
2006
   
2007
   
2006
 
STATEMENTS OF INCOME
 
(In thousands)
 
                         
REVENUES:
                       
Electric sales
  $
261,736
    $
254,979
    $
728,429
    $
684,992
 
Excise tax collections
   
7,926
     
7,858
     
22,026
     
21,420
 
Total revenues
   
269,662
     
262,837
     
750,455
     
706,412
 
                                 
EXPENSES:
                               
Fuel
   
8,784
     
9,399
     
29,392
     
28,799
 
Purchased power
   
112,502
     
112,389
     
304,947
     
268,468
 
Nuclear operating costs
   
17,705
     
19,252
     
53,272
     
54,450
 
Other operating costs
   
47,212
     
44,253
     
136,297
     
124,396
 
Provision for depreciation
   
9,231
     
8,386
     
27,475
     
24,723
 
Amortization of regulatory assets
   
30,460
     
27,336
     
79,284
     
73,909
 
Deferral of new regulatory assets
    (15,645 )     (15,340 )     (47,373 )     (43,186 )
General taxes
   
11,912
     
13,406
     
38,646
     
38,590
 
Total expenses
   
222,161
     
219,081
     
621,940
     
570,149
 
                                 
OPERATING INCOME
   
47,501
     
43,756
     
128,515
     
136,263
 
                                 
OTHER INCOME (EXPENSE):
                               
Investment income
   
6,721
     
9,724
     
21,255
     
28,449
 
Miscellaneous expense
    (2,153 )     (1,933 )     (7,309 )     (6,543 )
Interest expense
    (8,786 )     (4,940 )     (25,205 )     (13,614 )
Capitalized interest
   
220
     
277
     
467
     
835
 
Total other income (expense)
    (3,998 )    
3,128
      (10,792 )    
9,127
 
                                 
INCOME BEFORE INCOME TAXES
   
43,503
     
46,884
     
117,723
     
145,390
 
                                 
INCOME TAXES
   
18,435
     
17,706
     
44,924
     
54,834
 
                                 
NET INCOME
   
25,068
     
29,178
     
72,799
     
90,556
 
                                 
PREFERRED STOCK DIVIDEND REQUIREMENTS
   
-
     
1,161
     
-
     
3,597
 
                                 
EARNINGS ON COMMON STOCK
  $
25,068
    $
28,017
    $
72,799
    $
86,959
 
                                 
STATEMENTS OF COMPREHENSIVE INCOME
                               
                                 
NET INCOME
  $
25,068
    $
29,178
    $
72,799
    $
90,556
 
                                 
OTHER COMPREHENSIVE INCOME:
                               
Pension and other postretirement benefits
   
574
     
-
     
1,720
     
-
 
Change in unrealized gain on available for sale securities
   
1,946
     
1,379
     
1,656
     
432
 
Other comprehensive income
   
2,520
     
1,379
     
3,376
     
432
 
Income tax expense related to other
                               
comprehensive income
   
902
     
498
     
1,193
     
156
 
Other comprehensive income, net of tax
   
1,618
     
881
     
2,183
     
276
 
                                 
TOTAL COMPREHENSIVE INCOME
  $
26,686
    $
30,059
    $
74,982
    $
90,832
 
                                 
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of
 
these statements.
                               

100


 

THE TOLEDO EDISON COMPANY     
 
             
CONSOLIDATED BALANCE SHEETS     
 
(Unaudited)     
 
   
September 30,
   
December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $
20
    $
22
 
Receivables-
               
Customers
   
335
     
772
 
Associated companies
   
31,180
     
13,940
 
Other (less accumulated provisions of $518,000 and $430,000,
         
respectively, for uncollectible accounts)
   
3,600
     
3,831
 
Notes receivable from associated companies
   
79,188
     
100,545
 
Prepayments and other
   
627
     
851
 
     
114,950
     
119,961
 
UTILITY PLANT:
               
In service
   
913,191
     
894,888
 
Less - Accumulated provision for depreciation
   
406,949
     
394,225
 
     
506,242
     
500,663
 
Construction work in progress
   
26,665
     
16,479
 
     
532,907
     
517,142
 
OTHER PROPERTY AND INVESTMENTS:
               
Investment in lessor notes
   
154,674
     
169,493
 
Long-term notes receivable from associated companies
   
92,700
     
128,858
 
Nuclear plant decommissioning trusts
   
64,598
     
61,094
 
Other
   
1,778
     
1,871
 
     
313,750
     
361,316
 
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
   
500,576
     
500,576
 
Regulatory assets
   
214,896
     
247,595
 
Pension assets
   
5,962
     
-
 
Property taxes
   
22,010
     
22,010
 
Other
   
29,427
     
30,042
 
     
772,871
     
800,223
 
    $
1,734,478
    $
1,798,642
 
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $
55,134
    $
30,000
 
Accounts payable-
               
Associated companies
   
103,250
     
84,884
 
Other
   
4,043
     
4,021
 
Notes payable to associated companies
   
190,758
     
153,567
 
Accrued taxes
   
52,865
     
47,318
 
Lease market valuation liability
   
23,655
     
24,600
 
Other
   
32,906
     
37,551
 
     
462,611
     
381,941
 
CAPITALIZATION:
               
Common stockholder's equity-
               
Common stock, $5 par value, authorized 60,000,000 shares -
         
29,402,054 shares outstanding
   
147,010
     
147,010
 
Other paid-in capital
   
172,949
     
166,786
 
Accumulated other comprehensive loss
    (34,621 )     (36,804 )
Retained earnings
   
157,139
     
204,423
 
Total common stockholder's equity
   
442,477
     
481,415
 
Long-term debt
   
303,220
     
358,281
 
     
745,697
     
839,696
 
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
   
141,813
     
161,024
 
Accumulated deferred investment tax credits
   
10,389
     
11,014
 
Lease market valuation liability
   
192,774
     
218,800
 
Retirement benefits
   
77,275
     
77,843
 
Asset retirement obligations
   
27,899
     
26,543
 
Deferred revenues - electric service programs
   
15,896
     
23,546
 
Other
   
60,124
     
58,235
 
     
526,170
     
577,005
 
COMMITMENTS AND CONTINGENCIES (Note 10)
               
    $
1,734,478
    $
1,798,642
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are  
 an integral part of these balance sheets.
               

101



THE TOLEDO EDISON COMPANY
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30,
 
   
2007
   
2006
 
   
(In thousands)
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $
72,799
    $
90,556
 
Adjustments to reconcile net income to net cash from operating activities-
               
Provision for depreciation
   
27,475
     
24,723
 
Amortization of regulatory assets
   
79,284
     
73,909
 
Deferral of new regulatory assets
    (47,373 )     (43,186 )
Deferred rents and lease market valuation liability
    (23,551 )     (27,114 )
Deferred income taxes and investment tax credits, net
    (32,530 )     (28,603 )
Accrued compensation and retirement benefits
   
3,493
     
2,766
 
Pension trust contribution
    (7,659 )    
-
 
Decrease (increase) in operating assets-
               
Receivables
    (13,368 )     (25,069 )
Prepayments and other current assets
   
224
      (75 )
Increase (decrease) in operating liabilities-
               
Accounts payable
   
9,515
     
1,102
 
Accrued taxes
   
7,463
     
3,458
 
Accrued interest
   
3,444
      (709 )
Electric service prepayment programs
    (7,650 )     (6,744 )
  Other
   
1,953
     
1,716
 
Net cash provided from operating activities
   
73,519
     
66,730
 
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Short-term borrowings, net
   
37,191
     
113,886
 
Equity contribution from parent
   
6,125
     
-
 
Redemptions and Repayments-
               
Preferred stock
   
-
      (30,000 )
Long-term debt
    (30,014 )     (53,650 )
Dividend Payments-
               
Common stock
    (120,000 )     (50,000 )
Preferred stock
   
-
      (3,597 )
Net cash used for financing activities
    (106,698 )     (23,361 )
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (41,573 )     (45,661 )
Loan repayments from (loans to) associated companies, net
   
21,438
      (61,549 )
Collection of principal on long-term notes receivable
   
36,077
     
53,766
 
Redemption of lessor notes
   
14,819
     
9,275
 
Sales of investment securities held in trusts
   
39,260
     
50,255
 
Purchases of investment securities held in trusts
    (39,557 )     (50,433 )
  Other
   
2,713
     
983
 
Net cash provided from (used for) investing activities
   
33,177
      (43,364 )
                 
Net increase (decrease) in cash and cash equivalents
    (2 )    
5
 
Cash and cash equivalents at beginning of period
   
22
     
15
 
Cash and cash equivalents at end of period
  $
20
    $
20
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an
 
integral part of these statements.
               

102



 



Report of Independent Registered Public Accounting Firm









To the Stockholder and Board of
Directors of The Toledo Edison Company:

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006 as discussed in Note 3 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007


103



THE TOLEDO EDISON COMPANY

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


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

Results of Operations

Earnings on common stock in the first nine months of 2007 decreased to $73 million from $87 million in the same period of 2006. The decrease resulted primarily from higher purchased power and other operating costs and increased interest expense, partially offset by higher electric sales revenues.

Revenues

Revenues increased $44 million or 6.2% in the first nine months of 2007 compared to the same period of 2006 primarily due to increases in retail generation revenues ($24 million), wholesale generation revenues ($11 million) and distribution revenues ($6 million). Retail generation revenues increased in the first nine months of 2007 due to higher average prices and increased sales volume across all customer classes compared to the same period of 2006. Average prices increased primarily due to higher composite unit prices for retail generation shopping customers returning to TE. The increase in sales volume also reflects increased weather-related usage in the first nine months of 2007 (heating and cooling degree days increased 15.2% and 7.2%, respectively, from the same period of 2006).

The increase in wholesale revenues resulted primarily from increased KWH sales to associated companies and higher unit prices. TE sells KWH from its leasehold interests in Beaver Valley Unit 2 and the Bruce Mansfield Plant to CEI and FGCO, respectively.

Increases in retail electric generation KWH sales and revenues in the first nine months of 2007 from the same period of 2006 are summarized in the following tables.

Retail Generation KWH Sales
 
Increase
 
         
Residential
 
 
8.0
%
Commercial
   
3.1
%
Industrial
 
 
1.0
%
    Increase in Retail Generation  Sales
 
 
3.1
%

Retail Generation Revenues
 
Increase
 
   
(In millions)
 
Residential
 
$
8
 
Commercial
   
4
 
Industrial
   
12
 
    Increase in Retail Generation Revenues
 
$
24
 

Revenues from distribution throughput increased by $6 million in the first nine months of 2007 compared to the same period in 2006 due to higher KWH deliveries to all customer sectors, partially offset by lower average unit prices for industrial customers. The higher KWH deliveries to residential and commercial customers in the first nine months of 2007 reflected the weather impacts described above.

Changes in distribution KWH deliveries and revenues in the first nine months of 2007 from the same period of 2006 are summarized in the following tables.

Distribution KWH Deliveries
 
Increase
 
         
Residential
 
 
5.5
%
Commercial
 
 
2.6
%
Industrial
 
 
1.1
%
    Increase in Distribution Deliveries
 
 
2.5
%


104



Distribution Revenues
 
Increase (Decrease)
 
   
(In millions)
 
   Residential
 
$
7
 
   Commercial
 
 
3
 
   Industrial
   
(4
)
   Net Increase in Distribution Revenues
 
$
6
 

Expenses

Total expenses increased $52 million in the first nine months of 2007 from the same period of 2006. The following table presents changes from the prior year by expense category:

Expenses – Changes
 
Increase (Decrease)
 
   
(In millions)
 
Purchased power costs
 
$
37
 
Nuclear operating costs
   
(1
)
Other operating costs
   
12
 
Provision for depreciation
   
3
 
Amortization of regulatory assets
   
5
 
Deferral of new regulatory assets
   
(4
)
Net increase in expenses
 
$
52
 

Higher purchased power costs in the first nine months of 2007 compared to the same period of 2006 reflected higher unit prices associated with the PSA with FES and an increase in KWH purchases to meet the higher retail generation sales requirements. Other operating costs were higher due to an $11 million increase in MISO network transmission expenses in the first nine months of 2007. Depreciation expense was higher due to an increase in depreciable property, reflecting plant additions since the third quarter of 2006. Higher amortization of regulatory assets was due to increased amortization of transition cost deferrals ($3 million) and MISO transmission deferrals ($2 million). The change in the deferral of new regulatory assets was primarily due to increased deferrals for MISO transmission expenses ($7 million) and RCP distribution costs ($4 million), partially offset by lower RCP fuel cost deferrals ($5 million).

Other Expense

Other expense increased $20 million in the first nine months of 2007 compared to the same period of 2006 primarily due to lower investment income and higher interest expense. The decrease in investment income resulted primarily from the principal repayments since the third quarter of 2006 on notes receivable from associated companies. The higher interest expense is principally associated with new long-term debt issued in November 2006.

Legal Proceedings

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

New Accounting Standards and Interpretations

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



105


 
JERSEY CENTRAL POWER & LIGHT COMPANY
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2007
   
2006
   
2007
   
2006
 
STATEMENTS OF INCOME
 
(In thousands)       
 
                         
REVENUES:
                       
Electric sales
  $
1,018,049
    $
895,389
    $
2,457,146
    $
2,059,499
 
Excise tax collections
   
15,168
     
15,679
     
39,849
     
38,845
 
Total revenues
   
1,033,217
     
911,068
     
2,496,995
     
2,098,344
 
                                 
EXPENSES:
                               
Purchased power
   
654,418
     
546,125
     
1,505,420
     
1,204,880
 
Other operating costs
   
87,010
     
90,578
     
236,225
     
245,711
 
Provision for depreciation
   
22,032
     
21,099
     
63,867
     
62,553
 
Amortization of regulatory assets
   
107,837
     
78,052
     
296,955
     
210,323
 
General taxes
   
18,631
     
19,187
     
51,183
     
49,691
 
Total expenses
   
889,928
     
755,041
     
2,153,650
     
1,773,158
 
                                 
OPERATING INCOME
   
143,289
     
156,027
     
343,345
     
325,186
 
                                 
OTHER INCOME (EXPENSE):
                               
Miscellaneous income
   
2,967
     
2,091
     
9,266
     
8,162
 
Interest expense
    (24,666 )     (21,437 )     (71,576 )     (62,420 )
Capitalized interest
   
483
     
1,004
     
1,559
     
2,933
 
Total other expense
    (21,216 )     (18,342 )     (60,751 )     (51,325 )
                                 
INCOME BEFORE INCOME TAXES
   
122,073
     
137,685
     
282,594
     
273,861
 
                                 
INCOME TAXES
   
46,275
     
58,316
     
118,637
     
120,506
 
                                 
NET INCOME
   
75,798
     
79,369
     
163,957
     
153,355
 
                                 
PREFERRED STOCK DIVIDEND REQUIREMENTS
   
-
     
917
     
-
     
1,167
 
                                 
EARNINGS ON COMMON STOCK
  $
75,798
    $
78,452
    $
163,957
    $
152,188
 
                                 
STATEMENTS OF COMPREHENSIVE INCOME
                               
                                 
NET INCOME
  $
75,798
    $
79,369
    $
163,957
    $
153,355
 
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    (2,114 )    
-
      (6,344 )    
-
 
Unrealized gain on derivative hedges
   
69
     
100
     
235
     
207
 
Other comprehensive income (loss)
    (2,045 )    
100
      (6,109 )    
207
 
Income tax expense (benefit) related to other
                               
  comprehensive income
    (994 )    
41
      (2,973 )    
84
 
Other comprehensive income (loss), net of tax
    (1,051 )    
59
      (3,136 )    
123
 
                                 
TOTAL COMPREHENSIVE INCOME
  $
74,747
    $
79,428
    $
160,821
    $
153,478
 
                                 
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral
 
 part of these statements.
                               

106



JERSEY CENTRAL POWER & LIGHT COMPANY
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
   
December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $
77
    $
41
 
Receivables-
               
Customers (less accumulated provisions of $4,821,000 and $3,524,000,
               
respectively, for uncollectible accounts)
   
396,700
     
254,046
 
Associated companies
   
369
     
11,574
 
Other (less accumulated provisions of $718,000 and $204,000,
               
respectively, for uncollectible accounts)
   
62,235
     
40,023
 
Notes receivable - associated companies
   
22,734
     
24,456
 
Materials and supplies, at average cost
   
1,915
     
2,043
 
Prepaid taxes
   
41,670
     
13,333
 
  Other
   
14,080
     
18,076
 
     
539,780
     
363,592
 
UTILITY PLANT:
               
In service
   
4,122,325
     
4,029,070
 
Less - Accumulated provision for depreciation
   
1,490,846
     
1,473,159
 
     
2,631,479
     
2,555,911
 
Construction work in progress
   
84,199
     
78,728
 
     
2,715,678
     
2,634,639
 
OTHER PROPERTY AND INVESTMENTS:
               
Nuclear fuel disposal trust
   
172,278
     
171,045
 
Nuclear plant decommissioning trusts
   
177,217
     
164,108
 
  Other
   
2,075
     
2,047
 
     
351,570
     
337,200
 
DEFERRED CHARGES AND OTHER ASSETS:
               
Regulatory assets
   
1,757,516
     
2,152,332
 
Goodwill
   
1,826,190
     
1,962,361
 
Pension assets
   
43,183
     
14,660
 
  Other
   
15,124
     
17,781
 
     
3,642,013
     
4,147,134
 
    $
7,249,041
    $
7,482,565
 
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $
26,680
    $
32,683
 
Short-term borrowings-
               
Associated companies
   
155,395
     
186,540
 
Accounts payable-
               
Associated companies
   
22,399
     
80,426
 
Other
   
211,788
     
160,359
 
Accrued taxes
   
25,793
     
1,451
 
Accrued interest
   
27,520
     
14,458
 
Cash collateral from suppliers
   
68
     
32,311
 
  Other
   
85,746
     
96,139
 
     
555,389
     
604,367
 
CAPITALIZATION:
               
Common stockholder's equity-
               
Common stock, $10 par value, authorized 16,000,000 shares-
               
14,421,637 and 15,009,335 shares outstanding, respectively
   
144,216
     
150,093
 
Other paid-in capital
   
2,657,775
     
2,908,279
 
Accumulated other comprehensive loss
    (47,390 )     (44,254 )
Retained earnings
   
266,342
     
145,480
 
Total common stockholder's equity
   
3,020,943
     
3,159,598
 
Long-term debt and other long-term obligations
   
1,568,296
     
1,320,341
 
     
4,589,239
     
4,479,939
 
NONCURRENT LIABILITIES:
               
Power purchase contract loss liability
   
872,305
     
1,182,108
 
Accumulated deferred income taxes
   
762,782
     
803,944
 
Nuclear fuel disposal costs
   
190,524
     
183,533
 
Asset retirement obligations
   
88,334
     
84,446
 
  Other
   
190,468
     
144,228
 
     
2,104,413
     
2,398,259
 
COMMITMENTS AND CONTINGENCIES (Note 10)
               
    $
7,249,041
    $
7,482,565
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an
         
integral part of these balance sheets.
               

107


JERSEY CENTRAL POWER & LIGHT COMPANY
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30,
 
   
2007
   
2006
 
   
(In thousands)
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $
163,957
    $
153,355
 
Adjustments to reconcile net income to net cash from operating activities-
               
Provision for depreciation
   
63,867
     
62,553
 
Amortization of regulatory assets
   
296,955
     
210,323
 
Deferred purchased power and other costs
    (157,201 )     (213,621 )
Deferred income taxes and investment tax credits, net
    (23,786 )    
25,217
 
Accrued compensation and retirement benefits
    (17,543 )     (4,196 )
Cash collateral returned to suppliers
    (32,243 )     (108,926 )
Pension trust contribution
    (17,800 )    
-
 
Decrease (increase) in operating assets-
               
Receivables
    (153,660 )     (50,337 )
Materials and supplies
   
127
     
86
 
Prepaid taxes
    (28,337 )     (29,923 )
Other current assets
   
2,079
      (2,118 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (6,598 )     (8,131 )
Accrued taxes
   
29,318
      (16,992 )
Accrued interest
   
13,062
     
16,296
 
Tax collections payable
    (12,478 )     (10,316 )
Other
    (7,440 )     (4,814 )
Net cash provided from operating activities
   
112,279
     
18,456
 
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
   
549,999
     
382,400
 
Equity contribution from parent
   
4,636
     
-
 
Redemptions and Repayments-
               
Long-term debt
    (324,256 )     (162,157 )
Short-term borrowings, net
    (31,145 )     (44,162 )
Common stock
    (125,000 )    
-
 
Preferred stock
   
-
      (13,461 )
Dividend Payments-
               
Common stock
    (43,000 )     (45,000 )
Preferred stock
   
-
      (354 )
Net cash provided from financing activities
   
31,234
     
117,266
 
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (144,668 )     (123,540 )
Loan repayments from (loans to) associated companies, net
   
1,722
      (8,638 )
Sales of investment securities held in trusts
   
169,649
     
169,676
 
Purchases of investment securities held in trusts
    (171,820 )     (171,847 )
  Other
   
1,640
      (1,417 )
Net cash used for investing activities
    (143,477 )     (135,766 )
                 
Net increase (decrease) in cash and cash equivalents
   
36
      (44 )
Cash and cash equivalents at beginning of period
   
41
     
102
 
Cash and cash equivalents at end of period
  $
77
    $
58
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
 
are an integral part of these statements.
               

108


 



Report of Independent Registered Public Accounting Firm









To the Stockholder and Board of
Directors of Jersey Central Power & Light Company:

We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, as discussed in Note 3 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007


109



JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


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

Results of Operations

Earnings on common stock increased to $164 million in the first nine months of 2007 compared to $152 million for the same period in 2006. The increase was primarily due to higher revenues and lower other operating costs, partially offset by higher purchased power costs and increased amortization of regulatory assets.

Revenues

Revenues increased $399 million or 19% in the first nine months of 2007 compared with the same period of 2006. Retail and wholesale generation revenues increased by $250 million and $49 million, respectively, in the first nine months of 2007.

Retail generation revenues from all customer classes increased in the first nine months of 2007 compared to 2006 due to higher unit prices resulting from the BGS auctions effective June 1, 2006 and June 1, 2007 and higher retail generation KWH sales. Sales volume increased as a result of weather conditions in the first nine months of 2007 (heating degree days were 15.8% higher than the first nine months of 2006 and cooling degree days decreased slightly). Industrial generation KWH sales declined in the first nine months of 2007 from the same period in 2006 due to an increase in customer shopping.

Wholesale generation revenues increased $49 million in the first nine months of 2007 due to higher market prices, partially offset by a 3.0% decrease in sales volume compared with the first nine months of 2006.

Changes in retail generation KWH sales and revenues by customer class in the first nine months of 2007 compared to the same period of 2006 are summarized in the following table:

Retail Generation KWH Sales
 
Increase
(Decrease)
 
         
Residential
 
 
2.3
 %
Commercial
   
1.6
 %
Industrial
   
(7.0
)%
Net Increase in Generation Sales
 
 
1.6
 %

Retail Generation Revenues
 
Increase
 
   
(In millions)
 
Residential
 
$
145
 
Commercial
   
100
 
Industrial
   
5
 
Increase in Generation Revenues
 
$
250
 

Distribution revenues increased in the first nine months of 2007 compared to the same period of 2006 due to higher composite unit prices and increased KWH deliveries, reflecting the weather impacts described above. The higher unit prices resulted from an NUGC rate increase effective in December 2006.

Changes in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables.

Distribution KWH Deliveries
 
Increase
 
           
Residential
     
2.3
%
Commercial
     
3.3
%
Industrial
     
1.1
%
Increase in Distribution Deliveries
     
2.6
%

110



Distribution Revenues
   
Increase
 
     
(In millions)
Residential
   
$
35
 
Commercial
     
38
 
Industrial
     
6
 
Increase in Distribution Revenues
   
$
79
 

The higher revenues for the first nine months of 2007 also included $20 million of increased revenues resulting from the August 2006 securitization of deferred costs associated with JCP&L’s BGS supply.

Expenses

Total expenses increased by $380 million in the first nine months of 2007 as compared to the same period of 2006. The following table presents changes from the prior year by expense category:

 Expenses  - Changes
 
 
Increase
(Decrease)
 
  
 
 
(In millions)
Purchased power costs
 
 
$
300
 
Other operating costs
 
 
 
(9
)
Provision for depreciation
 
 
 
1
 
Amortization of regulatory assets
 
 
 
87
 
General Taxes
 
 
 
1
 
Net increase in expenses
 
 
$
380
 

The increase in purchased power costs primarily reflected higher unit prices resulting from the June 2006 and June 2007 BGS auctions. Other operating costs decreased $9 million in the first nine months of 2007 primarily due to lower employee benefit costs. Amortization of regulatory assets increased $87 million in the first nine months of 2007 due to higher cost recovery associated with the December 2006 NUGC rate increase.

Other Expenses

Other expenses increased $9 million in the first nine months of 2007 from the same period in 2006 primarily due to interest expense associated with JCP&L’s $550 million issuance of Senior Notes in May 2007.

Legal Proceedings

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

New Accounting Standards and Interpretations

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



111



 
METROPOLITAN EDISON COMPANY
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2007
   
2006
   
2007
   
2006
 
   
(In thousands)
 
                         
REVENUES:
                       
Electric sales
  $
391,083
    $
337,750
    $
1,087,460
    $
898,320
 
Gross receipts tax collections
   
19,524
     
18,431
     
55,146
     
51,293
 
Total revenues
   
410,607
     
356,181
     
1,142,606
     
949,613
 
                                 
EXPENSES:
                               
Purchased power
   
209,842
     
184,508
     
584,249
     
487,465
 
Other operating costs
   
106,104
     
108,740
     
315,227
     
229,394
 
Provision for depreciation
   
11,154
     
10,197
     
31,969
     
31,390
 
Amortization of regulatory assets
   
36,853
     
33,560
     
101,965
     
89,277
 
Deferral of new regulatory assets
    (19,151 )     (44,213 )     (93,772 )     (89,794 )
General taxes
   
21,986
     
21,362
     
63,208
     
60,578
 
Total expenses
   
366,788
     
314,154
     
1,002,846
     
808,310
 
                                 
OPERATING INCOME
   
43,819
     
42,027
     
139,760
     
141,303
 
                                 
OTHER INCOME (EXPENSE):
                               
Interest income
   
7,239
     
8,053
     
22,740
     
25,767
 
Miscellaneous income
   
1,366
     
1,477
     
3,973
     
5,881
 
Interest expense
    (13,291 )     (12,291 )     (38,471 )     (35,546 )
Capitalized interest
   
292
     
355
     
940
     
966
 
Total other expense
    (4,394 )     (2,406 )     (10,818 )     (2,932 )
                                 
INCOME BEFORE INCOME TAXES
   
39,425
     
39,621
     
128,942
     
138,371
 
                                 
INCOME TAXES
   
14,737
     
14,631
     
53,145
     
55,390
 
                                 
NET INCOME
   
24,688
     
24,990
     
75,797
     
82,981
 
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    (1,452 )    
-
      (4,357 )    
-
 
Unrealized gain on derivative hedges
   
83
     
83
     
251
     
251
 
Other comprehensive income (loss)
    (1,369 )    
83
      (4,106 )    
251
 
Income tax expense (benefit) related to other
                               
  comprehensive income
    (693 )    
34
      (2,078 )    
104
 
Other comprehensive income (loss), net of tax
    (676 )    
49
      (2,028 )    
147
 
                                 
TOTAL COMPREHENSIVE INCOME
  $
24,012
    $
25,039
    $
73,769
    $
83,128
 
                                 
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of
 
these statements.
                               

112


METROPOLITAN EDISON COMPANY
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
   
December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $
126
    $
130
 
Receivables-
               
Customers (less accumulated provisions of $4,740,000 and $4,153,000,
               
respectively, for uncollectible accounts)
   
154,622
     
127,084
 
Associated companies
   
23,728
     
3,604
 
Other
   
18,043
     
8,107
 
Notes receivable from associated companies
   
34,620
     
31,109
 
Prepaid taxes
   
5,755
     
13,533
 
  Other
   
1,976
     
1,424
 
     
238,870
     
184,991
 
UTILITY PLANT:
               
In service
   
1,976,453
     
1,920,563
 
Less - Accumulated provision for depreciation
   
755,018
     
739,719
 
     
1,221,435
     
1,180,844
 
Construction work in progress
   
21,124
     
18,466
 
     
1,242,559
     
1,199,310
 
OTHER PROPERTY AND INVESTMENTS:
               
Nuclear plant decommissioning trusts
   
290,349
     
269,777
 
  Other
   
1,360
     
1,362
 
     
291,709
     
271,139
 
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
   
426,368
     
496,129
 
Regulatory assets
   
458,566
     
409,095
 
Pension assets
   
26,239
     
7,261
 
  Other
   
38,653
     
46,354
 
     
949,826
     
958,839
 
    $
2,722,964
    $
2,614,279
 
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $
-
    $
50,000
 
Short-term borrowings-
               
Associated companies
   
254,826
     
141,501
 
Other
   
80,000
     
-
 
Accounts payable-
               
Associated companies
   
24,807
     
100,232
 
Other
   
55,186
     
59,077
 
Accrued taxes
   
9,033
     
11,300
 
Accrued interest
   
7,343
     
7,496
 
  Other
   
26,960
     
22,825
 
     
458,155
     
392,431
 
CAPITALIZATION:
               
Common stockholder's equity-
               
Common stock, without par value, authorized 900,000 shares-
               
859,500 shares outstanding
   
1,207,634
     
1,276,075
 
Accumulated other comprehensive loss
    (28,544 )     (26,516 )
Accumulated deficit
    (158,873 )     (234,620 )
Total common stockholder's equity
   
1,020,217
     
1,014,939
 
Long-term debt and other long-term obligations
   
542,100
     
542,009
 
     
1,562,317
     
1,556,948
 
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
   
393,169
     
387,456
 
Accumulated deferred investment tax credits
   
8,623
     
9,244
 
Nuclear fuel disposal costs
   
43,038
     
41,459
 
Asset retirement obligations
   
158,302
     
151,107
 
Retirement benefits
   
15,830
     
19,522
 
  Other
   
83,530
     
56,112
 
     
702,492
     
664,900
 
COMMITMENTS AND CONTINGENCIES (Note 10)
               
    $
2,722,964
    $
2,614,279
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part
 
of these balance sheets.
               

113



METROPOLITAN EDISON COMPANY     
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS     
 
(Unaudited)     
 
             
   
Nine Months Ended   
 
   
September 30,   
 
   
2007
   
2006
 
   
(In thousands)   
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $
75,797
    $
82,981
 
Adjustments to reconcile net income to net cash from operating activities-
         
Provision for depreciation
   
31,969
     
31,390
 
Amortization of regulatory assets
   
101,965
     
89,277
 
Deferred costs recoverable as regulatory assets
    (53,276 )     (53,406 )
Deferral of new regulatory assets
    (93,772 )     (89,794 )
Deferred income taxes and investment tax credits, net
   
20,514
     
27,895
 
Accrued compensation and retirement benefits
    (14,404 )     (6,007 )
Cash collateral
   
1,650
      (21,500 )
Pension trust contribution
    (11,012 )    
-
 
Decrease (increase) in operating assets-
               
Receivables
    (57,599 )    
27,680
 
Prepayments and other current assets
   
7,227
      (8,247 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (79,316 )     (1,553 )
Accrued taxes
   
1,787
      (10,451 )
Accrued interest
    (153 )     (308 )
Other
   
5,436
      (1,777 )
Net cash provided from (used for) operating activities
    (63,187 )    
66,180
 
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Short-term borrowings, net
   
193,324
     
116,624
 
Equity contribution from parent
   
1,237
       
Redemptions and Repayments-
               
Long-term debt
    (50,000 )     (100,000 )
Dividend Payments-
               
Common Stock
   
-
      (5,000 )
Net cash provided from financing activities
   
144,561
     
11,624
 
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (74,812 )     (65,332 )
Sales of investment securities held in trusts
   
153,943
     
146,841
 
Purchases of investment securities held in trusts
    (156,623 )     (153,953 )
Loans to associated companies, net
    (3,511 )     (4,853 )
  Other
    (375 )     (494 )
Net cash used for investing activities
    (81,378 )     (77,791 )
                 
Net increase (decrease) in cash and cash equivalents
    (4 )    
13
 
Cash and cash equivalents at beginning of period
   
130
     
120
 
Cash and cash equivalents at end of period
  $
126
    $
133
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
 
part of these statements.
               

114



 



Report of Independent Registered Public Accounting Firm









To the Stockholder and Board of
Directors of Metropolitan Edison Company:

We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007


115



METROPOLITAN EDISON COMPANY

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


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

Results of Operations

Net income for the first nine months of 2007 decreased to $76 million from $83 million in the first nine months of 2006. The decrease was primarily due to higher purchased power costs and other operating costs, partially offset by higher revenues.

Revenues

Revenues increased by $193 million, or 20.3%, in the first nine months of 2007 compared with the first nine months of 2006. This increase was primarily due to higher distribution revenues and wholesale generation revenues.

In the first nine months of 2007, retail generation revenues increased by $19 million primarily due to higher KWH sales in all customer sectors. The increase in retail generation revenues in the residential and commercial sectors primarily resulted from higher weather-related usage in the first nine months of 2007 as compared to the same period of 2006 (heating degree days increased by 17.1% and cooling degree days increased by 7.1%).

Increases in retail generation sales and revenues in the first nine months of 2007 compared to the same period of 2006 are summarized in the following tables:

Retail Generation KWH Sales
 
Increase
 
         
Residential
 
 
5.6
 %
Commercial
 
 
4.0
 %
Industrial
 
 
0.6
 %
    Increase in Retail Generation Sales
 
 
3.6
 %

Retail Generation Revenues
 
Increase
 
   
(In millions)
 
Residential
 
 $
11
 
Commercial
 
 
8
 
Industrial
 
 
-
 
    Increase in Retail Generation Revenues
 
 $
19
 

Wholesale revenues increased by $107 million in the first nine months of 2007 compared with the same period of 2006 due to Met-Ed selling additional available power into the PJM market beginning in January 2007.

Revenues from distribution throughput increased by $55 million in the first nine months of 2007 compared to the same period in 2006. The increase was due to higher KWH deliveries, reflecting the effect of the weather discussed above, and an increase in composite unit prices resulting from the January 2007 PPUC authorization to increase transmission rates, partially offset by a decrease in distribution rates.

Increases in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the same period of 2006 are summarized in the following tables:

Distribution KWH Deliveries
 
Increase
 
         
Residential
 
 
5.6
 %
Commercial
 
 
4.0
 %
Industrial
 
 
0.2
 %
    Increase in Distribution Deliveries
 
 
3.5
 %
       

116



Distribution Revenues
 
Increase
 
   
(In millions)
 
Residential
 
 $
38
 
Commercial
 
 
5
 
Industrial
 
 
12
 
    Increase in Distribution Revenues
 
 $
55
 

PJM transmission revenues increased by $18 million in the first nine months of 2007 as a result of higher transmission volumes and additional PJM auction revenue rights, compared to the prior year period. Met-Ed defers the difference between revenue from its transmission rider and transmission costs incurred, resulting in no material effect to current period earnings.

Expenses

Total expenses increased by $195 million in the first nine months of 2007 compared to the same period of 2006. The following table presents changes from the prior year by expense category:

Expenses – Changes
 
Increase
(Decrease)
 
   
(In millions)
 
Purchased power costs
 
$
97
 
Other operating costs
 
 
86
 
Amortization of regulatory assets
 
 
13
 
Deferral of new regulatory assets
   
(4
)
General taxes
   
3
 
Net increase in expenses
 
$
195
 

Purchased power costs increased in the first nine months of 2007 by $97 million due to higher volumes purchased to source higher generation sales, combined with higher composite unit costs. Other operating costs increased in the first nine months of 2007 primarily due to higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above ($83 million) and increased expenses ($3 million) related to Met-Ed’s customer assistance programs.

Amortization of regulatory assets increased in the first nine months of 2007 primarily due to the recovery (through Met-Ed’s transmission rider discussed above) of certain transmission costs deferred in 2006 and the amortization of the Saxton nuclear research facility’s decommissioning costs as authorized by the PPUC in January 2007. The deferral of new regulatory assets increased in the first nine months of 2007 primarily due to the deferral of previously expensed Saxton decommissioning costs of $15 million (see Legal Proceedings), partially offset by lower PJM transmission deferrals.

In the first nine months of 2007, general taxes increased primarily due to higher gross receipts taxes.

On October 1, 2007, Met-Ed sold 100% of its interest in York Haven Power Company for $5 million. The sale is subject to regulatory accounting and will not have a material impact on Met-Ed’s earnings in the fourth quarter of 2007.

Legal Proceedings

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

New Accounting Standards and Interpretations

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





117


 

 
PENNSYLVANIA ELECTRIC COMPANY
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2007
   
2006
   
2007
   
2006
 
   
(In thousands)
 
REVENUES:
                       
Electric sales
  $
336,798
    $
287,633
    $
991,769
    $
813,860
 
Gross receipts tax collections
   
16,637
     
15,787
     
48,989
     
46,311
 
Total revenues
   
353,435
     
303,420
     
1,040,758
     
860,171
 
                                 
EXPENSES:
                               
Purchased power
   
203,247
     
165,921
     
588,583
     
474,437
 
Other operating costs
   
51,571
     
65,165
     
169,299
     
151,640
 
Provision for depreciation
   
12,566
     
11,828
     
36,678
     
36,269
 
Amortization of regulatory assets, net
   
20,861
     
3,825
     
32,648
     
19,804
 
General taxes
   
19,433
     
18,593
     
57,634
     
55,440
 
Total expenses
   
307,678
     
265,332
     
884,842
     
737,590
 
                                 
OPERATING INCOME
   
45,757
     
38,088
     
155,916
     
122,581
 
                                 
OTHER INCOME (EXPENSE):
                               
Miscellaneous income
   
1,483
     
2,182
     
5,035
     
6,179
 
Interest expense
    (14,017 )     (11,840 )     (38,426 )     (33,975 )
Capitalized interest
   
194
     
363
     
737
     
1,132
 
Total other expense
    (12,340 )     (9,295 )     (32,654 )     (26,664 )
                                 
INCOME BEFORE INCOME TAXES
   
33,417
     
28,793
     
123,262
     
95,917
 
                                 
INCOME TAXES
   
10,387
     
10,733
     
49,025
     
39,251
 
                                 
NET INCOME
   
23,030
     
18,060
     
74,237
     
56,666
 
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    (2,825 )    
-
      (8,475 )    
-
 
Unrealized gain on derivative hedges
   
16
     
17
     
49
     
49
 
Change in unrealized gain on available for sale securities
   
10
     
14
      (6 )     (4 )
Other comprehensive income (loss)
    (2,799 )    
31
      (8,432 )    
45
 
Income tax expense (benefit) related to other
                               
  comprehensive income
    (1,294 )    
13
      (3,894 )    
20
 
Other comprehensive income (loss), net of tax
    (1,505 )    
18
      (4,538 )    
25
 
                                 
TOTAL COMPREHENSIVE INCOME
  $
21,525
    $
18,078
    $
69,699
    $
56,691
 
                                 
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral
         
part of these statements.
                               

118

 

PENNSYLVANIA ELECTRIC COMPANY
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
   
December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $
38
    $
44
 
Receivables-
               
Customers (less accumulated provisions of $4,094,000 and $3,814,000
               
respectively, for uncollectible accounts)
   
138,007
     
126,639
 
Associated companies
   
21,872
     
49,728
 
Other
   
19,047
     
16,367
 
Notes receivable from associated companies
   
17,170
     
19,548
 
Prepaid taxes
   
7,268
     
3,016
 
  Other
   
1,724
     
1,220
 
     
205,126
     
216,562
 
UTILITY PLANT:
               
In service
   
2,188,553
     
2,141,324
 
Less - Accumulated provision for depreciation
   
824,141
     
809,028
 
     
1,364,412
     
1,332,296
 
Construction work in progress
   
26,835
     
22,124
 
     
1,391,247
     
1,354,420
 
OTHER PROPERTY AND INVESTMENTS:
               
Nuclear plant decommissioning trusts
   
137,896
     
125,216
 
Non-utility generation trusts
   
147,745
     
99,814
 
  Other
   
531
     
531
 
     
286,172
     
225,561
 
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
   
777,904
     
860,716
 
Pension assets
   
34,484
     
11,474
 
  Other
   
34,371
     
36,059
 
     
846,759
     
908,249
 
    $
2,729,304
    $
2,704,792
 
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Short-term borrowings-
               
Associated companies
  $
187,313
    $
199,231
 
Other
   
65,000
     
-
 
Accounts payable-
               
Associated companies
   
107,666
     
92,020
 
Other
   
46,283
     
47,629
 
Accrued taxes
   
3,091
     
11,670
 
Accrued interest
   
13,832
     
7,224
 
  Other
   
24,481
     
21,178
 
     
447,666
     
378,952
 
CAPITALIZATION:
               
Common stockholder's equity-
               
Common stock, $20 par value, authorized 5,400,000 shares-
               
4,427,577 and 5,290,596 shares outstanding, respectively
   
88,552
     
105,812
 
Other paid-in capital
   
925,229
     
1,189,434
 
Accumulated other comprehensive loss
    (11,731 )     (7,193 )
Retained earnings
   
39,195
     
90,005
 
Total common stockholder's equity
   
1,041,245
     
1,378,058
 
Long-term debt and other long-term obligations
   
777,020
     
477,304
 
     
1,818,265
     
1,855,362
 
NONCURRENT LIABILITIES:
               
Regulatory liabilities
   
77,441
     
96,151
 
Asset retirement obligations
   
80,589
     
76,924
 
Accumulated deferred income taxes
   
183,598
     
193,662
 
Retirement benefits
   
51,289
     
50,328
 
Other
   
70,456
     
53,413
 
     
463,373
     
470,478
 
COMMITMENTS AND CONTINGENCIES (Note 10)
               
    $
2,729,304
    $
2,704,792
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
 
integral part of these balance sheets.
               

119



PENNSYLVANIA ELECTRIC COMPANY
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30,
 
   
2007
   
2006
 
   
(In thousands)   
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $
74,237
    $
56,666
 
Adjustments to reconcile net income to net cash from operating activities
               
Provision for depreciation
   
36,678
     
36,269
 
Amortization of regulatory assets
   
43,601
     
40,854
 
Deferral of new regulatory assets
    (10,953 )     (21,050 )
Deferred costs recoverable as regulatory assets
    (54,228 )     (56,272 )
Deferred income taxes and investment tax credits, net
   
8,065
     
14,518
 
Accrued compensation and retirement benefits
    (16,032 )    
2,807
 
Cash collateral
   
50
     
-
 
Pension trust contribution
    (13,436 )    
-
 
Decrease (increase) in operating assets
               
Receivables
   
13,809
     
22,719
 
Prepayments and other current assets
    (4,757 )     (2,977 )
Increase (decrease) in operating liabilities
               
Accounts payable
   
14,299
      (15,555 )
Accrued taxes
    (6,191 )     (9,841 )
Accrued interest
   
6,608
     
5,468
 
Other
   
2,653
      (2,188 )
Net cash provided from operating activities
   
94,403
     
71,418
 
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing
               
Long-Term Debt
   
297,149
     
-
 
Short-term borrowings, net
   
53,082
     
21,278
 
Equity contribution from parent
   
1,261
     
-
 
Redemptions and Repayments
               
Common Stock
    (200,000 )    
-
 
Dividend Payments
               
Common Stock
    (125,000 )     (5,000 )
Net cash provided from financing activities
   
26,492
     
16,278
 
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (70,076 )     (81,228 )
Loan repayments from (loans to) associated companies, net
   
2,378
      (2,976 )
Sales of investment securities held in trust
   
94,292
     
83,601
 
Purchases of investment securities held in trust
    (144,167 )     (83,601 )
Other, net
    (3,328 )     (3,480 )
Net cash used for investing activities
    (120,901 )     (87,684 )
                 
Net increase (decrease) in cash and cash equivalents
    (6 )    
12
 
Cash and cash equivalents at beginning of period
   
44
     
35
 
Cash and cash equivalents at end of period
  $
38
    $
47
 
                 
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
 
integral part of these statements.
               

120



 



Report of Independent Registered Public Accounting Firm









To the Stockholder and Board of
Directors of Pennsylvania Electric Company:

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007


121



PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


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

Results of Operations

In the first nine months of 2007, net income increased to $74 million, compared to $57 million in the first nine months of 2006. The increase in net income was primarily due to higher revenues, partially offset by increased purchased power costs and other operating costs.

Revenues

Revenues increased by $181 million, or 21.0%, in the first nine months of 2007 compared to the same period last year. The increase was primarily due to higher distribution revenues and wholesale generation revenues.

Retail generation revenues increased $15 million for the first nine months of 2007 primarily due to higher KWH sales to all customer classes. The increase in retail generation revenues in the residential and commercial sectors was primarily impacted by weather in the first nine months of 2007 (heating degree days increased 11.0% and cooling degree days increased 14.1% as compared to the same time period of 2006).

Increases in retail generation sales and revenues in first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables:

Retail Generation KWH Sales
 
Increase
 
 
 
 
 
Residential
 
 
3.6
 %
Commercial
 
 
3.6
 %
Industrial
 
 
0.1
 %
    Increase in Retail Generation Sales
 
 
2.5
 %

       
Retail Generation Revenues
 
Increase
 
   
(In millions)
 
Residential
 
$
6
 
Commercial
 
 
8
 
Industrial
 
 
1
 
    Increase in Retail Generation Revenues
 
$
15
 

Wholesale revenues increased $123 million in the first nine months of 2007, compared with the same period of 2006 due to Penelec selling additional available power into the PJM market beginning in January 2007.

Revenues from distribution throughput increased $37 million in the first nine months of 2007 due to higher KWH deliveries to residential and commercial customers reflecting the effect of the weather discussed above and an increase in composite unit prices for residential and industrial customers resulting from a January 2007 PPUC authorization to increase transmission rates, partially offset by a decrease in distribution rates.

Changes in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the same period in 2006 are summarized in the following tables:

 
 
Increase
 
Distribution KWH Deliveries
 
(Decrease)
 
 
 
 
 
Residential
 
 
3.6
 %
Commercial
 
 
3.6
 %
Industrial
 
 
(1.3
)%
    Net Increase in Distribution Deliveries
 
 
1.9
 %
 
 
 
122


 
   
Increase
 
Distribution  Revenues
 
(Decrease)
 
   
(In millions)
 
Residential
 
$
37
 
Commercial
 
 
(4
)
Industrial
 
 
4
 
    Net Increase in Distribution Revenues
 
$
37
 

PJM transmission revenues increased by $6 million in the first nine months of 2007 compared to the same period in 2006 due to higher transmission volumes and additional PJM auction revenue rights in 2007. Penelec defers the difference between revenue from its transmission rider and transmission costs incurred, with no material effect to current period earnings.

Expenses

Total expenses increased by $147 million in the first nine months of 2007 compared with the same period in 2006. The following table presents changes from the prior year by expense category:

     
Expenses - Changes
 
Increase
   
(In millions)
Purchased power costs
 
$
114
Other operating costs
 
 
18
Amortization of regulatory assets, net
 
 
13
General taxes
   
2
Increase in Expenses
 
$
147

Purchased power costs increased by $114 million, or 24.1% in the first nine months of 2007, compared to the same period of 2006. The increase was due primarily to higher volumes purchased to source higher retail and wholesale generation sales combined with higher composite unit costs. Other operating costs increased by $18 million in the first nine months of 2007 principally due to higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above.

Net amortization of regulatory assets increased in the first nine months of 2007 primarily due to the recovery (through Penelec’s transmission rider discussed above) of certain transmission costs deferred in 2006 and lower transmission cost deferrals in 2007, partially offset by the deferral of new regulatory assets for previously expensed decommissioning costs of $12 million associated with the Saxton nuclear research facility as authorized by the PPUC in January 2007 (see Legal Proceedings).

General taxes increased $2 million in the first nine months of 2007 as compared to 2006, primarily due to higher gross receipts taxes.

Legal Proceedings

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

New Accounting Standards and Interpretations

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


123



COMBINED MANAGEMENT’S DISCUSSION
AND ANALYSIS OF REGISTRANT SUBSIDIARIES


The following is a combined presentation of certain disclosures referenced in Management’s Narrative Analysis of Results of Operations of FES and the Companies. This information should be read in conjunction with (i) FES’ and the Companies’ respective Consolidated Financial Statements and Management’s Narrative Analysis of Results of Operations; (ii) the Notes to Consolidated Financial Statements as they relate to FES and the Companies; and (iii) the Companies’ respective 2006 Annual Reports on Form 10-K.

Regulatory Matters (Applicable to each of the Companies)

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

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

The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $227 million as of September 30, 2007 (JCP&L - $93 million, Met-Ed - $43 million and Penelec - $91 million). Regulatory assets not earning a current return will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets by company:

 
 
September 30,
 
December 31,
 
Increase
 
Regulatory Assets*
 
2007
 
2006
 
(Decrease)
 
 
 
(In millions)
 
OE
 
$
717
 
$
741
 
$
(24
)
CEI
 
 
856
 
 
855
 
 
1
 
TE
 
 
215
 
 
248
 
 
(33
)
JCP&L
 
 
1,758
 
 
2,152
 
 
(394
)
Met-Ed
 
 
459
 
 
409
 
 
50
 
ATSI
 
 
42
 
 
36
 
 
6
 
Total
 
$
4,047
 
$
4,441
 
$
(394
)

*
Penelec had net regulatory liabilities of approximately $77 million
and $96 million as of September 30, 2007 and December 31,
2006, respectively. These net regulatory liabilities are included in
Other Non-current Liabilities on the Consolidated Balance Sheets.


124



Ohio (Applicable to OE, CEI and TE)

The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2007 through 2010:

Amortization
 
 
 
 
 
 
 
 Total
 
Period
 
OE
 
CEI
 
TE
 
 Ohio
 
 
 
(In millions)
 
2007
 
$
176
 
$
108
 
$
92
 
$
376
 
2008
 
 
209
 
 
126
 
 
113
 
 
448
 
2009
 
 
-
 
 
217
 
 
-
 
 
217
 
2010
 
 
-
 
 
269
 
 
-
 
 
269
 
Total Amortization
 
$
385
 
$
720
 
$
205
 
$
1,310
 

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.

125



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.

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

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.

126



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.

127



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.

New Jersey (Applicable to JCP&L)

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 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;

 · Reduce air pollution related to energy use;

128



 · 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.

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

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, 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.

Environmental Matters

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

Clean Air Act Compliance (Applicable to FES)

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

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006 alleging violations to various sections of the Clean Air Act. FES 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.

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

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.

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National Ambient Air Quality Standards (Applicable to FES)

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). FES’ 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 FES operates affected facilities.

Mercury Emissions (Applicable to FES)

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, 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. FES' future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FES operates affected facilities.

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. FES 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, FES will be disadvantaged if these model rules were implemented as proposed because FES’ 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, FES’ only coal-fired Pennsylvania power plant, until 2015, if at all.

W. H. Sammis Plant (Applicable to FES, OE and Penn)

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).

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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 (Applicable to FES)

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 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.

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.

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

Clean Water Act (Applicable to FES)

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. On January 26, 2007, the 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. FES 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 (Applicable to FES and each of the Companies)

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.

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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.

Other Legal Proceedings

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 material items not otherwise discussed above are described below.

Power Outages and Related Litigation (Applicable to FES and each of the Companies)

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.

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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.

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 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.

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Nuclear Plant Matters (Applicable to FES)

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 (Applicable to OE and JCP&L)

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.

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.

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

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. FES and the Companies are currently evaluating the impact of this Statement on their 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. FES and the Companies are currently evaluating the impact of this Statement on their 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 additional paid-in capital (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 impact on FES’ or the Companies’ 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. FES and the Companies are currently evaluating the impact of this FSP on their financial statements but it is not expected to have a material impact.



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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Information” in Item 2 above.

ITEM 4. CONTROLS AND PROCEDURES

(a)    EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The applicable registrant's chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that the applicable registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to the registrant and its consolidated subsidiaries by others within those entities.

(b)    CHANGES IN INTERNAL CONTROLS

During the quarter ended September 30, 2007, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1.         LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 10 and 11 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A.      RISK FACTORS

See Item 1A RISK FACTORS in Part I of the Form 10-K for the year ended December 31, 2006 for a discussion of the risk factors of FirstEnergy and the subsidiary registrants. For the quarter ended September 30, 2007, there have been no material changes to these risk factors.

ITEM 2.         UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

(c)   FirstEnergy

The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock.

   
Period
 
   
July 1-31,
 
August 1-31,
 
September 1-30,
 
Third
 
   
2007
 
2007
 
2007
 
Quarter
 
Total Number of Shares Purchased (a)
 
29,656
 
83,448
 
253,701
 
366,805
 
Average Price Paid per Share
 
$66.00
 
$62.95
 
$61.85
 
$62.44
 
Total Number of Shares Purchased
                 
As Part of Publicly Announced Plans
                 
or Programs (b)
   
-
   
-
   
-
   
-
 
Maximum Number (or Approximate Dollar
                         
Value) of Shares that May Yet Be
                         
Purchased Under the Plans or Programs
   
1,629,890
   
1,629,890
   
1,629,890
   
1,629,890
 
                           

(a)
Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its Executive and Director Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the Executive and Director Incentive Compensation Plan and shares purchased as part of publicly announced plans.
   
(b)
FirstEnergy publicly announced, on January 30, 2007, a plan to repurchase up to 16 million shares of its common stock through June 30, 2008. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock under this plan through an accelerated share repurchase program with an affiliate of Morgan Stanley and Co., Incorporated at an initial price of $62.63 per share.


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ITEM 6.         EXHIBITS

        Exhibit
        Number
     
     
         
        FirstEnergy
     
 
    10.1
Amendment to Agreement for Engineering, Procurement and Construction of Air Quality Control Systems by and between FirstEnergy Generation Corp. and Bechtel Power Corporation dated September 14, 2007 (Form 8-K dated September 18, 2007)*
   
 
    10.2
FirstEnergy Corp. Executive Deferred Compensation Plan as amended September 18, 2007
(Form 8-K dated September 21, 2007)
   
 
    10.3
FirstEnergy Corp. Supplemental Executive Retirement Plan as amended September 18, 2007
(Form 8-K dated September 21, 2007)
   
 
    12
Fixed charge ratios
   
 
    15
Letter from independent registered public accounting firm
   
 
    31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
   
 
    31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
   
 
    32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
   
FES
   
 
12
Fixed charge ratios
 
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
 
OE
   
 
12
Fixed charge ratios
 
 
15
Letter from independent registered public accounting firm
 
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
 
CEI
   
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
 
TE
   
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
 
JCP&L
   
 
12
Fixed charge ratios
 
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
 
Met-Ed
 
 
12
Fixed charge ratios
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
Penelec
 
 
4.1
Form of Pennsylvania Electric Company 6.05% Senior Notes due 2017 (incorporated by reference to a Form 8-K dated August 31, 2007)
 
10.1
Registration Rights Agreement, dated as of August 30, 2007, among Pennsylvania Electric Company and Citigroup Global Markets Inc., Lehman Brothers Inc. and Scotia Capital (USA) Inc., as representatives of the several initial purchasers named in the Purchase Agreement (incorporated by reference to a Form 8-K dated August 31, 2007)
 
12
Fixed charge ratios
 
15
Letter from independent registered public accounting firm
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

* Confidential treatment has been requested for certain portions of the Exhibit. Omitted portions have been filed separately with the SEC.

Pursuant to reporting requirements of respective financings, FirstEnergy, FES, OE, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.

140


SIGNATURES



Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


October 31, 2007





 
FIRSTENERGY CORP.
 
Registrant
   
 
FIRSTENERGY SOLUTIONS CORP.
 
Registrant
   
 
OHIO EDISON COMPANY
 
Registrant
   
 
THE CLEVELAND ELECTRIC
 
ILLUMINATING COMPANY
 
Registrant
   
 
THE TOLEDO EDISON COMPANY
 
Registrant
   
 
METROPOLITAN EDISON COMPANY
 
Registrant
   
 
PENNSYLVANIA ELECTRIC COMPANY
 
Registrant



 
/s/  Harvey L. Wagner
 
Harvey L. Wagner
 
Vice President, Controller
 
and Chief Accounting Officer



 
JERSEY CENTRAL POWER & LIGHT COMPANY
 
Registrant
   
   
   
 
/s/  Paulette R. Chatman
 
Paulette R. Chatman
 
Controller
 
(Principal Accounting Officer)
 
 

141