10-K 1 form10k_2007.htm FORM 10-K DATED DECEMBER 31, 2007 form10k_2007.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K

(Mark One)
[X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 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
 

 
 

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

       
Name of Each Exchange
Registrant
 
Title of Each Class
 
on Which Registered
         
FirstEnergy Corp.
 
Common Stock, $0.10 par value
 
New York Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes (X)  No (  )
FirstEnergy Corp.
Yes  (  ) No (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 if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

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

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

Yes (X)  No (  )
FirstEnergy Corp., Ohio Edison Company and Pennsylvania Electric Company
Yes (  )  No (X)
FirstEnergy Solutions Corp., The Toledo Edison Company,  Metropolitan Edison Company, The Cleveland Electric Illuminating Company and Jersey Central Power & Light Company
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

(  )
FirstEnergy Corp.
(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 the registrant 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. (Check One):

Large Accelerated Filer
(X)
 
FirstEnergy Corp.
Accelerated Filer
(  )
 
N/A
Non-accelerated Filer (do not check if a Smaller Reporting Company)
(X)
FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company

Smaller Reporting Company
(  )
N/A

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

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

 
 

 

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and ask price of such common equity, as of the last business day of the registrants' most recently completed second fiscal quarter.

FirstEnergy Corp., $19,606,108,911 as of June 30, 2007; and for all other registrants, none.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

   
OUTSTANDING
CLASS
 
AS OF FEBRUARY 28, 2008
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.

Documents incorporated by reference (to the extent indicated herein):

   
PART OF FORM 10-K INTO WHICH
DOCUMENT
 
DOCUMENT IS INCORPORATED
     
FirstEnergy Corp. Annual Report to Stockholders for
   
the fiscal year ended December 31, 2007
 
Part II
     
Proxy Statement for 2008 Annual Meeting of Stockholders
   
to be held May 20, 2008
 
Part III

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

OMISSION OF CERTAIN INFORMATION

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

 
 

 

Forward-Looking Statements: This Form 10-K 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, revised environmental requirements, including possible GHG emission regulations,
 
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 ability to operate at, or near full capacity,
 
the changing market conditions that could affect the value of assets held in the registrants' nuclear decommissioning trusts, pension trusts and other trust funds,
 
the ability to comply with applicable state and federal reliability standards,
 
the ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives),
 
the ability to improve electric commodity margins and to experience growth in the distribution business,
 
the ability to access the public securities and other capital markets and the cost of such capital,
 
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.

 
 

 

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
Centerior
Centerior Energy Corporation, former parent of CEI and TE, which merged with OE to form
   FirstEnergy on November 8, 1997
Companies
OE, CEI, TE, Penn, 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 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
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
   
The following abbreviations and acronyms are used to identify frequently used terms in this report:
   
AEP
American Electric Power Company, Inc.
ALJ
Administrative Law Judge
AQC
Air Quality Control
BGS
Basic Generation Service
BPJ
Best Professional Judgment
CAA
Clean Air Act
CAIR
Clean Air Interstate Rule
CAMR
Clean Air Mercury Rule
CAVR
Clean Air Visibility Rule
CBP
Competitive Bid Process
CO2
Carbon Dioxide
CTC
Competitive Transition Charge
DFI
Demand for Information
DOE
United States Department of Energy
DOJ
United States Department of Justice
DRA
Division of Ratepayer Advocate
ECAR
East Central Area Reliability Coordination Agreement
EIS
Energy Independence Strategy
EMP
Energy Master Plan
EPA
United States Environmental Protection Agency
EPACT
Energy Policy Act of 2005
EPRI
Electric Power Research Institute
ERO
Electric Reliability Organization
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
FMB
First Mortgage Bonds
GAAP
Accounting Principles Generally Accepted in the United States

 
i

 

GLOSSARY OF TERMS Cont'd.

GHG
Greenhouse Gases
ISO
Independent System Operator
kv Kilovolts
KWH
Kilowatt-hours
LOC
Letter of Credit
LTIP
Long-term Incentive Program
MEIUG
Met-Ed Industrial Users Group
MISO
Midwest Independent Transmission System Operator, Inc.
Moody's
Moody's Investors Service, Inc.
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
OVEC
Ohio Valley Electric Corporation
PICA
Penelec Industrial Customer Alliance
PJM
PJM Interconnection L. L. C.
PLR
Provider of Last Resort; an electric utility's obligation to provide generation service to customers
   whose alternative supplier fails to deliver service
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
RECB
Regional Expansion Criteria and Benefits
RFP
Request for Proposal
ROP
Reactor Oversight Process
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
SCR
Selective Catalytic Reduction
SEC
U.S. Securities and Exchange Commission
SECA
Seams Elimination Cost Adjustment
SFAS
Statement of Financial Accounting Standards
SFAS 71
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 101
SFAS No. 101, "Accounting for Discontinuation of Application of SFAS 71"
SIP
State Implementation Plan(s) Under the Clean Air Act
SNCR
Selective Non-Catalytic Reduction
SO2
Sulfur Dioxide
TEBSA
Termobarranquila S.A. Empresa de Servicios Publicos
TMI-1
Three Mile Island Unit 1
TMI-2
Three Mile Island Unit 2

 
ii

 

FORM 10-K TABLE OF CONTENTS
 
Page
Part I
 
Item 1.    Business
 
The Company
1-2
Generation Asset Transfers
2
Sale and Leaseback Transaction
3
Utility Regulation
3-12
Regulatory Accounting
4
Reliability Initiatives
4
PUCO Rate Matters
5-6
PPUC Rate Matters
7-8
NJBPU Rate Matters
8-9
FERC Rate Matters
10-12
Capital Requirements
13-14
                        Nuclear Operating Licenses                                                                            
15
Nuclear Regulation
15
Nuclear Insurance
15
Environmental Matters
16
Fuel Supply
16-19
System Capacity and Reserves
19
Regional Reliability
20
Competition
20
Research and Development
21
Executive Officers
21
Employees
23
FirstEnergy Website
23
   
Item 1A.   Risk Factors
23-33
   
Item 1B.    Unresolved Staff Comments
33
   
Item 2.      Properties
33-35
   
Item 3.      Legal Proceedings
35
   
Item 4.      Submission of Matters to a Vote of Security Holders
35
   
Part II
 
    Item 5.      Market for Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
35-36
   
Item 6.      Selected Financial Data
36
   
Item 7.      Management's Discussion and Analysis of Financial Condition and Results of Operations
36
   
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk
36
   
Item 8.      Financial Statements and Supplementary Data
36
   
Item 9.      Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
36
   
Item 9A.   Controls and Procedures
36-37
   
Item 9A(T).  Controls and Procedures
37
   
Item 9B.    Other Information
37
   
Part III
 
Item 10.    Directors, Executive Officers and Corporate Governance
37-38
   
Item 11.    Executive Compensation
38
   
Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
38
   
Item 13.    Certain Relationships and Related Transactions, and Director Independence
38
   
Item 14.    Principal Accounting Fees and Services
38
   
Part IV
 
Item 15.    Exhibits, Financial Statement Schedules
39


 
iii

 

PART I
ITEM 1.  BUSINESS

The Company

FirstEnergy Corp. was organized under the laws of the State of Ohio in 1996. 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. FirstEnergy's consolidated revenues are primarily derived from electric service provided by its utility operating subsidiaries and the revenues of its other principal subsidiary, FES. In addition, FirstEnergy holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FirstEnergy Ventures Corp., FENOC, FirstEnergy Securities Transfer Company, GPU Diversified Holdings, LLC, GPU Telecom Services, Inc., GPU Nuclear, Inc. and FESC.

FES was organized under the laws of the State of Ohio in 1997.  FES provides energy-related products and services to wholesale and retail customers in the MISO and PJM markets. FES also owns and operates, through its subsidiary, FGCO, FirstEnergy's fossil and hydroelectric generating facilities and owns, through its subsidiary, NGC, FirstEnergy's nuclear generating facilities (see Generation Asset Transfers below).  FENOC, a separate subsidiary of FirstEnergy, organized under the laws of the State of Ohio in 1998, operates and maintains NGC's nuclear generating facilities. FES purchases the entire generation output of the facilities owned by FGCO and NGC, as well as the output relating to leasehold interests of the Ohio Companies in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service PSAs.

FirstEnergy's generating portfolio includes 14,127 MW (net) of diversified capacity (FES – 13,841 MW and JCP&L – 286 MW). Within FES’ portfolio, approximately 7,469 MW, or 54.0%, consists of coal-fired capacity; 3,945 MW, or 28.5%, consists of nuclear capacity; 1,513 MW, or 10.9%, consists of oil and natural gas peaking units; 451 MW, or 3.3%, consists of hydroelectric capacity; and 463 MW, or 3.3%, consists of capacity from FGCO’s 20.5% entitlement to the generation output owned by the Ohio Valley Electric Corporation. FirstEnergy’s nuclear and non-nuclear facilities are all operated by FENOC and FGCO, respectively, and, except for portions of certain facilities that are subject to the sale and leaseback arrangements with non-affiliates referred to above for which the corresponding output is available to FES through power sale agreements, are all owned directly by NGC and FGCO, respectively. The FES generating assets are concentrated primarily in Ohio, plus the bordering regions of Pennsylvania and Michigan. All FES units are dedicated to MISO except the Beaver Valley Power Station, which is designated as a PJM resource.
 
FES complies with the regulations, orders, policies and practices prescribed by the SEC and the FERC.  NGC and FENOC comply with the regulations, orders, policies and practices prescribed by the NRC.

The Companies' combined service areas encompass approximately 36,100 square miles in Ohio, New Jersey and Pennsylvania. The areas they serve have a combined population of approximately 11.3 million.

OE was organized under the laws of the State of Ohio in 1930 and owns property and does business as an electric public utility in that state. OE engages in the distribution and sale of electric energy to communities in a 7,000 square mile area of central and northeastern Ohio. The area it serves has a population of approximately 2.8 million. OE complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.

OE owns all of Penn's outstanding common stock. Penn was organized under the laws of the Commonwealth of Pennsylvania in 1930 and owns property and does business as an electric public utility in that state. Penn is also authorized to do business in the State of Ohio (see Item 2 Properties). Penn furnishes electric service to communities in a 1,100 square mile area of western Pennsylvania. The area it serves has a population of approximately 0.4 million. Penn complies with the regulations, orders, policies and practices prescribed by the FERC and PPUC.

CEI was organized under the laws of the State of Ohio in 1892 and does business as an electric public utility in that state. CEI engages in the distribution and sale of electric energy in an area of approximately 1,600 square miles in northeastern Ohio. The area it serves has a population of approximately 1.8 million. CEI complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.

TE was organized under the laws of the State of Ohio in 1901 and does business as an electric public utility in that state. TE engages in the distribution and sale of electric energy in an area of approximately 2,300 square miles in northwestern Ohio. The area it serves has a population of approximately 0.8 million. TE complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.

 
1

 

ATSI was organized under the laws of the State of Ohio in 1998. ATSI owns transmission assets that were formerly owned by the Ohio Companies and Penn. ATSI owns and operates major, high-voltage transmission facilities, which consist of approximately 5,821 pole miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV. ATSI is the control area operator for the Ohio Companies and Penn service areas. ATSI plans, operates and maintains the transmission system in accordance with the requirements of the FERC, NERC and other applicable regulatory bodies to provide reliable service to FirstEnergy's customers (see FERC Rate Matters for a discussion of ATSI's participation in MISO).

JCP&L was organized under the laws of the State of New Jersey in 1925 and owns property and does business as an electric public utility in that state. JCP&L provides transmission and distribution services in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.6 million. JCP&L complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and the NJBPU.

Met-Ed was organized under the laws of the Commonwealth of Pennsylvania in 1922 and owns property and does business as an electric public utility in that state. Met-Ed provides transmission and distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million. Met-Ed complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.

Penelec was organized under the laws of the Commonwealth of Pennsylvania in 1919 and owns property and does business as an electric public utility in that state. Penelec provides transmission and distribution services in 17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.6 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, also serves customers in Waverly, New York and its vicinity. Penelec complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.
 
FESC provides legal, financial and other corporate support services to affiliated FirstEnergy companies. Reference is made to Note 16, Segment Information, of the Notes to Consolidated Financial Statements contained in Item 8 for information regarding FirstEnergy's reportable segments.

Generation Asset Transfers

In 2005, the Ohio Companies and Penn transferred their respective undivided ownership interests in FirstEnergy's nuclear and non-nuclear generation assets to NGC and FGCO, respectively. All of the non-nuclear assets were transferred to FGCO under the purchase option terms of a Master Facility Lease between FGCO and the Ohio Companies and Penn, under which FGCO leased, operated and maintained the assets that it now owns. CEI and TE sold their interests in nuclear generation assets at net book value to NGC, while OE and Penn transferred their interests to NGC through an asset spin-off in the form of a dividend. On December 28, 2006, the NRC approved the transfer of ownership in NGC from FirstEnergy to FES. Effective December 31, 2006, NGC is a wholly owned subsidiary of FES and second tier subsidiary of FirstEnergy.  FENOC continues to operate and maintain the nuclear generation assets.

Although the generating plant interests transferred in 2005 did not include leasehold interests of CEI, OE and TE in certain of the plants that are subject to sale and leaseback arrangements entered into in 1987 with non-affiliates, 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. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCO's leasehold interests under its July 13, 2007 Bruce Mansfield Unit 1 sale and leaseback transaction, to a newly formed wholly-owned subsidiary on December 17, 2007.  The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE remain primarily liable on the 1987 leases and related agreements. FGCO remains primarily liable on the 2007 leases and related agreements, and FES remains primarily liable as a guarantor under the related 2007 guarantees, as to the lessors and other parties to the respective agreements.

These transactions above were undertaken pursuant to the Ohio Companies' and Penn's restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer or sale to a separate corporate entity. The transactions essentially completed the divestitures of owned assets contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants. The transfers were intracompany transactions and, therefore, had no impact on our consolidated results.

 
2

 

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.

Utility Regulation

State Regulation

Each of the Companies’ retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the state in which each company operates – in Ohio by the PUCO, in New Jersey by the NJBPU and in Pennsylvania by the PPUC.  In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.

As a competitive retail electric supplier serving retail customers in Michigan, Ohio, Pennsylvania, New Jersey and Maryland, FES is subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES and its public utility affiliates.  In addition, if FES or any of its subsidiaries were to engage in the construction of significant new generation facilities, they would also be subject to state siting authority.

Federal Regulation

With respect to their wholesale and interstate electric operations and rates, the Companies, ATSI, FES, FGCO and NGC are subject to regulation by the FERC. Under the FPA, the FERC regulates rates for interstate sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. The FERC regulations require ATSI, Met-Ed, JCP&L and Penelec to provide open access transmission service at FERC-approved rates, terms and conditions.  Transmission service over ATSI’s facilities is provided by MISO under its open access transmission tariff, and transmission service over Met-Ed’s, JCP&L’s and Penelec’s facilities is provided by PJM under its open access transmission tariff. The FERC also regulates unbundled transmission service to retail customers.

The FERC also regulates the sale of power for resale in interstate commerce by granting authority to public utilities to sell wholesale power at market-based rates upon a showing that the seller cannot exert market power in generation or transmission. FES, FGCO and NGC have been authorized by the FERC to sell wholesale power in interstate commerce and have a market-based tariff on file with the FERC. By virtue of this tariff and authority to sell wholesale power, each company is regulated as a public utility under the FPA.  However, consistent with its historical practice, the FERC has granted FES, FGCO and NGC a waiver from most of the reporting, record-keeping and accounting requirements that typically apply to traditional public utilities.  Along with market-based rate authority, the FERC also granted FES, FGCO and NGC blanket authority to issue securities and assume liabilities under Section 204 of the FPA. As a condition to selling electricity on a wholesale basis at market-based rates, FES, FGCO and NGC, like all other entities granted market-based rate authority, must file electronic quarterly reports with the FERC, listing its sales transactions for the prior quarter.

In August 2005, President Bush signed into law the EPACT, which repealed the PUHCA effective February 2006. The PUHCA imposed financial and operational restrictions on many aspects of FirstEnergy’s business. Some of the PUHCA’s consumer protection authority was transferred to the FERC and state utility commissions.  The EPACT also provides for tax credits for the development of certain clean coal and emissions technologies.

 
 
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The nuclear generating facilities owned and leased by NGC are subject to extensive regulation by the NRC.  The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security and environmental and radiological aspects of those stations. The NRC may modify, suspend or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of the licenses. FENOC is the licensee for these plants and has direct compliance responsibility for NRC matters. FES controls the economic dispatch of NGC’s plants.  See “Nuclear Regulation” below.

Regulatory Accounting

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. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations.

FirstEnergy accounts for the effects of regulation through the application of SFAS 71 to its operating utilities since their rates:

 
are established by a third-party regulator with the authority to set rates that bind customers;

 
are cost-based; and

 
can be charged to and collected from customers.

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

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.

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. The proposed enhancements were divided into two groups:  enhancements that were to be completed in 2004; and enhancements that were to be completed after 2004.  In 2004, FirstEnergy completed all of the enhancements that were recommended for completion in 2004.  Subsequently, FirstEnergy has worked systematically to complete all of the enhancements that were identified for completion after 2004, and FirstEnergy expects to complete this work prior to the summer of 2008.  The FERC and the other affected government agencies and reliability entities may review FirstEnergy's work and, on the basis of any such review, may recommend additional enhancements in the future, which could require additional, material expenditures.


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

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

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

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

PUCO Rate Matters

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 stipulations clarifying certain provisions. Several parties subsequently filed appeals to the Supreme Court of Ohio in connection with certain portions of the approved RCP. 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 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 are expected to be effective on January 1, 2009 for OE and TE, and approximately May 2009 for CEI.  Through December 31, 2007, the deferred fuel costs, including interest, were $111 million, $76 million and $33 million for OE, CEI and TE, respectively.
 
On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses because fuel costs are a component of generation service, not distribution service, and permitting recovery of deferred fuel costs through distribution rates constituted an impermissible subsidy. 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 10, 2007 the Ohio Companies filed an Application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. The Ohio Companies requested the riders to become effective in October 2007 and end in December 2008, subject to reconciliation that would be expected to continue through the first quarter of 2009. On January 9, 2008 the PUCO approved the Ohio Companies' proposed fuel cost rider to recover increased fuel costs to be incurred commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $167 million. The fuel cost rider became effective January 11, 2008 and will be adjusted and reconciled quarterly. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $220 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider, with alternative options for the recovery period ranging from five to twenty-five years. This second application is currently pending before the PUCO.

 
 
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The Ohio Companies recover all MISO transmission and ancillary service related costs incurred through a reconcilable rider that is updated annually on July 1. The riders that became effective on July 1, 2007, 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 riders as filed are necessary, such adjustments, with carrying costs, will be incorporated into the 2008 transmission rider filing.

The Ohio Companies filed an application and rate request for an increase in electric distribution rates 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 average electric bill for most Ohio customers.  The distribution rate increases reflect capital expenditures since the Ohio Companies' last distribution rate proceedings, increases in operation and maintenance expenses and recovery of regulatory assets that were authorized in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of their investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. This amount excludes the recovery of deferred fuel costs, whose recovery is now being sought in a separate proceeding before the PUCO, discussed above. On January 3, 2008, the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 2008. During the evidentiary hearings, the PUCO Staff submitted testimony decreasing their recommended revenue increase to a range of $114 million to $132 million. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred pursuant to the RCP that, if upheld by the PUCO, would result in the write-off of approximately $13 million of interest costs deferred through December 31, 2007 ($0.03 per share of common stock). The PUCO is expected to render its decision during the second or third 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 retail 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. A slice-of-system approach would require the successful bidder to be responsible for supplying a fixed percentage of the utility's total load notwithstanding the customer's classification. 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. Initial and reply comments on the proposal were filed by various parties in September and October, 2007, respectively. The proposal is currently pending before the PUCO.
 
On September 25, 2007, the Ohio Governors 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 default 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 conducted hearings on the bill and received testimony from interested parties, including the Governors Energy Advisor, the Chairman of the PUCO, consumer groups, utility executives and others. Several proposed amendments to the bill were submitted, including those from Ohios 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 and was passed by the Ohio Senate on October 31, 2007. The bill as passed by the Senate is now being considered by the House Public Utilities Committee, which has conducted hearings on the bill. Testimony has been received from interested parties, including the Chairman of the PUCO, consumer groups, utility executives and others. 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.
 
 
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PPUC Rate Matters

Met-Ed and Penelec have been purchasing a portion of their PLR and default service requirements from FES through a partial requirements wholesale power sales agreement and various amendments. 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 sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. 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 their fixed income securities. Based on the PPUCs January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Eds and Penelecs 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 requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Eds non-NUG stranded costs. The order decreased Met-Eds and Penelecs distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Eds and Penelecs 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 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 MEIUGs and PICAs 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 PPUCs determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase.  The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are expected to take place on April 7, 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.

 
 
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As of December 31, 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 $512 million and $55 million, respectively. During the PPUCs annual audit of Met-Eds and Penelecs 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 ALJs initial decision denied Met-Ed's and Penelecs 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. On November 8, 2007, the PPUC issued an order denying any changes in the accounting methodology for NUGs.

On May 2, 2007, Penn filed a plan with the PPUC for the procurement of default service supply from June 2008 through May 2011. The filing proposed multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid default service supply to the residential and commercial classes. The proposal would phase out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class default service would be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers was 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 was either supported, or not opposed, by all parties. On December 20, 2007, the PPUC approved the settlement except for the full requirements tranche approach for residential customers, which was remanded to the ALJ for hearings.  Under the terms of the Settlement Agreement, the default service procurement for small commercial customers will be done with multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the first RFP for small commercial load were received on February 20, 2008. In February 2008, parties filed direct and rebuttal testimony in the remand proceeding for the residential procurement approach. An evidentiary hearing was held on February 26, 2008, and this matter will be presented to the PPUC for its consideration by March 13, 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 and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the "lowest reasonable rate on a long-term basis," the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company's transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. On December 12, 2007, the Pennsylvania Senate passed the Alternative Energy Investment Act which, as amended, provides over $650 million over ten years to implement the Governor's proposal.  The bill was then referred to the House Environmental Resources and Energy Committee where it awaits consideration.  On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy.  The final form of this pending legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

NJBPU Rate Matters

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 December 31, 2007, the accumulated deferred cost balance totaled approximately $322 million.

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

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

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor's Office and the Governor's Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated 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 in 2008. 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 that were submitted in September and October 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.
 
 
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FERC Matters

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. FERC's intent was to eliminate so-called "pancaking" of transmission charges 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 rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or "SECA" during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the first quarter of 2008.

PJM Transmission Rate Design

On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load.  The ALJ issued an initial decision directing that the cost of all PJM transmission facilities, regardless of voltage, 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" or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate.  Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a beneficiary pays basis.  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 PJMs tariff.
 
On May 18, 2007, certain parties filed for rehearing of the FERCs April 19, 2007 order.  On January 31, 2008, the requests for rehearing were denied. The FERCs orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERCs decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission revenue recovery from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the beneficiary pays methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERCs Trial Staff, and was certified by the Presiding Judge. The FERCs action on the settlement agreement is pending. The remaining merchant transmission cost allocation issues will proceed to hearing in May 2008. On February 13, 2008, AEP appealed the FERCs orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission has also appealed these orders.

Post Transition Period Rate Design

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

 
 
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Certain stand-alone transmission companies in MISO 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 under the RECB methodology.  FERC rejected these requests in an order issued January 31, 2008 again maintaining the status quo with respect to allocation of the cost of new transmission facilities in the 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 Super Region that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers.  Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate.  AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008.  On January 31, 2008, FERC issued an order denying the complaint.

Distribution of MISO Network Service Revenues

Effective February 1, 2008, the MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners.  MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation.   This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their unbundled retail load is currently exempt from MISO network service charges. The tariff changes filed with FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements.  Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSIs Attachment O formula under the MISO tariff.

Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3 filing violates the MISO Transmission Owners Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electrics bundled load cannot be charged by MISO for network service.  On January 31, 2008, FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing.  This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement.
 
MISO Ancillary Services Market and Balancing Area Consolidation

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.  This filing would permit load serving entities to purchase their operating reserve requirements in a competitive market.  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 providing an analysis of market power within its footprint and a plan to ensure reliability during the consolidation of balancing areas. MISO made a September 14 filing addressing 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.  FERC conducted a technical conference on certain aspects of the MISO proposal on December 6, 2007, and additional comments were filed by FirstEnergy and other parties on December 19, 2007. FERC action is anticipated in the first quarter of 2008.

 
 
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Duquesne's Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join the MISO. In its filing, Duquesne asked FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2010.  Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM's forward capacity market.  FirstEnergy believes that Duquesne's filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne's proposal. Consequently, on December 4, 2007 and January 3, 2008, FirstEnergy submitted responsive filings that, while conceding Duquesne's rights to exit PJM, contested various aspects of Duquesne's proposal.  FirstEnergy particularly focused on Duquesne's proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne's failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load.  Additionally, FirstEnergy protested Duquesne's failure to identify or address a number of legal, financial or operational issues and uncertainties that may or will result for both PJM and MISO market participants.  Other market participants also submitted filings contesting Duquesne's plans.

On January 17, 2008, the FERC conditionally approved Duquesne's request to exit PJM.  Among other conditions, FERC obligated Duquesne to pay the PJM capacity obligations that had accrued prior to January 17, 2008.  Duquesne was given until February 1, 2008 to provide FERC written notice of its intent to withdraw and Duquesne filed the notice on February 1st.  The FERCs order took notice of the numerous transmission and other issues raised by FirstEnergy and other parties to the proceeding, but did not provide any responsive rulings or other guidance.  Rather, FERC ordered Duquesne to make a compliance filing in forty-five days from the FERC order (or by March 3, 2008) detailing how Duquesne will satisfy its obligations under the PJM Transmission Owner's Agreement. The FERC likewise directed the MISO to submit a compliance filing in forty-five days (or by March 3, 2008) detailing the MISO's plans to integrate Duquesne into the MISO.  Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne's transition into the MISO.  On February 19, 2008, FirstEnergy asked for clarification or rehearing of certain of the matters addressed in FERC's January 17, 2008 Order.

MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load serving entities such as the Ohio Companies, Penn, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009.  The filing would permit MISO to establish the reserve margin requirement for load serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load serving entities in its state. FirstEnergy generally supports the proposal as it promotes a mechanism that will result in long-term commitments from both load-serving entities and resources, including both generation and demand side resources, that are necessary for reliable resource adequacy and planning in the MISO footprint. FirstEnergy does not expect this filing to impose additional supply costs since its load serving entities in MISO are already bound by similar planning reserve requirements established by ReliabilityFirst Corporation. Comments on the filing were filed on January 28, 2008. An effective date of June 1, 2009 was requested in the filing, but MISO has requested FERC approval by the end of the first quarter of 2008.
 
Organized Wholesale Power Markets

On February 21, 2008, the FERC issued a NOPR through which it proposes to adopt new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers.  FirstEnergy has not yet had an opportunity to evaluate the impact of the proposed rule on its operations.


 
 
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Capital Requirements

Anticipated capital expenditures for the Companies, FES and FirstEnergy's other subsidiaries for the years 2008 through 2012 excluding nuclear fuel, are shown in the following table. Such costs include expenditures for the betterment of existing facilities and for the construction of generating capacity, facilities for environmental compliance, transmission lines, distribution lines, substations and other assets.

   
2007
 
Capital Expenditures Forecast
 
   
Actual
 
2008
 
2009-2012
 
Total
 
   
(In millions)
 
OE
  $ 115   $ 112   $ 517   $ 629  
Penn
    27     22     89     111  
CEI
    149     113     457     570  
TE
    60     52     205     257  
JCP&L
    194     173     724     897  
Met-Ed
    102     100     395     495  
Penelec
    97     124     431     555  
ATSI
    44     52     243     295  
FGCO
    461     1,005     1,316     2,321  
NGC
    133     109     910     1,019  
Other subsidiaries
    114     176     279     455  
Total
  $ 1,496   $ 2,038   $ 5,566   $ 7,604  


During the 2008-2012 period, maturities of, and sinking fund requirements for, long-term debt of FirstEnergy and its subsidiaries are:

   
Long-Term Debt Redemption Schedule
 
   
2008
   
2009-2012
 
Total
 
   
(In millions)
 
                 
FirstEnergy
  $ -   $ 1,500   $ 1,500  
OE
    176     3     179  
Penn*
    1     4     5  
CEI**
    125     150     275  
JCP&L
    27     126     153  
Met-Ed
    -     100     100  
Penelec
    -     159     159  
Other subsidiaries
    5     27     32  
Total
  $ 334   $ 2,069   $ 2,403  
                     
* Penn has an additional $63 million due to associated companies in 2009-2012.
 
** CEI has an additional $72 million due to associated companies in 2009-2012.
 

NGC's investments for additional nuclear fuel during the 2008-2012 period are estimated to be approximately $1.4 billion, of which about $132 million applies to 2008. During the same period, its nuclear fuel investments are expected to be reduced by approximately $952 million and $111 million, respectively, as the nuclear fuel is consumed. The following table displays the Companies' operating lease commitments, net of capital trust cash receipts for the 2008-2012 period.

   
Net Operating Lease Commitments
 
   
2008
   
2009-2012
 
Total
 
   
(In millions)
 
                 
FGCO
  $ 173   $ 740   $ 913  
OE
    113     424     537  
CEI*
    (36 )   (160 )   (196 )
TE
    38     150     188  
JCP&L
    9     33     42  
Met-Ed
    4     17     21  
Penelec
    6     21     27  
FESC
    9     34     43  
Total
  $ 316   $ 1,259   $ 1,575  
                     
* Reflects CEI's investment in Shippingport that purchased lease obligations bonds issued on behalf of lessors in Bruce Mansfield Units  1, 2 and 3 sale and leaseback transactions. Effective October 16, 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO.
 

 
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FirstEnergy had approximately $903 million of short-term indebtedness as of December 31, 2007, comprised of $800 million in borrowings under a $2.75 billion revolving line of credit and $103 million of other bank borrowings. Total short-term bank lines of committed credit to FirstEnergy and the Companies as of December 31, 2007 were approximately $3.4 billion.

FirstEnergy, along with certain of its subsidiaries, are party to a $2.75 billion five-year revolving credit facility. 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, 2012, unless the lenders agree, at the request of the Borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each Borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.  The annual facility fee is 0.125%.

The revolving credit facility, combined with an aggregate $550 million (unused as of December 31, 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. Total unused borrowing capability under existing facilities and accounts receivable financing facilities totaled $2.4 billion as of December 31, 2007. An additional source of ongoing cash for FirstEnergy, as a holding company, is cash dividends and return of capital from its subsidiaries. In 2007, the holding company received $1.3 billion of cash dividends on common stock and return of capital from its subsidiaries.

Based on their present plans, the Companies could provide for their cash requirements in 2008 from the following sources: funds to be received from operations; available cash and temporary cash investments as of December 31, 2007 (FirstEnergy's non-utility subsidiaries $128 million and OE $1 million); the issuance of long-term debt (for refunding purposes); funds from capital markets and funds available under revolving credit arrangements.

The extent and type of future financings will depend on the need for external funds as well as market conditions, the maintenance of an appropriate capital structure and the ability of the Companies to comply with coverage requirements in order to issue FMB and preferred stock. The Companies will continue to monitor financial market conditions and, where appropriate, may take advantage of economic opportunities to refund debt to the extent that their financial resources permit.

As of December 31, 2007, the Ohio Companies and Penn had the aggregate capability to issue approximately $3.4 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 $573 million, $442 million and $118 million, respectively, as of December 31, 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.

To the extent that coverage requirements or market conditions restrict the Companies' abilities to issue desired amounts of FMB or preferred stock, the Companies may seek other methods of financing. Such financings could include the sale of preferred and/or preference stock or of such other types of securities as might be authorized by applicable regulatory authorities which would not otherwise be sold and could result in annual interest charges and/or dividend requirements in excess of those that would otherwise be incurred.

As of December 31, 2007, FirstEnergy had approximately $1.0 billion of remaining unused capacity under an existing 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 December 31, 2007, OE had approximately $400 million of capacity remaining unused under a shelf registration for unsecured debt securities filed with the SEC in 2006.

 
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Nuclear Operating Licenses
 
Each of the nuclear units in the FES portfolio operates under a 40-year operating license granted by the NRC. FENOC’s application for operating license extensions for Beaver Valley Units 1 and 2 was accepted by the NRC on November 9, 2007.  Similar applications are expected to be filed for Davis-Besse in 2010 and Perry in 2013. The NRC review process takes approximately two to three years from the docketing of an application. The license extension is for 20 years beyond the current license period. The following table summarizes operating license expiration dates for FES’ nuclear facilities in service.
 
 
Station
 
In-Service Date
Current License
Expiration
Beaver Valley Unit 1
1976
2016
Beaver Valley Unit 2
1987
2027
Perry
1986
2026
Davis-Besse
1977
2017
 
Nuclear Regulation

On March 2, 2007, the NRC returned the Perry Plant to routine agency oversight as a result of its assessment of the corrective actions that FENOC has taken over the last two-and-one-half years. The plant had been operating under heightened NRC oversight since August 2004.  On May 8, 2007, as a result of a "white" Emergency AC Power Systems mitigating systems performance indicator, the NRC notified FENOC that the Perry Plant was being placed in the Regulatory Response Column (Column 2 of the ROP) and additional inspections would be conducted.

On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information (DFI) to FENOC, following FENOCs reply to an April 2, 2007 NRC request for information, about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC "to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commissions 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. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC's Office of Enforcement after it completes the key commitments embodied in the NRC's order. FENOC's compliance with these commitments is subject to future NRC review.

Nuclear Insurance

The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $10.8 billion (assuming 104 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $300 million; and (ii) $10.5 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $100.6 million (but not more than $15 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on its present nuclear ownership and leasehold interests, FirstEnergy's maximum potential assessment under these provisions would be $402.4 million (OE - $34.4 million, NGC - $349.6 million, and TE - $18.4 million) per incident but not more than $60 million (OE - $5.1 million, NGC - $52.1 million, and TE - $2.8 million) in any one year for each incident.

In addition to the public liability insurance provided pursuant to the Price-Anderson Act, FirstEnergy has also obtained insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of Nuclear Electric Insurance Limited (NEIL) which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, FirstEnergy has policies, renewable yearly, corresponding to its nuclear interests, which provide an aggregate indemnity of up to approximately $1.96 billion (OE - $168 million, NGC - $1.70 billion, TE - $89 million) for replacement power costs incurred during an outage after an initial 20-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy's present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $18.4 million (OE - $1.6 million, NGC - $16.0 million, and TE - $0.8 million).


 
15

 
 
 
FirstEnergy is insured under property damage insurance provided by NEIL to the operating company for each plant. Under these arrangements, up to $2.75 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. FirstEnergy pays annual premiums for this coverage and is liable for retrospective assessments of up to approximately $62.5 million (OE - $5.9 million, NGC - $53.4 million, TE - $2.4 million, Met-Ed - $0.4 million, Penelec - $0.2 million and JCP&L - $0.2 million) during a policy year.

FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of FirstEnergy's plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by FirstEnergy's insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs.
 
The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.06 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds.

Environmental Matters

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

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

Clean Air Act Compliance

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

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the Clean Air Act. FirstEnergy has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss an appropriate compliance program and a disagreement regarding 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.
 
 
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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 Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 16, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. FGCO is not required to respond to other claims until the Court rules on this motion to dismiss.
 
On December 18, 2007, the state of New Jersey filed a Clean Air Act citizen suit alleging new source review violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed.  Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction new source review or permitting required by the Clean Air Act's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions.  Although it remains liable for civil or criminal penalties and fines that may be assessed relating to events prior to the sale of the Portland Station in 1999, Met-Ed is indemnified by Sithe Energy against any other liability arising under the CAA whether it arises out of pre-1999 or post-1999 events.

National Ambient Air Quality Standards
 
In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires 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. CAIR has been challenged in the United States Court of Appeals for the District of Columbia. The future cost of compliance with these regulations may be substantial and may depend on the outcome of this litigation and how CAIR is ultimately implemented.
 
Mercury Emissions

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

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

W. H. Sammis Plant

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W.H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, are referred to as the New Source Review (NSR) cases.

 
17

 

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 consent decree are currently estimated to be $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

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.

On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation, or Bechtel, under which Bechtel will engineer, procure and construct AQC systems for the reduction of SO2 emissions.  FGCO also entered into an agreement with Babcock & Wilcox Company, or B&W, on August 25, 2006 to supply flue gas desulfurization systems for the reduction of SO2 emissions.  SCR systems for the reduction of NOX emissions are also being installed at the Sammis Plant under a 1999 Agreement with B&W.
 
On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to change the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.
 
Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it 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. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

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

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as "air pollutants" under the 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.

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.
 
 
18

 
 

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPAs 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 EPAs 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 non-hazardous waste.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.  As of December 31, 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 (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks 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 may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 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 of approximately $56 million 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 $93 million have been accrued through December 31, 2007.

Fuel Supply

FirstEnergy currently has long-term coal contracts with various terms to provide approximately 23.6 million tons of coal for the year 2008, sufficient to meet 2008 coal requirements of 23.6 million tons. This contract coal is produced primarily from mines located in Pennsylvania, Kentucky, Wyoming, West Virginia and Ohio. The contracts expire at various times through December 31, 2028. See Environmental Matters for factors pertaining to meeting environmental regulations affecting coal-fired generating units.


 
19

 
 
FirstEnergy is contracted for all uranium requirements through 2009 and a portion of uranium material requirements through 2014. Conversion services contracts fully cover requirements through 2010 and partially fill requirements through 2015. Enrichment services are contracted for all of the enrichment requirements for nuclear fuel through 2013. A portion of enrichment requirements is also contracted for through 2020. Fabrication services for fuel assemblies are contracted for both Beaver Valley units and Davis Besse through 2013 and through the operating license period for Perry (through approximately 2026). The Davis-Besse fabrication contract also has an extension provision for services for three additional consecutive reload batches through the current operating license period (approximately 2017). In addition to the existing commitments, FirstEnergy intends to make additional arrangements for the supply of uranium and for the subsequent conversion, enrichment, fabrication, and waste disposal services.
 
On-site spent fuel storage facilities are expected to be adequate for Perry through 2011; facilities at Beaver Valley Units 1 and 2 are expected to be adequate through 2015 and 2008, respectively. With the plant modifications completed in 2002, Davis-Besse has adequate storage through the remainder of its current operating license period. After current on-site storage capacity is exhausted, additional storage capacity will have to be obtained either through plant modifications, interim off-site disposal, or permanent waste disposal facilities. FENOC has submitted a License Amendment Request (LAR) to the NRC to revise the criticality analysis for the spent fuel storage racks at Beaver Valley Unit 2. When this LAR is approved, several storage locations that are currently required to remain empty will be made available for spent fuel storage, thus providing sufficient storage capacity until early 2011. FENOC expects the NRC to approve the LAR in March 2008. FENOC is also currently taking actions to extend the spent fuel storage capacity for Perry.

The Federal Nuclear Waste Policy Act of 1982 provides for the construction of facilities for the permanent disposal of high-level nuclear wastes, including spent fuel from nuclear power plants operated by electric utilities. CEI, TE, OE and Penn have contracts with the U.S. Department of Energy (DOE) for the disposal of spent fuel for Beaver Valley, Davis-Besse and Perry. On February 15, 2002, President Bush approved the DOEs recommendation of Yucca Mountain for underground disposal of spent nuclear fuel from nuclear power plants and high level waste from U.S. defense programs. The approval by President Bush enables the process to proceed to the licensing phase. Based on the DOE schedule published on July 19, 2006, the Yucca Mountain Repository is currently projected to start receiving spent fuel in 2017. The Companies intend to make additional arrangements for storage capacity as a contingency for further delays with the DOE acceptance of spent fuel for disposal past 2017.
 
Fuel oil and natural gas are used primarily to fuel peaking units and to ignite the burners prior to burning coal when a coal-fired plant is restarted. Fuel oil requirements have historically been low and are forecast to remain so, expected to average approximately 5 million gallons per year over the next five years. Since the price and supply risk associated with fuel oil procurement is perceived to be low compared to the overall FES generating fleet fuel requirements, most fuel oil is purchased through annual contracts at market prices. Natural gas is consumed primarily by the peaking units, and the demand is forecasted to range from approximately 2.8 million cubic feet (Mcf) in 2006 to 5.8 Mcf in 2008. Because of the relatively high price volatility and unpredictability of unit dispatch, natural gas is typically purchased for the current year based on forecasted demand, and sold daily when the units do not run or supplemented by additional gas purchases on days that the units run at dispatch levels that are above planned usage.
 
System Capacity and Reserves

The 2007 net maximum hourly demand for each of the Companies was: OE-5,955 MW on August 8, 2007; Penn-1,082 MW on August 24, 2007; CEI-4,471 MW on August 24, 2007; TE-2,200 MW on August 2, 2007; JCP&L-6,152 MW on August 8, 2007; Met-Ed-2,934 MW on August 8, 2007; and Penelec-2,895 MW on February 5, 2007.

Based on existing capacity plans, ongoing arrangements for firm purchase contracts and anticipated term power sales and purchases, FirstEnergy has sufficient supply resources to meet load obligations. The current FirstEnergy capacity portfolio of 14,127 MW consists of 13,664 MW of owned or leased generation and 463 MW of generation from our 20.5% ownership of OVEC.  In addition, FirstEnergy has 1,334 MW of long-term purchases from Pennsylvania and New Jersey NUGs and has entered into 215 MW of long-term purchase contracts for renewable energy from wind resources. Any remaining load obligations will be met through a mix of multi-year forward purchases, short-term forward purchases (less than one year) and spot market purchases. FirstEnergy's sources of generation during 2007 were 62% non-nuclear and 38% nuclear.

Regional Reliability

FirstEnergy's operating companies in Ohio, Pennsylvania, and New Jersey within MISO and PJM operate under the reliability oversight of a regional entity known as ReliabilityFirst. This regional entity operates under the oversight of the NERC in accordance with a Delegation Agreement approved by the FERC. ReliabilityFirst began operations under NERC on January 1, 2006. Subsequently on July 20, 2006, NERC was certified by FERC as the ERO in the United States pursuant to Section 215 of the Federal Power Act and ReliabilityFirst was certified as a regional entity. ReliabilityFirst represents the consolidation of the ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils into a single new regional reliability organization.
 
 
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Competition

As a result of actions taken by state legislative bodies, major changes in the electric utility business have occurred in parts of the United States, including Ohio, New Jersey and Pennsylvania where FirstEnergy's utility subsidiaries operate. These changes have altered the way traditional integrated utilities conduct their business. In accordance with the Ohio electric utility restructuring law under which Ohio electric customers could begin choosing their electric generation suppliers starting in January 2001, FirstEnergy has further aligned its business units to accommodate its retail strategy and participate in the competitive electricity marketplace in Ohio. The structural changes deal with the unbundling of electric utility services and new ways of conducting business. FirstEnergy's Competitive Energy Services segment participates in deregulated energy markets in Ohio, Pennsylvania, Maryland and Michigan through FES.
 
Competition in Ohio's electric generation market began on January 1, 2001. Pursuant to the generation asset transfers on October 24, 2005 and December 16, 2005, FGCO and NGC own or lease all of the fossil and nuclear generation assets, respectively, previously owned by the Ohio Companies and Penn, and FENOC continues to operate those companies respective nuclear leasehold interests. The Ohio Companies continue to obtain their PLR and default service requirements through power supply agreements with FES. JCP&Ls obligation to provide BGS has been transferred through a transitional mechanism of auctioning the obligation (see NJBPU Rate Matters). Met-Ed and Penelec have been purchasing a portion of their PLR and default service 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 and default service capacity and energy requirements during the term of these agreements with FES (see PPUC Rate Matters for further discussion).

On May 2, 2007, Penn filed a plan with the PPUC for the procurement of default service 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 default service 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 default service will be provided through an hourly-priced service provided by Penn (see PPUC Rate Matters for further discussion).

Research and Development

The Companies participate in funding EPRI, which was formed for the purpose of expanding electric research and development under the voluntary sponsorship of the nations electric utility industry - public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on all aspects of electric power production and use, including fuels, generation, delivery, energy management and conservation, environmental effects and energy analysis. The major portion of EPRI research and development projects is directed toward practical solutions and their applications to problems currently facing the electric utility industry.

 
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Executive Officers

Name
 
Age
 
Positions Held During Past Five Years
 
Dates
             
A. J. Alexander (A)(B)
 
56
 
President and Chief Executive Officer
 
2004-present
       
President and Chief Operating Officer
 
*-2004
 
W. D. Byrd
 
 
 
53
 
 
Vice President, Corporate Risk & Chief Risk Officer
Director - Rates Strategy
Director - Commodity Supply
 
 
2007-present
2004-2007
*-2004
 
L. M. Cavalier
 
56
 
Senior Vice President - Human Resources
Vice President - Human Resources
 
2005-present
*-2005
             
M. T. Clark (E)
 
57
 
Senior Vice President - Strategic Planning & Operations
Vice President - Business Development
 
2004-present
*-2004
             
D. S. Elliott (B)
 
53
 
President - Pennsylvania Operations
 
2005-present
       
Senior Vice President
 
*-2005
             
R. R. Grigg (A)(B)(F)
 
59
 
Executive Vice President and Chief Operating Officer
 
2004-present
 
 
J. J. Hagan
 
 
 
57
 
President and Chief Executive Officer - WE Generation
 
President and Chief Nuclear Officer - FENOC
Senior Vice President and Chief Operating Officer - FENOC
Senior Vice President - FENOC
 
 
*-2004
 
2007-present
2005-2007
*-2005
 
C. E. Jones (D)
 
52
 
President - FirstEnergy Solutions
Senior Vice President - Energy Delivery & Customer Service
Regional Vice President - Operations
 
2007-present
2003-2007
**-2003
             
C. D. Lasky (D)
 
45
 
Vice President - Fossil Operations & Air Quality Compliance
 
2004-present
       
Plant Director
 
*2004
             
G. R. Leidich (G)
 
57
 
Senior Vice President - Operations
President and Chief Nuclear Officer- FENOC
 
2007-present
2003-2007
       
Executive Vice President - FENOC
 
*-2003
             
D. C. Luff
 
60
 
Senior Vice President - Governmental Affairs
 
2007-present
       
Vice President
 
*-2007
             
R. H. Marsh (A)(B)(D)
 
57
 
Senior Vice President and Chief Financial Officer
 
*-present
             
S. E. Morgan (C)
 
57
 
President - JCP&L
 
2004-present
       
Vice President - Energy Delivery
 
*-2004
             
J. M. Murray (A)
 
61
 
President - Ohio Operations
Regional President - Toledo Edison Company
 
2005-present
2004-2005
       
Regional President - West
 
*-2004
 
J. F. Pearson (A)(B)(D)
 
53
 
Vice President and Treasurer
 
2006-present
       
Treasurer
Group Controller - Strategic Planning and Operations
 
2005-2006
2004-2005
       
Group Controller - FirstEnergy Solutions
 
*-2004
             
D. R. Schneider (A)(B)
 
46
 
Senior Vice President
Vice President - Energy Delivery
Vice President - Commodity Operations (FES)
 
2007-present
2006-2007
2004-2006
       
Vice President - Fossil Operations (FES)
 
*-2004
             
L.L. Vespoli (A)(B)(D)(H)
 
48
 
Senior Vice President and General Counsel
 
*-present
             
H. L. Wagner (A)(B)(D)
 
55
 
Vice President, Controller and Chief Accounting Officer
 
*-present
             
T. M. Welsh
 
58
 
Senior Vice President - Assistant to CEO
Senior Vice President
 
2007-present
2004-2007
       
Vice President
 
*-2004

(A) Denotes executive officers of OE, CEI and TE.
(B) Denotes executive officers of Met-Ed, Penelec and Penn Power.
(C) Denotes executive officer of JCP&L.
(D) Denotes executive officers of FES.
(E) Effective March 2, 2008, elected Executive Vice President, Strategic Planning and Operations.
(F) Effective March 2, 2008, elected Executive Vice President and President, FirstEnergy Utilities.
(G) Effective March 2, 2008, elected Executive Vice President and President, FirstEnergy Generation.
(H) Effective March 2, 2008, elected Executive Vice President and General Counsel.
*  Indicates position held at least since January 1, 2003.

 
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Effective March 2, 2008, Mr. Richard R. Grigg, who previously was Executive Vice President and Chief Operating Officer, was elected Executive Vice President and President, FirstEnergy Utilities.  Also, effective March 2, 2008, Mr. Gary R. Leidich was elected Executive Vice President and President, FirstEnergy Generation.
 
Employees

As of January 1, 2008, FirstEnergy's subsidiaries had a total of 14,534 employees located in the United States as follows:

FESC
3,318
OE
1,318
CEI
1,021
TE
445
Penn
224
JCP&L
1,482
Met-Ed
764
Penelec
964
ATSI
39
FES
196
FGCO
1,942
FENOC
2,821
Total
14,534

Of the above employees 6,720 (including 257 for FESC; 774 for OE; 672 for CEI; 323 for TE; 165 for Penn; 1,126 for JCP&L; 534 for Met-Ed; 655 for Penelec; 1,249 for FGCO; and 965 for FENOC) are covered by collective bargaining agreements.

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

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

FirstEnergy Web Site

Each of the registrants' Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy's internet Web site at www.firstenergycorp.com. These reports are posted on the Web site as soon as reasonably practicable after they are electronically filed with the SEC. Information contained on FirstEnergy's Web site shall not be deemed incorporated into, or be part of, this report.

ITEM 1A. 
RISK FACTORS

We operate in a business environment that involves significant risks, many of which are beyond our control. Below, we have identified risks we currently consider material. However, our business, financial condition, cash flows or results of operations could be affected materially and adversely by additional risks not currently known to us or that we deem immaterial at this time. Additional information on risk factors is included in "Item 1. Business" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results.

 
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Risks Related to Business Operations

Risks Arising from the Reliability of Our Power Plants and Transmission and Distribution Equipment

Operation of generation, transmission and distribution facilities involves risk, including the potential breakdown or failure of equipment or processes, accidents, labor disputes or work stoppages by unionized employees, acts of terrorism or sabotage, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of those facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.

Operation of our power plants below expected capacity levels could result in lost revenues or increased expenses, including higher maintenance costs. Unplanned outages may require us to incur significant replacement power costs. Also, when planned outages last longer than anticipated, capacity factors decrease and we face lower margins due to higher replacement energy costs and/or lower energy sales.  Moreover, if we were unable to perform under contractual obligations, penalties or liability for damages could result. FES, FGCO and the Ohio Companies are exposed to losses under their applicable sale-leaseback arrangements for generating facilities upon the occurrence of certain contingent events that could render those facilities worthless. Although we believe these types of events are unlikely to occur, FES, FGCO and the Ohio Companies have a maximum exposure to loss under those provisions of approximately $1.3 billion for FES and $800 million for each of the Ohio Companies.

We remain obligated to provide safe and reliable service to customers within our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. Failure to provide safe and reliable service and failure to meet regulatory reliability standards due to a number of factors, including equipment failure and weather, could adversely affect our operating results through reduced revenues and increased capital and operating costs and the imposition of penalties/fines or other adverse regulatory outcomes.

Changes in Commodity Prices Could Adversely Affect Our Profit Margins
 
While much of our generation currently serves customers under retail rates set by regulatory bodies, we also purchase and sell electricity in the competitive wholesale and retail markets. Increases in the costs of fuel for our generation facilities (particularly coal, uranium and natural gas) can affect our profit margins in both competitive and non-competitive markets. Changes in the market prices of electricity, which are affected by changes in other commodity costs and other factors, may impact our results of operations and financial position by increasing the amount we pay to purchase power to supply PLR and default service obligations in Ohio and Pennsylvania.

Electricity and fuel prices may fluctuate substantially over relatively short periods of time for a variety of reasons, including:

 
changing weather conditions or seasonality;

 
changes in electricity usage by our customers;

 
illiquidity in wholesale power and other markets;

 
transmission congestion or transportation constraints, inoperability or inefficiencies;

 
availability of competitively priced alternative energy sources;

 
changes in supply and demand for energy commodities;

 
changes in power production capacity;

 
outages at our power production facilities or those of our competitors;

 
changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products; and
 
 
natural disasters, wars, acts of sabotage, terrorist acts, embargoes and other catastrophic events.

 
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We Are Exposed to Operational, Price and Credit Risks Associated With Selling and Marketing Products in the Power Markets That We Do Not Always Completely Hedge Against

We purchase and sell power at the wholesale level under market-based tariffs authorized by the FERC, and also enter into short-term agreements to sell available energy and capacity from our generation assets. If we are unable to deliver firm capacity and energy under these agreements, we may be required to pay damages. These damages would generally be based on the difference between the market price to acquire replacement capacity or energy and the contract price of the undelivered capacity or energy. Depending on price volatility in the wholesale energy markets, such damages could be significant. Extreme weather conditions, unplanned power plant outages, transmission disruptions, and other factors could affect our ability to meet our obligations, or cause increases in the market price of replacement capacity and energy.

We attempt to mitigate risks associated with satisfying our contractual power sales arrangements by reserving generation capacity to deliver electricity to satisfy our net firm sales contracts and, when necessary, by purchasing firm transmission service. We also routinely enter into contracts, such as fuel and power purchase and sale commitments, to hedge our exposure to fuel requirements and other energy-related commodities. We may not, however, hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position could be negatively affected.

The Use of Derivative Contracts by Us to Mitigate Risks Could Result in Financial Losses that may Negatively Impact our Financial Results

We use a variety of non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts.  Also, we could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.
 
Our Risk Management Policies Relating to Energy and Fuel Prices, and Counterparty Credit are by Their Very Nature Risk Related, and We Could Suffer Economic Losses Despite Such Policies

We attempt to mitigate the market risk inherent in our energy and fuel and debt positions. Procedures have been implemented to enhance and monitor compliance with our risk management policies, including validation of transaction and market prices, verification of risk and transaction limits, sensitivity analysis and daily portfolio reporting of various risk measurement metrics. Nonetheless, we cannot economically hedge against all of our exposures in these areas and our risk management program may not operate as planned. For instance, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions upon which we based our risk management positions. Also, our power plants might not produce the expected amount of power during a given day or time period due to weather conditions, technical problems or other unanticipated events, which could require us to make energy purchases at higher prices than the prices under our energy supply contracts. In addition, the amount of fuel required for our power plants during a given day or time period could be more than expected, which could require us to buy additional fuel at prices less favorable than the prices under our fuel contracts. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge.

We also face credit risks from parties with whom we contract which could default in their performance, in which cases we could be forced to sell our power into a lower-priced market or make purchases in a higher-priced market than existed at the time of executing the contract. Although we have established risk management policies and programs, including credit policies to evaluate counterparty credit risk, there can be no assurance that we will be able to fully meet our obligations, that we will not be required to pay damages for failure to perform or that we will not experience counterparty non-performance or that we will collect for voided contracts. If counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices. In that event, our financial results could be adversely affected.

 
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Nuclear Generation Involves Risks that Include Uncertainties Relating to Health and Safety, Additional Capital Costs, the Adequacy of Insurance Coverage and Nuclear Plant Decommissioning

FirstEnergy is subject to the risks of nuclear generation, including but not limited to the following:

 
the potential harmful effects on the environment and human health resulting from certain unplanned radiological releases associated with the operation of our nuclear facilities and the storage, handling and disposal of radioactive materials;

 
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;

 
uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and

 
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed operation.

The NRC has broad authority under federal law to impose licensing security and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down a unit, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants, including ours.

FirstEnergy's nuclear facilities are insured under NEIL policies issued for each plant. Under these policies, up to $2.8 billion of insurance coverage is provided for property damage and decontamination and decommissioning costs. We have also obtained approximately $2.0 billion of insurance coverage for replacement power costs. Under these policies, we can be assessed a maximum of approximately $81 million for incidents at any covered nuclear facility occurring during a policy year that are in excess of accumulated funds available to the insurer for paying losses.

The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $10.8 billion (assuming 104 units licensed to operate in the United States) for a single nuclear incident, which amount is covered by:  (i) private insurance amounting to $300.0 million; and (ii) $10.5 billion provided by an industry retrospective rating plan. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $100.6 million (but not more than $15.0 million per year) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on our present nuclear ownership, the maximum potential assessment under these provisions would be $402.4 million per incident but not more than $60.0 million in any one year.

Capital Market Performance and Other Changes May Decrease the Value of Decommissioning Trust Fund, Pension Fund Assets and Other Trust Funds Which Then Could Require Significant Additional Funding

The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations to decommission our nuclear plants, to pay pensions to our retired employees and to pay other obligations. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. For example, certain investments within our nuclear decommissioning, pension and other postretirement benefit trusts hold underlying credit market securities, including subprime mortgage-related assets. Due to recent market developments, including a series of rating agency downgrades of subprime mortgage-related assets, the fair value of these subprime-related investments has declined. We expect the market to continue to evolve, and that the fair value of our subprime-related investments may frequently change. A decline in the market value of the assets may increase the funding requirements of these obligations. Forecasting investment earnings and costs to decommission nuclear generating stations, to pay future pensions and other obligations requires significant judgment, and actual results may differ significantly from current estimates. Ultimately, if the investments held by our nuclear decommissioning trusts, pension funds and other trust investments are not sufficient to fund the decommissioning of our nuclear plants or to fund pension and other obligations, we may be required to provide other means of funding those obligations.  If we are unable to successfully manage those trust funds our results of operation and financial position could be negatively affected.

We Could be Subject to Higher Costs and/or Penalties Related to Mandatory NERC/FERC Reliability Standards
 
As a result of the EPACT, owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by NERC and approved by FERC. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. Compliance with new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties.

 
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We Rely on Transmission and Distribution Assets that we do not Own or Control to Deliver Our Wholesale Electricity. If Transmission is Disrupted Including Our Own Transmission, or not Operated Efficiently, or if Capacity is Inadequate, Our Ability to Sell and Deliver Power may be Hindered

We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity we sell. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by independent system operators, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products on the most favorable terms.
 
Demand for electricity within our service areas could stress available transmission capacity requiring alternative routing or curtailing electricity usage that may increase operating costs or reduce revenues with adverse impacts to results of operations. In addition, as with all utilities, potential concerns over transmission capacity could result in MISO, PJM or the FERC requiring us to upgrade or expand our transmission system, requiring additional capital expenditures.

The FERC requires wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, it is possible that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electricity as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether independent system operators in applicable markets will operate the transmission networks, and provide related services, efficiently.

Disruptions in Our Fuel Supplies Could Occur, Which Could Adversely Affect Our Ability to Operate Our Generation Facilities and Impact Financial Results

We purchase fuel from a number of suppliers. The lack of availability of fuel at expected prices, or a disruption in the delivery of fuel which exceeds the duration of our on-site fuel inventories, including disruptions as a result of weather, increased transportation costs or other difficulties, labor relations or environmental or other regulations affecting our fuel suppliers, could cause an adverse impact on our ability to operate our facilities, possibly resulting in lower sales and/or higher costs and thereby adversely affect our results of operations. Operation of many of our coal-fired generation facilities is highly dependent on our ability to procure coal. Although we have long-term contracts in place for our coal and coal transportation needs, power generators in the Midwest and the Northeast have experienced significant pressures on available coal supplies that are either transportation or supply related. If prices for physical delivery are unfavorable, our financial condition, results of operations and cash flows could be materially adversely affected.

Seasonal Temperature Variations, as well as Weather Conditions or other Natural Disasters Could Have a Negative Impact on Our Results of Operations and Demand Significantly Below or Above our Forecasts Could Adversely Affect our Energy Margins

Weather conditions directly influence the demand for electric power. In our service areas, demand for power generally peaks during the summer months, with market prices also typically peaking at that time. As a result, overall operating results may fluctuate on a seasonal and quarterly basis. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, ice or snow storms or droughts or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period.

Customer demand that we satisfy pursuant to our default service tariffs could increase as a result of severe weather conditions, economic development or other circumstances over which we have no control. We satisfy our electricity supply obligations through a portfolio approach of providing electricity from our generation assets, contractual relationships and market purchases. A significant increase in demand could adversely affect our energy margins if we are required under the terms of the default service tariffs to provide the energy supply to fulfill this increased demand at capped rates, which we expect to remain significantly below the wholesale prices at which we would have to purchase the additional supply if needed or, if we had available capacity, the prices at which we could otherwise sell the additional supply. Accordingly, any significant change in demand could have a material adverse effect on our results of operations or financial position.

 
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We Are Subject to Financial Performance Risks Related to the Economic Cycles of the Electric Utility Industry

Our business follows the economic cycles of our customers. Sustained downturns or sluggishness in the economy generally affects the markets in which we operate and negatively influences our energy operations. Declines in demand for electricity as a result of economic downturns will reduce overall electricity sales and reduce our cash flows, especially as industrial customers reduce production, resulting in less consumption of electricity. Economic conditions also impact the rate of delinquent customer accounts receivable, further increasing our costs.

The Goodwill of One or More of Our Operating Subsidiaries May Become Impaired, Which Would Result in Write-Offs of the Impaired Amounts
 
 
There is a possibility that additional goodwill may be impaired at one or more of our operating subsidiaries. The actual timing and amounts of any goodwill impairments in future years would depend on many uncertain variables, including changing interest rates, utility sector market performance, our capital structure, market prices for power, results of future rate proceedings, operating and capital expenditure requirements, the value of comparable utility acquisitions and other factors.

We Face Certain Human Resource Risks Associated with the Availability of Trained and Qualified Labor to Meet Our Future Staffing Requirements

We face the difficult challenge of finding ways to retain our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Mitigating these risks could require additional financial commitments.

Significant Increases in Our Operation and Maintenance Expenses, Including Our Health Care and Pension Costs, Could Adversely Affect Our Future Earnings and Liquidity

We continually focus on limiting, and reducing where possible, our operation and maintenance expenses. However, we expect to continue to face increased cost pressures, including health care and pension costs. We have experienced significant health care cost inflation in the last few years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to continue to take to require employees and retirees to bear a higher portion of the costs of their health care benefits. The measurement of our expected future health care and pension obligations, costs and liabilities is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, health care cost trends, benefit improvements, salary increases and the demographics of plan participants. If actual results differ materially from our assumptions, our costs could be significantly increased.

Our  Business is Subject to the Risk that Sensitive Customer Data May be Compromised, Which Could Result in an Adverse Impact to Our Reputation and/or Results of Operations

Our business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business. A security breach may occur, despite security measures taken by us and required of vendors. If a significant or widely publicized breach occurred, our business reputation may be adversely affected, customer confidence may be diminished, or we may become subject to legal claims, any of which may have a negative impact on our business and/or results of operations.

Acts of War or Terrorism Could Negatively Impact Our Business

The possibility that our infrastructure, or that of an interconnected company, such as electric generation, transmission and distribution facilities could be direct targets of, or indirect casualties of, an act of war or terrorism could affect our operations. Our generation plants, transmission and distribution facilities, or those of interconnected companies, may be targets of terrorist activities that could result in disruption of our ability to generate, purchase, transmit or distribute electricity. Any such disruption could result in a decrease in revenues and additional costs to purchase electricity and to replace or repair our assets, which could have a material adverse impact on our results of operations and financial condition.

 
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Capital Improvements and Construction Projects May Not be Completed within Forecasted Budget, Schedule or Scope Parameters

Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades, as well as other initiatives. We may be exposed to the risk of substantial price increases in the costs of labor and materials used in construction. We have engaged numerous contractors and entered into a large number of agreements to acquire the necessary materials and/or obtain the required construction related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors inability to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. This could have negative financial impacts such as incurring losses or delays in completing construction projects.

We May Acquire Assets That Could Present Unanticipated Issues for our Business in the Future, Which Could Adversely Affect Our Ability to Realize Anticipated Benefits of Those Acquisitions

Asset acquisitions involve a number of risks and challenges, including management attention; integration with existing assets; difficulty in evaluating the requirements associated with the assets prior to acquisition, operating costs, potential environmental and other liabilities, and other factors beyond our control; and an increase in our expenses and working capital requirements.  Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows or realize other anticipated benefits from any such asset acquisition.

Risks Associated With Regulation

Complex and Changing Government Regulations Could Have a Negative Impact on Our Results of Operations
 
We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in or reinterpretations of existing laws or regulations or the imposition of new laws or regulations could require us to incur additional costs or change the way we conduct our business, and therefore could have an adverse impact on our results of operations.

Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. Thus, the rates a utility is allowed to charge may or may not match its expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered. While rate regulation is premised on providing an opportunity to earn a reasonable return on invested capital and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner.

Regulatory Changes in the Electric Industry Including a Reversal, Discontinuance or Delay of the Present Trend Toward Competitive Markets Could Affect Our Competitive Position and Result in Unrecoverable Costs Adversely Affecting Our Business and Results of Operations

As a result of restructuring initiatives, changes in the electric utility business have occurred and are continuing to take place throughout the United States, including Ohio, Pennsylvania and New Jersey. These changes have resulted, and are expected to continue to result, in fundamental alterations in the way utilities conduct their business.

Criticism of restructured electricity markets in public forums escalated during 2007 as retail rate freezes expired in a number of states and fuel prices increased, thereby driving up retail prices for electricity. Consumers in other states are experiencing significant rate increases. In Ohio, Pennsylvania and New Jersey there is growing pressure for state regulatory and political processes to take steps to reduce the impact of price increases on retail customers. The political pressure for states to retreat from allowing competitively-priced supplies to serve retail load and to return to cost-based regulation of generation resources or take other actions directed at generators of electricity creates heightened risk of limitations on the retail price of electricity or other restrictions on the full recovery of market-based generation prices, which could significantly affect our results of operations.

 
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Some states that have deregulated generation service have experienced difficulty in transitioning to market-based pricing. In some instances, state and federal government agencies and other interested parties have made proposals to delay market restructuring or even re-regulate areas of these markets that have previously been deregulated. Although we expect wholesale electricity markets to continue to be competitive, other proposals to re-regulate our industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be delayed, discontinued or reversed in the states in which we currently, or may in the future, operate. Such delays, discontinuations or reversals of electricity market restructuring in the markets in which we operate could have an adverse impact on our results of operations and financial condition.

The FERC and the U.S. Congress propose changes from time to time in the structure and conduct of the electric utility industry. If the restructuring, deregulation or re-regulation efforts result in decreased margins or unrecoverable costs, our business and results of operations may be adversely affected. We cannot predict the extent or timing of further efforts to restructure, deregulate or re-regulate our business or the industry.

Our Profitability is Impacted by Our Affiliated Companies Continued Authorization to Sell Power at Market-Based Rates

In 2005 the FERC granted FES, FGCO and NGC authority to sell electricity at market-based rates. These orders also granted them waivers of certain FERC accounting, record-keeping and reporting requirements.   JCP&L, Met-Ed, OE, Penn, Penelec and TE also have market-based rate authority.  The FERCs orders that grant this market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. As a condition to the orders granting these generating companies market-based rate authority, every three years they are required to file a market power update to show that they continue to meet the FERCs standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates. FES, FGCO NGC,JCP&L, Met-Ed, OE, Penn, Penelec and TE have filed to renew this authority in 2008. If any of these companies were to lose its market-based rate authority or fail to have such authority renewed, it would be required to obtain the FERCs acceptance to sell power at cost-based rates. FES, FGCO and NGC could also lose their waivers, and become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.

There Are Uncertainties Relating to the Operations of the PJM and MISO Regional Transmission Organizations (RTOs)

RTO rules could affect our ability to sell power produced by our generating facilities to users in certain markets due to transmission constraints and attendant congestion costs. The prices in day-ahead and real-time energy markets and RTO capacity markets have been subject to price volatility. Administrative costs imposed by RTOs, including the cost of administering energy markets, have also increased. The rules governing the various regional power markets may also change from time to time which could affect our costs or revenues. To the degree we incur significant additional fees and increased costs to participate in an RTO, and we are limited with respect to recovery of such costs from retail customers, we may suffer financial harm. While RTO rates for transmission service are designed to be revenue neutral, our revenues from customers to whom we currently provide transmission services may not reflect all of the administrative and market-related costs imposed under the RTO tariff. In addition, we may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. Finally, we may be required to expand our transmission system according to decisions made by an RTO rather than our internal planning process. Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will ultimately develop and operate or what region they will cover, we cannot fully assess the impact that these power markets or other ongoing RTO developments may have.

Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with Future Environmental Laws, Including limitations on GHG Emissions Could Adversely Affect Cash Flow and Profitability

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. Environmental advocacy groups, other organizations and some agencies in the United States are focusing considerable attention on carbon dioxide emissions from power generation facilities and their potential role in climate change.  Many states and environmental groups have also challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict.  As a result, it is possible that state and federal regulations will be developed that will impose more stringent limitations on emissions than are currently in effect. Although several bills have been introduced at the state and federal level that would compel carbon dioxide emission reductions, none have advanced through the legislature. Future changes in environmental regulations governing these pollutants could require us to make increased capital expenditures for pollution control devices which could have an adverse impact on our results of operations, cash flows and financial condition. Such legislation could even make some of our electric generating units uneconomic to maintain or operate. In addition, any legal obligation that would require us to substantially reduce our emissions beyond present levels could require extensive mitigation efforts and, in the case of carbon dioxide legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.

 
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Certain of our subsidiaries operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for environmental monitoring, installation of pollution control equipment, emission fees, maintenance, upgrading, remediation and permitting at all of our facilities. These expenditures have been significant in the past and may increase in the future. If the cost of compliance with existing environmental laws and regulations does increase, it could adversely affect our business and results of operations, financial position and cash flows. Moreover, changes in environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures. Because of the deregulation of generation, we may not directly recover through rates additional costs incurred for such compliance. Our compliance strategy, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If FirstEnergy or its subsidiaries fail to comply with environmental laws and regulations, even if caused by factors beyond our control or new interpretations of longstanding requirements, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations.

The EPAs final CAIR and CAVR require significant reductions beginning in 2009 in air emissions from coal-fired power plants and the states have been given substantial discretion in developing their own rules to implement these programs. CAIR has been challenged in the United States Court of Appeals for the District of Columbia. As a result, the ultimate requirements under these air emission reduction programs may not be known for several years and may differ significantly from the current rules. If the final rules are remanded by the Court of Appeals, if states elect not to participate in the various federal programs under the rules, or if the states elect to impose additional requirements on individual units that are already subject to the CAIR and/or the CAVR, costs of compliance could increase significantly and could have an adverse effect on future results of operations, cash flows and financial condition. Alternatively, if the final rules are remanded by the Court and their implementation is postponed, we could be competitively disadvantaged because we are currently obligated to comply with essentially this same level of emission controls as a result of our settlement of the New Source Review Litigation related to our W. H. Sammis Plant.
 
The EPA's final CAMR was vacated by the United States Court of Appeals for the District Court of Columbia on February 8, 2008 because the EPA failed to take the necessary steps to "de-list" coal-fired power plants from its hazardous air pollution program and therefore, could not promulgate a cap and trade air emissions reduction program.  The EPA must now seek judicial review of the court's ruling or take further regulatory action to promulgate new hazardous air emission reduction programs which may differ significantly from the cap and trade program previously promulgated by the EPA for mercury.  As a result, costs of compliance could increase significantly and could have a material adverse effect on future results of operations, cash flows and financial condition.
 
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.

Also, we are generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of our facilities which we have acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with some acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against some environmental liabilities. If we incur a material liability, or the other party to a transaction fails to meet its indemnification obligations to us, we could suffer material losses.
 
Availability and Cost of Emission Credits Could Materially Impact Our Costs of Operations
 
We are required to maintain, either by allocation or purchase, sufficient emission credits to support our operations in the ordinary course of operating our power generation facilities. These credits are used to meet our obligations imposed by various applicable environmental laws. If our operational needs require more than our allocated allowances of emission credits, we may be forced to purchase such credits on the open market, which could be costly. If we are unable to maintain sufficient emission credits to match our operational needs, we may have to curtail our operations so as not to exceed our available emission credits, or install costly new emissions controls. As we use the emissions credits that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such credits are available for purchase, but only at significantly higher prices, the purchase of such credits could materially increase our costs of operations in the affected markets.

Mandatory Renewable Portfolio Requirements Could Negatively Affect Our Costs

If federal or state legislation mandates the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal, and such legislation would not also provide for adequate cost recovery, it could result in significant changes in our business, including renewable energy credit purchase costs, purchased power and potentially renewable energy credit costs and capital expenditures.

 
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We are and may Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of our Facilities

We have been named as a defendant in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at our facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us.

The Continuing Availability and Operation of Generating Units is Dependent on Retaining the Necessary Licenses, Permits, and Operating Authority from Governmental Entities, Including the NRC
 
We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on operating results from future regulatory activities of any of these agencies and we are not assured that any such permits, approvals or certifications will be renewed.

Risks Associated With Financing and Capital Structure

Interest Rates and/or a Credit Rating Downgrade Could Negatively Affect Our Financing Costs and Our Ability to Access Capital

We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. Interest rates could significantly change as a result of economic or other events that our risk management processes were not established to address. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations.

We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. A downgrade in our credit ratings from the nationally-recognized credit rating agencies, particularly to a level below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as in place of letters of credit and other guarantees. A rating downgrade would also increase the fees we pay on our various credit facilities, thus increasing the cost of our working capital. A rating downgrade could also impact our ability to grow our businesses by substantially increasing the cost of, or limiting access to, capital. Our senior unsecured debt ratings from S&P and Moodys are investment grade. The current ratings outlook from S&P is negative and the ratings outlook from Moodys is stable.

A rating is not a recommendation to buy, sell or hold debt, inasmuch as such rating does not comment as to market price or suitability for a particular investor. The ratings assigned to our debt address the likelihood of payment of principal and interest pursuant to their terms. A rating may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating that may be assigned to our securities.

We Must Rely on Cash from Our Subsidiaries

We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our business is conducted by our subsidiaries. Consequently, our cash flow is dependent on the operating cash flows of our subsidiaries and their ability to upstream cash to the holding company. Our utility subsidiaries are regulated by various state utility commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state commissions could attempt to impose restrictions on the ability of our utility subsidiaries to pay dividends or otherwise restrict cash payments to us.

 
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We Cannot Assure Common Shareholders that Future Dividend Payments Will be Made, or if Made, in What Amounts they May be Paid

Our Board of Directors regularly evaluates our common stock dividend policy and determines the dividend rate each quarter. The level of dividends will continue to be influenced by many factors, including, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past.

ITEM 1B. 
UNRESOLVED STAFF COMMENTS

None.

ITEM 2. 
PROPERTIES

The Companies' respective first mortgage indentures constitute, in the opinion of the Companies counsel, direct first liens on substantially all of the respective Companies physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. See the "Leases" and "Capitalization" notes to the respective financial statements for information concerning leases and financing encumbrances affecting certain of the Companies' properties.

FirstEnergy has access, either through ownership or lease, to the following generation sources as of February 28, 2008, shown in the table below. Except for the leasehold interests referenced in the footnotes to the table, substantially all of the generating units are owned by NGC (nuclear) and FGCO (non-nuclear). See "Generation Asset Transfers" under Item 1 above.

 
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Net
 
       
Demonstrated
 
       
Capacity
 
   
Unit
 
(MW)
 
Plant-Location
         
Coal-Fired Units
         
Ashtabula-
         
Ashtabula, OH
 
 5
    244  
Bay Shore-
           
Toledo, OH
 
 1-4
    631  
R. E. Burger-
 
 
       
Shadyside, OH
 
 3-5
    406  
Eastlake-Eastlake, OH
 
 1-5
    1,233  
Lakeshore-
 
 
       
Cleveland, OH
 
 18
    245  
Bruce Mansfield-
 
 1
    830 (a)
Shippingport, PA
 
 2
    830 (b)
   
 3
    830 (c)
             
W. H. Sammis - Stratton, OH
 
 1-7
    2,220  
Kyger Creek - Chesire, OH
 
 1-5
    210 (d)
Clifty Creek - Madison, IN
 
 1-6
    253 (d)
Total
        7,932  
             
Nuclear Units
           
Beaver Valley-
 
 1
    911  
Shippingport, PA
 
 2
    868 (e)
Davis-Besse-
           
Oak Harbor, OH
 
 1
    893  
Perry-
           
N. Perry Village, OH
 
 1
    1,273 (f)
Total
        3,945  
             
Oil/Gas - Fired/
           
Pumped Storage Units
           
Richland - Defiance, OH
 
 1-6
    432  
Seneca - Warren, PA
 
 1-3
    451  
Sumpter - Sumpter Twp, MI
 
 1-4
    340  
West Lorain - Lorain, OH
 
 1-6
    545  
Yards Creek - Blairstown
           
Twp., NJ
 
 1-3
    200 (g)
Other
        282  
Total
        2,250  
Total
        14,127  


Notes:
(a)
Includes FGCO's leasehold interest of 93.825% (779 MW) and CEIs leasehold interest of 6.175% (51 MW), which has been assigned to FGCO.
 
(b)
Includes CEIs and TEs leasehold interests of 27.17% (226 MW) and 16.435% (136 MW), respectively, which have been assigned to FGCO.
 
(c)
Includes CEIs and TEs leasehold interests of 23.247% (193 MW) and 18.915% (157 MW), respectively, which have been assigned to FGCO.
 
(d)
Represents FGCO's 20.5% entitlement based on FirstEnergy's participation in OVEC.
 
(e)
Includes OEs and TEs leasehold interests of 21.66% (188 MW) and 18.26% (158 MW), respectively.
 
(f)
Includes OEs leasehold interest of 12.58% (160 MW).
 
(g)
Represents JCP&Ls 50% ownership interest.


FirstEnergy's generating plants and load centers are connected by a transmission system consisting of elements having various voltage ratings ranging from 23 kV to 500 kV. The Companies overhead and underground transmission lines aggregate 15,014 pole miles.

 
34

 

The Companies electric distribution systems include 117,642 miles of overhead pole line and underground conduit carrying primary, secondary and street lighting circuits. They own substations with a total installed transformer capacity of 88,329,000 kV-amperes.

The transmission facilities that are owned by ATSI are operated on an integrated basis as part of MISO and are interconnected with facilities operated by PJM. The transmission facilities of JCP&L, Met-Ed and Penelec are physically interconnected and are operated on an integrated basis as part of PJM.

FirstEnergy's distribution and transmission systems as of December 31, 2007, consist of the following:

           
Substation
 
   
Distribution
 
Transmission
 
Transformer
 
   
Lines
 
Lines
 
Capacity
 
   
(Miles)
 
(kV-amperes)
 
               
OE
    30,238     550     9,718,000  
Penn
    5,863     44     922,000  
CEI
    25,239     2,144     7,841,000  
TE
    1,982     223     2,503,000  
JCP&L
    19,287     2,135     21,608,000  
Met-Ed
    14,942     1,407     9,837,000  
Penelec
    20,091     2,690     14,471,000  
ATSI*
    -     5,821     21,429,000  
Total
    117,642     15,014     88,329,000  

 
*
Represents transmission lines of 69kv and above located in the service areas of OE, Penn, CEI and TE.

ITEM 3.
LEGAL PROCEEDINGS

Reference is made to Note 14, Commitments, Guarantees and Contingencies, of the Notes to Consolidated Financial Statements contained in Item 8 for a description of certain legal proceedings involving FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.

ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

ITEM 5.
MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 

The information required by Item 5 regarding FirstEnergy's market information, including stock exchange listings and quarterly stock market prices, dividends and holders of common stock is included on page 1 of FirstEnergy's 2007 Annual Report to Stockholders (Exhibit 13.1). Information for FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec is not required to be disclosed because they are wholly owned subsidiaries.

Information regarding compensation plans for which shares of FirstEnergy common stock may be issued is incorporated herein by reference to FirstEnergy's 2008 proxy statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.

 
35

 

The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock during the fourth quarter of 2007.

   
Period
   
October 1-31,
2007
 
November 1-30,
2007
 
December 1-31,
2007
 
Fourth Quarter
Total Number of Shares Purchased (a)
   
66,271    
    98,238         392,793         557,302      
Average Price Paid per Share
    $67.21         $71.81         $71.47         $71.02      
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
    -         -         -         -      
                           
(a)
Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the Executive and Director Incentive Compensation Plan and shares purchased as part of publicly announced plans.
   
       
(b)
On December 10, 2007, FirstEnergy's plan to repurchase up to 16 million shares of its common stock through June 30, 2008, was concluded.
   


ITEM 6. 
SELECTED FINANCIAL DATA

ITEM 7. 
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
ITEM 7A. 
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 8. 
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by Items 6 through 8 is incorporated herein by reference to Selected Financial Data, Management's Discussion and Analysis of Financial Condition and Results of Operation, and Financial Statements included on the following pages in the 2007 Annual Report of FirstEnergy (Exhibit 13.1) and the combined 2007 Annual Report of FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec (Exhibit 13.2).

 
Item 6*
Item 7*
Item 7A
Item 8
         
FirstEnergy
1-2
3-60
39-42
63-112
FES
N/A
N/A
3-5
  8-12, 91-145
OE
N/A
N/A
14-15
18-22, 91-145
CEI
N/A
N/A
24-25
28-32, 91-145
TE
N/A
N/A
34-35
38-42, 91-145
JCP&L
N/A
N/A
44-45
49-53, 91-145
Met-Ed
N/A
N/A
56-57
60-64, 91-145
Penelec
N/A
N/A
66-68
71-75, 91-145

 
*FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to Form 10-K.

ITEM 9. 
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 

None.

ITEM 9A. 
CONTROLS AND PROCEDURES -- FIRSTENERGY

Evaluation of Disclosure Controls and Procedures

FirstEnergy's Chief Executive Officer and Chief Financial Officer have reviewed and evaluated such registrants disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e), as of the end date covered by this report. Based upon this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that FirstEnergy's disclosure controls and procedures were effective as of December 31, 2007.

 
36

 

Management's Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control Integrated Framework, management conducted an evaluation of the effectiveness of FirstEnergy's internal control over financial reporting under the supervision of FirstEnergy's Chief Executive Officer and Chief Financial Officer. Based on that evaluation, management concluded that FirstEnergy's internal control over financial reporting was effective as of December 31, 2007. The effectiveness of FirstEnergy's internal control over financial reporting, as of December 31, 2007, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included in FirstEnergy's 2007 Annual Report to Stockholders and incorporated by reference hereto.

Changes in Internal Control over Financial Reporting

There were no changes in FirstEnergy's internal control over financial reporting during the fourth quarter of 2007 that have materially affected, or are reasonably likely to materially affect, FirstEnergy's internal control over financial reporting.

ITEM 9A(T). 
CONTROLS AND PROCEDURES -- FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec

Evaluation of Disclosure Controls and Procedures

Each registrant's Chief Executive Officer and Chief Financial Officer have reviewed and evaluated such registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 rules 13a-15(e) and 15d-15(e), as of the end date covered by this report. Based upon this evaluation, the respective Chief Executive Officer and Chief Financial Officer concluded that such registrant's disclosure controls and procedures were effective as of December 31, 2007.

Management's Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control Integrated Framework, management conducted an evaluation of the effectiveness of each registrants' internal control over financial reporting under the supervision of such registrant's Chief Executive Officer and Chief Financial Officer. Based on that evaluation, management concluded that each registrant's internal control over financial reporting was effective as of December 31, 2007. The effectiveness of each registrant's internal control over financial reporting, as of December 31, 2007, has not been audited by such registrant's independent registered public accounting firm.

Changes in Internal Control over Financial Reporting

There were no changes in the registrants' internal control over financial reporting during the fourth quarter of 2007 that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.

ITEM 9B. 
OTHER INFORMATION

None.

PART III

ITEM 10. 
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by Item 10, with respect to identification of FirstEnergy's directors and with respect to reports required to be filed under Section 16 of the Securities Exchange Act of 1934, is incorporated herein by reference to FirstEnergy's 2008 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934 and, with respect to identification of executive officers, to "Part I, Item 1. Business  Executive Officers" herein.

The Board of Directors has determined that Ernest J. Novak, Jr., an independent director, is the audit committee financial expert.

 
37

 

FirstEnergy makes available on its Web site at http://www.firstenergycorp.com/ir its Corporate Governance Policies and the charters for each of the following committees of the Board of Directors: Audit; Corporate Governance; Compensation; Finance; and Nuclear. The Corporate Governance Policies and Board committee charters are also available in print upon written request to Rhonda S. Ferguson, Corporate Secretary, FirstEnergy Corp., 76 South Main Street, Akron, OH 44308-1890.

FirstEnergy has adopted a Code of Business Conduct, which applies to all employees, including the Chief Executive Officer, the Chief Financial Officer and the Chief Accounting Officer. In addition, the Board of Directors has its own Code of Business Conduct. These Codes can be found on the Web site provided in the previous paragraph or upon written request to the Corporate Secretary.

Pursuant to Section 303A.12(a) of the New York Stock Exchange Listed Company Manual, the Company submitted the Annual CEO Certification to the NYSE on May 17, 2007.

ITEM 11.
EXECUTIVE COMPENSATION

ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by Items 11, 12 and 13 is incorporated herein by reference to FirstEnergy's 2008 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.

ITEM 14. 
PRINCIPAL ACCOUNTING FEES AND SERVICES

A summary of the audit and audit-related fees rendered by PricewaterhouseCoopers LLP for the years ended December 31, 2007 and 2006 are as follows:

   
Audit Fees(1)
 
Audit-Related Fees
 
Company
 
2007
 
2006
 
2007
 
2006
 
   
(In thousands)
 
FES
  $ 1,091   $ -   $ 494   $ -  
OE
    1,014     1,495     -     -  
CEI
    719     726     -     -  
TE
    540     643     -     -  
JCP&L
    701     816     -     -  
Met-Ed
    528     576     -     -  
Penelec
    586     576     -     -  
Other subsidiaries
    886     1,478     -     -  
Total FirstEnergy
  $ 6,065   $ 6,310   $ 494   $ -  
 
 
(1)
Professional services rendered for the audits of FirstEnergy's annual financial statements and reviews of financial statements included in FirstEnergy's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
 
 
Tax and Other Fees
 
There were no other fees billed to FirstEnergy for tax or other services for the years ended December 31, 2007 and 2006.

Additional information required by this item is incorporated herein by reference to FirstEnergy's 2008 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.

 
38

 

PART IV

ITEM 15. 
EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

1.     Financial Statements

Included in Part II of this report and incorporated herein by reference to the 2007 Annual Report of FirstEnergy (Exhibit 13.1) and the combined 2007 Annual Report of FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec (Exhibit 13.2) at the pages indicated.

 
FirstEnergy
 
FES
 
OE
 
CEI
 
TE
 
JCP&L
 
Met-Ed
 
Penelec
                 
Management Reports
61
6
16
26
36
47
58
69
Report of Independent Registered Public Accounting Firm
62
7
17
27
37
48
59
70
Statements of Income, Three Years Ended December 31, 2007
63
8
18
28
38
49
60
71
Balance Sheets, December 31, 2007 and 2006
64
9
19
29
39
50
61
72
Statements of Capitalization, December 31, 2007 and 2006
65-66
10
20
30
40
51
62
73
Statements of Common Stockholders Equity, Three Years Ended December 31, 2007
67
11
21
31
41
52
63
74
Statements of Cash Flows, Three Years Ended December 31, 2007
68
12
22
32
42
53
64
75
Notes to Financial Statements
69-112
91-145
91-145
91-145
91-145
91-145
91-145
91-145
 
2.
Financial Statement Schedules

Included in Part IV of this report:

 
FirstEnergy
 
FES
 
OE
 
CEI
 
TE
 
JCP&L
 
Met-Ed
 
Penelec
                 
Report of Independent Registered Public Accounting Firm
78
79
80
81
82
83
84
85
                 
Schedule II -- Consolidated Valuation and Qualifying Accounts, Three Years Ended December 31, 2007
86
87
88
89
90
91
92
93

Schedules other than the schedule listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto.

3.
Exhibits FirstEnergy

Exhibit
Number

3-1
Articles of Incorporation constituting FirstEnergy Corp.s Articles of Incorporation, dated September 17, 1996. (September 17, 1996 Form 8-K, Exhibit C)
   
    3-1(a)
Amended Articles of Incorporation of FirstEnergy Corp. (Registration No. 333-21011, Exhibit (3)-1)
   
3-2
Regulations of FirstEnergy Corp. (September 17, 1996 Form 8-K, Exhibit D)
   
    3-2(a)
FirstEnergy Corp. Amended Code of Regulations. (Registration No. 333-21011, Exhibit (3)-2)
   
4-1
Rights Agreement (December 1, 1997 Form 8-K, Exhibit 4.1)
   
4-2
FirstEnergy Corp. to The Bank of New York, Supplemental Indenture, dated November 7, 2001. (2001 Form 10-K, Exhibit 4-2)
   
(C)10-1        
FirstEnergy Corp. Executive and Director Incentive Compensation Plan, revised November 15, 1999. (1999 Form 10-K, Exhibit 10-1)
   
(C)10-2        
Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, revised November 15, 1999. (1999 Form 10-K, Exhibit 10-2)
   
(C)10-3        
Form of Employment, severance and change of control agreement between FirstEnergy Corp. and the following executive officers: L.L. Vespoli, C.B. Snyder, and R.H. Marsh, through December 31, 2005. (1999 Form 10-K, Exhibit 10-3)

 
39

 
Exhibit
Number
   
(C)10-4        
FirstEnergy Corp. Supplemental Executive Retirement Plan, amended January 1, 1999. (1999 Form 10-K, Exhibit 10-4)
   
(C)10-5        
FirstEnergy Corp. Executive Incentive Compensation Plan. (1999 Form 10-K, Exhibit 10-5)
   
(C)10-6        
Restricted stock agreement between FirstEnergy Corp. and A. J. Alexander. (1999 Form 10-K, Exhibit 10-6)
   
(C)10-7        
FirstEnergy Corp. Executive and Director Incentive Compensation Plan. (1998 Form 10-K, Exhibit 10-1)
   
(C)10-8        
Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, amended February 15, 1999. (1998 Form 10-K, Exhibit 10-2)
   
(C)10-9        
Restricted Stock Agreement between FirstEnergy Corp. and A. J. Alexander. (2000 Form 10-K, Exhibit 10-1)
   
(C)10-10        
Restricted Stock Agreement between FirstEnergy Corp. and H. P. Burg. (2000 Form 10-K, Exhibit 10-2)
   
(C)10-11        
Stock Option Agreement between FirstEnergy Corp. and officers dated November 22, 2000. (2000 Form 10-K, Exhibit 10-3)
   
(C)10-12        
Stock Option Agreement between FirstEnergy Corp. and officers dated March 1, 2000. (2000 Form 10-K, Exhibit 10-4)
   
(C)10-13        
Stock Option Agreement between FirstEnergy Corp. and director dated January 1, 2000. (2000 Form 10-K, Exhibit 10-5)
   
(C)10-14        
Stock Option Agreement between FirstEnergy Corp. and two directors dated January 1, 2001. (2000 Form 10-K, Exhibit 10-6)
   
(C)10-15        
Executive and Director Incentive Compensation Plan dated May 15, 2001. (2001 Form 10-K, Exhibit 10-1)
   
(C)10-16        
Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, revised September 18, 2000. (2001 Form 10-K, Exhibit 10-2)
   
(C)10-17        
Stock Option Agreements between FirstEnergy Corp. and Officers dated May 16, 2001. (2001 Form 10-K, Exhibit 10-3)
   
(C)10-18        
Form of Restricted Stock Agreements between FirstEnergy Corp. and Officers. (2001 Form 10-K, Exhibit 10-4)
   
(C)10-19        
Stock Option Agreements between FirstEnergy Corp. and One Director dated January 1, 2002. (2001 Form 10-K, Exhibit 10-5)
   
(C)10-20        
FirstEnergy Corp. Executive Deferred Compensation Plan. (2001 Form 10-K, Exhibit 10-6)
   
(C)10-21        
Executive Incentive Compensation Plan-Tier 2. (2001 Form 10-K, Exhibit 10-7)
   
(C)10-22        
Executive Incentive Compensation Plan-Tier 3. (2001 Form 10-K, Exhibit 10-8)
   
(C)10-23        
Executive Incentive Compensation Plan-Tier 4. (2001 Form 10-K, Exhibit 10-9)
   
(C)10-24        
Executive Incentive Compensation Plan-Tier 5. (2001 Form 10-K, Exhibit 10-10)
   
(C)10-25        
Amendment to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, effective April 5, 2001. (2001 Form 10-K, Exhibit 10-11)
   
(C)10-26        
Form of Amendment, effective November 7, 2001, to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, Deferred Remuneration Plan for Outside Directors of GPU, Inc., and Retirement Plan for Outside Directors of GPU, Inc. (2001 Form 10-K, Exhibit 10-12)
   
(C)10-27        
GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group, Inc. Employees. (2001 Form 10-K, Exhibit 10-13)

 
40

 
Exhibit
Number
   
(C)10-28        
Executive and Director Stock Option Agreement dated June 11, 2002. (2002 Form 10-K, Exhibit 10-1)
   
(C)10-29        
Director Stock Option Agreement. (2002 Form 10-K, Exhibit 10-2)
   
(C)10-30        
Executive and Director Executive Incentive Compensation Plan, Amendment dated May 21, 2002. (2002 Form 10-K, Exhibit 10-3)
   
(C)10-31        
Directors Deferred Compensation Plan, Revised Nov. 19, 2002. (2002 Form 10-K, Exhibit 10-4)
   
(C)10-32        
Executive Incentive Compensation Plan 2002. (2002 Form 10-K, Exhibit 10-5)
   
(C)10-33        
GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries as amended and restated to reflect amendments through June 3, 1999. (1999 Form 10-K, Exhibit 10-V, File No. 1-6047, GPU, Inc.)
   
(C)10-34        
Form of 1998 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (1997 Form 10-K, Exhibit 10-Q, File No. 1-6047, GPU, Inc.)
   
(C)10-35        
Form of 1999 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (1999 Form 10-K, Exhibit 10-W, File No. 1-6047, GPU, Inc.)
   
(C)10-36        
Form of 2000 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (2000 Form 10-K, Exhibit 10-W, File No. 1-6047, GPU, Inc.)
 
 
(C)10-37        
Deferred Remuneration Plan for Outside Directors of GPU, Inc. as amended and restated effective August 8, 2000. (2000 Form 10-K, Exhibit 10-O, File No. 1-6047, GPU, Inc.)
   
(C)10-38        
Retirement Plan for Outside Directors of GPU, Inc. as amended and restated as of August 8, 2000. (2000 Form 10-K, Exhibit 10-N, File No. 1-6047, GPU, Inc.)
 
 
(C)10-39        
Forms of Estate Enhancement Program Agreements entered into by certain former GPU directors. (1999 Form 10-K, Exhibit 10-JJ, File No. 1-6047, GPU, Inc.)
   
(C)10-40        
Deferred Compensation Plan for Outside Directors, effective November 7, 2001. (Exhibit 4(f), Form S-8, File No. 333-101472)
   
(C)10-41        
Employment Agreement between FirstEnergy and an officer dated July 20, 2004. (September 30, 2004 Form 10-Q, Exhibit 10-41)
   
(C)10-42        
Stock Option Agreement between FirstEnergy and an officer dated August 20, 2004.  (September 30, 2004 Form 10-Q, Exhibit 10-42)
   
(C)10-43        
Restricted Stock Agreement between FirstEnergy and an officer dated August 20, 2004. (September 30, 2004 Form 10-Q, Exhibit 10-43)
   
(C)10-44        
Executive Bonus Plan between FirstEnergy and Officers dated October 31, 2004. (September 30, 2004 Form 10-Q, Exhibit 10-44)
   
(C)10-45        
Form of Employment, Severance, and Change of Control Agreement, between FirstEnergy and A. J. Alexander. (2004 Form 10-K, Exhibit 10-12)
   
(C)10-46        
Form of Employment, Severance, and Change of Control Agreement, Tier 1, between FirstEnergy and the following executive officers: C.B. Snyder, L.L. Vespoli, and R.H. Marsh (effective January 1, 2006). (2004 Form 10-K, Exhibit 10-13)
   
(C)10-47        
Form of Employment, Severance, and Change of Control Agreement, Tier 1, between FirstEnergy and the following executive officers: L.M. Cavalier, M.T. Clark, and R.R. Grigg. (2004 Form 10-K, Exhibit 10-14)
   
(C)10-48        
Form of Employment, Severance, and Change of Control Agreement, Tier 2, between FirstEnergy and the following executive officers: K.J. Keough and K.W. Dindo (effective January 1, 2006). (2004 Form 10-K, Exhibit 10-15)

 
41

 
Exhibit
Number
   
(C)10-49        
Form of Employment, Severance, and Change of Control Agreement, Tier 2, between FirstEnergy and G. L. Pipitone. (2004 Form 10-K, Exhibit 10-16)
   
(C)10-50        
Executive and Director Incentive Compensation Plan, Amendment dated January 18, 2005. (2004 Form 10-K, Exhibit 10-3)
   
(C)10-51        
Form of Restricted Stock Agreements, between FirstEnergy and Officers. (2004 Form 10-K, Exhibit 10-4)
   
(C)10-52        
Form of Restricted Stock Unit Agreements (Performance Adjusted), between FirstEnergy and Officers. (2004 Form 10-K, Exhibit 10-5)
   
(C)10-53        
Form of Restricted Stock Agreement, between FirstEnergy and an officer. (2004 Form 10-K, Exhibit 10-6)
   
10-54  
Notice of Termination Tolling Agreement, Restated Partial Requirements Agreement (September 2005 10-Q, Exhibit 10-1)
   
10-55  
Agreement by and between FirstEnergy Generation Corp. and Bechtel Power Corporation dated August 26, 2005. (September 2005 10-Q, Exhibit 10-2)
   
10-56  
Consent Decree dated as of March 18, 2005. (Form 8-K dated March 18, 2005, Exhibit 10-1.)
   
10-57  
Deferred Prosecution Agreement entered into January 20, 2006 among FirstEnergy Nuclear Operating Company, U.S. Attorney's Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the Department of Justice. (Form 8-K dated January 20, 2006, Exhibit 99-2)
   
(D)10-58        
Form of Guaranty Agreement dated as of December 16, 2005 between FirstEnergy Corp. and FirstEnergy Solutions Corp. in Favor of Barclays Bank PLC as Administrative Agent for the Banks. (2005 Form 10-K, Exhibit 10-1)
 
 
(D)10-59        
Form of Trust Indenture dated as of December 1, 2005 between Ohio Water Development Authority and JP Morgan Trust Company related to issuance of FirstEnergy Nuclear Generation Corp. pollution control revenue refunding bonds. (2005 Form 10-K, Exhibit 10-3)
   
10-60  
GENCO Power Supply Agreement dated as of October 14, 2005 between FirstEnergy Generation Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer).  (2005 Form 10-K, Exhibit 10-5)
   
10-61  
Nuclear Power Supply Agreement dated as of October 14, 2005 between FirstEnergy Nuclear Generation Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer). (2005 Form 10-K, Exhibit 10-8)
   
(D)10-62        
Form of Letter of Credit and Reimbursement Agreement Dated as of December 16, 2005 among FirstEnergy Nuclear Generation Corp., and the Participating Banks and Barclays Bank PLC. (2005 Form 10-K, Exhibit 10-2)
   
(D)10-63        
Form of Waste Water Facilities and Solid Waste Facilities Loan Agreement Between Ohio Water Development Authority and FirstEnergy Nuclear Generation Corp., Dated as of December 1, 2005. (2005 Form 10-K, Exhibit 10-4)
   
10-64  
Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and The Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer) (2005 Form 10-K, Exhibit 10-6)
   
10-65  
Mansfield Power Supply Agreement dated as of October 14, 2005 between The Cleveland Electric Illuminating Company and The Toledo Edison Company (Sellers) and FirstEnergy Generation Corp. (Buyer) (2005 Form 10-K, Exhibit 10-7)
   
10-66  
Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and the FirstEnergy Operating Companies OE, CEI and TE (Buyers) (2005 Form 10-K, Exhibit 10-9)
   
10-67  
Electric Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and Pennsylvania Power Company (Buyer). (2005 Form 10-K, Exhibit 10-10)

 
42

 
Exhibit
Number
   
 (E)10-68        
Form of Guaranty Agreement dated as of April 3, 2006 by FirstEnergy Corp. in favor of the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent, under the related Letter of Credit and Reimbursement Agreement. (March 2006 10-Q, Exhibit 10-1)
   
(E)10-69        
Form of Letter of Credit and Reimbursement Agreement dated as of April 3, 2006 among FirstEnergy Generation Corp., the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent. (March 2006 10-Q, Exhibit 10-2)
   
(E)10-70        
Form of Trust Indenture dated as of April 1, 2006 between the Ohio Water Development Authority and The Bank of New York Trust Company, N.A. as Trustee securing pollution control revenue refunding bonds issued on behalf of FirstEnergy Generation Corp. (March 2006 10-Q, Exhibit 10-3)
   
(E)10-71        
Form of Waste Water Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Generation Corp. dated as of April 1, 2006. (March 2006 10-Q, Exhibit 10-4)
   
(C)10-72        
Form of Restricted Stock Agreement between FirstEnergy and A. J. Alexander, dated February 27, 2006. (March 2006 10-Q, Exhibit 10-6)
   
(C)10-73        
Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy and A.J. Alexander, dated March 1, 2006. (March 2006 10-Q, Exhibit 10-7)
   
(C)10-74        
Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy and named executive officers, dated March 1, 2006. (March 2006 10-Q, Exhibit 10-8)
   
(C)10-75        
Form of Restricted Stock Unit Agreement (Discretionary) between FirstEnergy and R.H. Marsh, dated March 1, 2006. (March 2006 10-Q, Exhibit 10-9)
   
10-76  
Confirmation dated August 9, 2006 between FirstEnergy Corp and JP Morgan Chase Bank National Association (September 2006 10-Q, Exhibit 10-1)
   
(F)10-77        
Form of Trust Indenture dated as of December 1, 2006 between the Ohio Water Development Authority and The Bank of New York Trust Company, N.A. as Trustee securing State of Ohio Pollution Control Revenue Refunding Bonds (FirstEnergy Nuclear Generation Corp. Project) (2006 Form 10-K, Exhibit 10.1)
   
(G)10-78        
Form of Supplemental Letter of Credit Agreement, dated as of December 5, 2006 among FirstEnergy Corp., FirstEnergy Generation Corp. and Barclays Bank PLC, as Fronting Bank (FirstEnergy Generation Corp. Project) (2006 Form 10-K, Exhibit 10.2)
 
 
10-79  
Form of Letter of Credit and Reimbursement Agreement dated as of December 28, 2006 among FirstEnergy Corp., as Obligor, The Lenders Named Herein, as Lender, and Wachovia Fixed Income Structured Trading Solutions, LLC as Administrative Agent and as Fronting Bank (2006 Form 10-K, Exhibit 10.3)
   
(F)10-80        
Form of Waste Water Facilities and Solid Waste Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Nuclear Generation Corp. dated as of December 1, 2006. (2006 Form 10-K, Exhibit 10.4)
   
(C)10-81        
Amendment to Employment Agreement for Richard R. Grigg dated January 16, 2007. (2006 Form 10-K, Exhibit 10.5)
   
10-82  
Confirmation dated March 1, 2007 between FirstEnergy Corp. and Morgan Stanley and Co., International Limited. (March 2007 10-Q, Exhibit 10.1)
 
 
10-83  
Form of U.S. $250,000,000 Credit Agreement, dated as of March 2, 2007, between FirstEnergy Corp., as Borrower, and Morgan Stanley Senior Funding, Inc., as Lender. (March 2007 10-Q, Exhibit 10.2)
   

 
43

 
 
Exhibit
Number
 
10-84  
Form of Guaranty dated as of March 2, 2007, between FirstEnergy Corp., as Guarantor, and Morgan Stanley Senior Funding, Inc., as Lender under a U.S. $250,000,000 Credit Agreement dated as of March 2, 2007, with FirstEnergy Solutions Corp., as Borrower. (March 2007 10-Q, Exhibit 10.2)
   
(C)10-85        
FirstEnergy Corp. Executive Deferred Compensation Plan as amended September 18, 2007 (September 2007 10-Q, Exhibit 10.2)
   
(C)10-86        
FirstEnergy Corp. Supplemental Executive Retirement Plan as amended September 18, 2007 (September 2007 10-Q, Exhibit 10.3)

(A) (C) 10-87 
Form of Special Severance Agreements of the Chief Executive Officer, Chief Financial Officer and certain other members of senior management, including some of the other named executive officers
 
(A) (C) 10-88
Employment Agreement between FirstEnergy Corp. and Gary R. Leidich, dated February 26, 2008
   
(A) (C) 10-89
Amendment to Employment Agreement between FirstEnergy Corp. and Richard R. Grigg, dated February 26, 2008
   
(A) (C) 10-90
Form of Restricted Stock Unit Agreement for Gary R. Leidich (per Employment Agreement dated February 26, 2008)
   
(A) (C) 10-91
Form of Restricted Stock Agreement Amendment for Gary R. Leidich dated February 26, 2008
   
(A) (C) 10-92
Form of Restricted Stock Unit Agreement for Richard R. Grigg (per Employment Agreement dated February 26, 2008)
   
(A) (C) 10-93
Form of Restricted Stock Unit Agreement for named executive officers dated March 3, 2008
   
(A) (C) 10-94
Form of 2007 Incentive Compensation Plan Performance Share Award for the performance period January 1, 2008 to December 31, 2010
 
(A)12.1            
Consolidated fixed charge ratios.
   
(A)13.1            
FirstEnergy 2007 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10K are to be deemed filed with the SEC.)
   
(A)21               
List of Subsidiaries of the Registrant at December 31, 2007.
   
(A)23.1            
Consent of Independent Registered Public Accounting Firm.
   
(A)31.1            
Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
   
(A)31.2            
Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
   
(A)32               
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. 1350.
 
 
(A)                   
Provided herein in electronic format as an exhibit.
   
(C)                   
Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.
   
(D)                   
Four substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to four other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority, the Ohio Air Quality Authority and Beaver County Industrial Development Authority, Pennsylvania, relating to pollution control notes of FirstEnergy Nuclear Generation Corp.
   
(E)                   
Three substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to three other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority and the Beaver County Industrial Development Authority relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp.
 
 
44

 
Exhibit
Number
 
 
(F)                   
Seven substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to one other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority, three other series of pollution control bonds issued by the Ohio Air Quality Development Authority and the three other series of pollution control bonds issued by the Beaver County Industrial Development Authority, relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp.