10-K

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).

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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.

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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.

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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.

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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 GHGEmissions 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.

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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.

(G)

Two substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to two other series of pollution control revenue refunding bonds issued by the Ohio Air Quality Development Authority, and the Beaver County Industrial Development Authority relating to pollution control notes of FirstEnergy Generation Corp.

3. Exhibits - FES

3-1	Articles of Incorporation of FirstEnergy Solutions Corp., as amended August 31, 2001 (Form S-4 dated August 6, 2007, Exhibit 3.1)
3-2	Code of Regulations of FirstEnergy Solutions Corp. (Form S-4 dated August 6, 2007, Exhibit 3.4)

10-1	Form of 6.85% Exchange Certificate due 2034 (Form S-4 dated August 6, 2007, Exhibit 4.1)
10-2	Guaranty of FirstEnergy Solutions Corp., dated as of July 1, 2007 (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-9)
10-3	Indenture of Trust, Open-End Mortgage and Security Agreement, dated as of July 1, 2007, between the applicable Lessor and The Bank of New York Trust Company, N.A., as Indenture Trustee (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-3)
10-4	6.85% Lessor Note due 2034 (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-3)
10-5	Registration Rights Agreement, dated as of July 13, 2007, among FirstEnergy Generation Corp., FirstEnergy Solutions Corp., The Bank of New York Trust Company, N.A., as Pass Through Trustee, Morgan Stanley & Co. Incorporated, and Credit Suisse Securities (USA) LLC, as representatives of the several initial purchasers named in the Purchase Agreement (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-14)
10-6	Participation Agreement, dated as of June 26, 2007, among FirstEnergy Generation Corp., as Lessee, FirstEnergy Solutions Corp., as Guarantor, the applicable Lessor, U.S. Bank Trust National Association, as Trust Company, the applicable Owner Participant, The Bank of New York Trust Company, N.A., as Indenture Trustee, and The Bank of New York Trust Company, N.A., as Pass Through Trustee (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-1)
10-7	Trust Agreement, dated as of June 26, 2007, between the applicable Owner Participant and U.S. Bank Trust National Association, as Owner Trustee (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-2)
10-8	Pass Through Trust Agreement, dated as of June 26, 2007, among FirstEnergy Generation Corp., FirstEnergy Solutions Corp., and The Bank of New York Trust Company, N.A., as Pass Through Trustee (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-12)

45

Exhibit

Number

10-9	Bill of Sale and Transfer, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-5)
10-10	Facility Lease Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-6)
10-11	Site Lease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-7)
10-12	Site Sublease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-8)
10-13	Support Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-10)

10-14	Second Amendment to the Bruce Mansfield Units 1, 2, and 3 Operating Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp., The Cleveland Electric Illuminating Company and The Toledo Edison Company (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-11)
10-15	OE Fossil Purchase and Sale Agreement by and between Ohio Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser) (Form 10-Q filed August 1, 2005 by FirstEnergy Corp. (333-21011), Exhibit 10.2)
10-16	CEI Fossil Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company (Seller) and FirstEnergy Generation Corp. (Purchaser) (Form 10-Q filed August 1, 2005 by FirstEnergy Corp. (333-21011), Exhibit 10.6)
10-17	TE Fossil Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser) (Form 10-Q filed August 1, 2005 by FirstEnergy Corp. (333-21011), Exhibit 10.2)
10-18	Agreement, dated August 26, 2005, by and between FirstEnergy Generation Corp. and Bechtel Power Corporation (Form 10-Q filed November 2, 2005 by FirstEnergy Corp., (333-21011), Exhibit 10-2)
10-19	CEI Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.15)
10-20	CEI Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Cleveland Electric Illuminating Company (Form S-4/A dated August 20, 2007, Exhibit 10.16)
10-21	OE Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.17)
10-22	OE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and Ohio Edison Company (Form S-4/A dated August 20, 2007, Exhibit 10.18)

46

Exhibit

Number

10-23	Amendment No. 1 to OE Fossil Security Agreement, dated as of June 30, 2007, between FirstEnergy Generation Corp. and Ohio Edison Company (Form S-4/A dated August 20, 2007, Exhibit 10.19)
10-24	PP Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.20)
10-25	PP Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and Pennsylvania Power Company (Form S-4/A dated August 20, 2007, Exhibit 10.21)
10-26	Amendment No. 1 to PP Fossil Security Agreement, dated as of June 30, 2007, between FirstEnergy Generation Corp. and Pennsylvania Power Company (Form S-4/A dated August 20, 2007, Exhibit 10.22)
10-27	TE Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.23)
10-28	TE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Toledo Edison Company (Form S-4/A dated August 20, 2007, Exhibit 10.24)

10-29	CEI Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.25)
10-30	CEI Nuclear Security Agreement, dated December 16, 2005, by and between FirstEnergy Nuclear Generation Corp. and The Cleveland Electric Illuminating Company (Form S-4/A dated August 20, 2007, Exhibit 10.26)
10-31	OE Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.27)
10-32	PP Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.28)
10-33	TE Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.29)
10-34	TE Nuclear Security Agreement, dated December 16, 2005, by and between FirstEnergy Nuclear Generation Corp. and The Toledo Edison Company (Form S-4/A dated August 20, 2007, Exhibit 10.30)
10-35	Mansfield Power Supply Agreement, dated August 10, 2006, among The Cleveland Electric Illuminating Company, The Toledo Edison Company and FirstEnergy Generation Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.31)
10-36	Nuclear Power Supply Agreement, dated August 10, 2006, between FirstEnergy Nuclear Generation Corp. and FirstEnergy Solutions Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.32)
10-37	Revised Power Supply Agreement, dated December 8, 2006, among FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company (Form S-4/A dated August 20, 2007, Exhibit 10.34)

47

Exhibit

Number

10-38	Second Restated Partial Requirements Agreement, dated January 1, 2007, among Metropolitan Edison Company, Pennsylvania Electric Company, The Waverly Electric Power and Light Company and FirstEnergy Solutions Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.35)
10-39	GENCO Power Supply Agreement, dated January 1, 2007, between FirstEnergy Generation Corp. and FirstEnergy Solutions Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.36)
10-40	Form of U.S. $250,000,000 Credit Agreement, dated as of March 2, 2007, between FirstEnergy Solutions Corp., as Borrower, and Morgan Stanley Senior Funding, Inc., as Lender (Form 10-Q filed May 9, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-2)
10-41	Form of Guaranty dated as of March 2, 2007, between FirstEnergy Corp., as Guarantor, and Morgan Stanley Senior Funding, Inc., as Lender under the U.S. $250,000,000 Credit Agreement, dated as of March 2, 2007, with FirstEnergy Solutions Corp., as Borrower (Form 10-Q filed May 9, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-3)
10-42	Guaranty, dated as of March 26, 2007, by FirstEnergy Generation Corp. on behalf of FirstEnergy Solutions Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.39)
10-43	Guaranty, dated as of March 26, 2007, by FirstEnergy Solutions Corp. on behalf of FirstEnergy Generation Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.40)

10-44	Guaranty, dated as of March 26, 2007, by FirstEnergy Solutions Corp. on behalf of FirstEnergy Nuclear Generation Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.41)
10-45	Guaranty, dated as of March 26, 2007, by FirstEnergy Nuclear Generation Corp. on behalf of FirstEnergy Solutions Corp. (Form S-4/A dated August 20, 2007, Exhibit 10.42)
10-46	Consent Decree dated March 18, 2005 (Form 8-K dated March 18, 2005 by FirstEnergy Corp. (333-21011), Exhibit 10.1)
10-47	Amendment to Agreement for Engineering, Procurement and Construction of Air Quality Control Systems by and between FirstEnergy Generation Corp. and Bechtel Power Corporation dated September 14, 2007 (September 2007 10-Q, Exhibit 10.1)
(A)10-48	Asset Purchase Agreement by and between Calpine Corporation, as Seller, and FirstEnergy Generation Corp., as Buyer, dated as of January 28, 2008
(A)12.2	Consolidated Fixed Charged Ratios.
(A)13.2	FES 2007 Annual Report to Stockholders (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed filed with the SEC.)
(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.

48

Exhibit

Number

3.      Exhibits OE

2-1	Agreement and Plan of Merger, dated as of September 13, 1996, between Ohio Edison Company (OE) and Centerior Energy Corporation. (September 17, 1996 Form 8K, Exhibit 21)
3-1	Amended Articles of Incorporation, Effective June 21, 1994, constituting OEs Articles of Incorporation. (1994 Form 10K, Exhibit 31).
3-2	Amendment to Articles of Incorporation, Effective November 12, 1999 (2004 Form 10-K, Exhibit 3-2).
3-3	Amended and Restated Code of Regulations, amended March 15, 2002. (2001 Form 10-K, Exhibit 3-2).
(A)3-4	Amended and Restated Articles of Incorporation of Ohio Edison Company, Effective December 18, 2007
(A)3-5	Amended and Restated Code of Regulation of Ohio Edison Company, dated December 14, 2007
(B)4-1	Indenture dated as of August 1, 1930 between OE and Bankers Trust Company (now the Bank of New York), as Trustee, as amended and supplemented by Supplemental Indentures:

49

Exhibit

Number

		Incorporated by
		Reference to
Dated as of	File Reference	Exhibit No.
March 3, 1931	2-1725	B1, B-1(a),B-1(b)
November 1, 1935	2-2721	B-4
January 1, 1937	2-3402	B-5
September 1, 1937	Form 8-A	B-6
June 13, 1939	2-5462	7(a)-7
August 1, 1974	Form 8-A, August 28, 1974	2(b)
July 1, 1976	Form 8-A, July 28, 1976	2(b)
December 1, 1976	Form 8-A, December 15, 1976	2(b)
June 15, 1977	Form 8-A, June 27, 1977	2(b)
Supplemental Indentures:
September 1, 1944	2-61146	2(b)(2)
April 1, 1945	2-61146	2(b)(2)
September 1, 1948	2-61146	2(b)(2)
May 1, 1950	2-61146	2(b)(2)
January 1, 1954	2-61146	2(b)(2)
May 1, 1955	2-61146	2(b)(2)
August 1, 1956	2-61146	2(b)(2)
March 1, 1958	2-61146	2(b)(2)
April 1, 1959	2-61146	2(b)(2)
June 1, 1961	2-61146	2(b)(2)
September 1, 1969	2-34351	2(b)(2)
May 1, 1970	2-37146	2(b)(2)
September 1, 1970	2-38172	2(b)(2)
June 1, 1971	2-40379	2(b)(2)
August 1, 1972	2-44803	2(b)(2)
September 1, 1973	2-48867	2(b)(2)
May 15, 1978	2-66957	2(b)(4)
February 1, 1980	2-66957	2(b)(5)
		Incorporated by
		Reference to
Dated as of	File Reference	Exhibit No.
April 15, 1980	2-66957	2(b)(6)
June 15, 1980	2-68023	(b)(4)(b)(5)
October 1, 1981	2-74059	(4)(d)
October 15, 1981	2-75917	(4)(e)
February 15, 1982	2-75917	(4)(e)
July 1, 1982	2-89360	(4)(d)
March 1, 1983	2-89360	(4)(e)
March 1, 1984	2-89360	(4)(f)
September 15, 1984	2-92918	(4)(d)
September 27, 1984	33-2576	(4)(d)
November 8, 1984	33-2576	(4)(d)
December 1, 1984	33-2576	(4)(d)
December 5, 1984	33-2576	(4)(e)
January 30, 1985	33-2576	(4)(e)
February 25, 1985	33-2576	(4)(e)
July 1, 1985	33-2576	(4)(e)
October 1, 1985	33-2576	(4)(e)
January 15, 1986	33-8791	(4)(d)
May 20, 1986	33-8791	(4)(d)
June 3, 1986	33-8791	(4)(e)
October 1, 1986	33-29827	(4)(d)
August 25, 1989	33-34663	(4)(d)
February 15, 1991	33-39713	(4)(d)
May 1, 1991	33-45751	(4)(d)
May 15, 1991	33-45751	(4)(d)
September 15, 1991	33-45751	(4)(d)
April 1, 1992	33-48931	(4)(d)
June 15, 1992	33-48931	(4)(d)
September 15, 1992	33-48931	(4)(e)
April 1, 1993	33-51139	(4)(d)

50

Exhibit

Number

June 15, 1993	33-51139	(4)(d)
September 15, 1993	33-51139	(4)(d)
November 15, 1993	1-2578	(4)(2)
April 1, 1995	1-2578	(4)(2)
May 1, 1995	1-2578	(4)(2)
July 1, 1995	1-2578	(4)(2)
June 1, 1997	1-2578	(4)(2)
April 1, 1998	1-2578	(4)(2)
June 1, 1998	1-2578	(4)(2)
September 29, 1999	1-2578	(4)(2)
April 1, 2000	1-2578	(4)(2)(a)
April 1, 2000	1-2578	(4)(2)(b)
June 1, 2001	1-2578
February 1, 2003	1-2578	4(2)
March 1, 2003	1-2578	4(2)
August 1, 2003	1-2578	4(2)
June 1, 2004	1-2578	4(2)
June 1, 2004	1-2578	4(2)
December 1, 2004	1-2578	4(2)
April 1, 2005	1-2578	4(2)
April 15, 2005	1-2578	4(2)
June 1, 2005	1-2578	4(2)

(B) 4-2 General Mortgage Indenture and Deed of Trust dated as of January 1, 1998 between OE and the Bank of New York, as Trustee, as amended and supplemented by Supplemental Indentures; (Registration No. 333-05277, Exhibit 4(g)).

February 1, 2003	1-2578	4-2
March 1, 2003	1-2578	4-2
August 1, 2003	1-2578	4-2
June 1, 2004	1-2578	4-2
June 1, 2004	1-2578	4-2
December 1, 2004	1-2578	4-2
April 1, 2005	1-2578	4(2)
April 15, 2005	1-2578	4(2)
June 1, 2005	1-2578	4(2)

4-3	Indenture dated as of April 1, 2003 between OE and The Bank of New York, as Trustee.
4-4	Officers Certificate (including the forms of the 6.40% Senior Notes due 2016 and the 6.875% Senior Notes due 2036), dated June 21, 2006. (Form 8-K dated June 26, 2006, Exhibit 4)
10-1	Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(2)
10-2	Amendment No. 1 dated January 4, 1974 to Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-68906, Exhibit 5(c)(3))
10-3	Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(3))
10-4	Amendment No. 1 dated as of January 1, 1993 to Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (1993 Form 10-K, Exhibit 10-4)
10-5	Agreement for the Termination or Construction of Certain Agreements effective September 1, 1980 among the CAPCO Group. (Registration No. 2-68906, Exhibit 10-4)
10-6	Amendment dated as of December 23, 1993 to Agreement for the Termination or Construction of Certain Agreements effective September 1, 1980 among the CAPCO Group. (1993 Form 10-K, Exhibit 10-6)
10-7	CAPCO Basic Operating Agreement, as amended September 1, 1980. (Registration No. 2-68906, Exhibit 10-5)

51

Exhibit

Number

10-8	Amendment No. 1 dated August 1, 1981, and Amendment No. 2 dated September 1, 1982 to CAPCO Basic Operating Agreement, as amended September 1, 1980. (September 30, 1981 Form 10-Q, Exhibit 20-1 and 1982 Form 10-K, Exhibit 19-3, respectively)
10-9	Amendment No. 3 dated July 1, 1984 to CAPCO Basic Operating Agreement, as amended September 1, 1980. (1985 Form 10-K, Exhibit 10-7)
10-10	Basic Operating Agreement between the CAPCO Companies as amended October 1, 1991. (1991 Form 10-K, Exhibit 10-8)
10-11	Basic Operating Agreement between the CAPCO Companies as amended January 1, 1993. (1993 Form 10-K, Exhibit 10-11)
10-12	Memorandum of Agreement effective as of September 1, 1980 among the CAPCO Group. (1982 Form 10-K, Exhibit 19-2)
10-13	Operating Agreement for Beaver Valley Power Station Units Nos. 1 and 2 as Amended and Restated September 15, 1987, by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 10-15)
10-14	Construction Agreement with respect to Perry Plant between the CAPCO Group dated as of July 22, 1974. (Registration No. 2-52251 of Toledo Edison Company, Exhibit 5(yy))
10-15	Amendment No. 3 dated as of October 31, 1980 to the Bond Guaranty dated as of October 1, 1973, as amended, with respect to the CAPCO Group. (Registration No. 2-68906 of Pennsylvania Power Company, Exhibit 10-16)
10-16	Amendment No. 4 dated as of July 1, 1985 to the Bond Guaranty dated as October 1, 1973, as amended, by the CAPCO Companies to National City Bank as Bond Trustee. (1985 Form 10-K, Exhibit 10-30)
10-17	Amendment No. 5 dated as of May 1, 1986, to the Bond Guaranty by the CAPCO Companies to National City Bank as Bond Trustee. (1986 Form 10-K, Exhibit 10-33)
10-18	Amendment No. 6A dated as of December 1, 1991, to the Bond Guaranty dated as of October 1, 1973, by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (1991 Form 10-K, Exhibit 10-33)
10-19	Amendment No. 6B dated as of December 30, 1991, to the Bond Guaranty dated as of October 1, 1973 by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (1991 Form 10-K, Exhibit 10-34)
10-20	Bond Guaranty dated as of December 1, 1991, by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (1991 Form 10-K, Exhibit 10-35)
10-21	Memorandum of Understanding dated March 31, 1985 among the CAPCO Companies. (1985 Form 10-K, Exhibit 10-35)
(C)10-22	Ohio Edison System Executive Supplemental Life Insurance Plan. (1995 Form 10-K, Exhibit 10-44)
(C)10-23	Ohio Edison System Executive Incentive Compensation Plan. (1995 Form 10-K, Exhibit 10-45.)
(C)10-24	Ohio Edison System Restated and Amended Executive Deferred Compensation Plan. (1995 Form 10-K, Exhibit 10-46.)
(C)10-25	Ohio Edison System Restated and Amended Supplemental Executive Retirement Plan. (1995 Form 10-K, Exhibit 10-47.)

52

Exhibit

Number

(C)10-28	Severance pay agreement between Ohio Edison Company and A. J. Alexander. (1995 Form 10-K, Exhibit 10-50.)
(D)10-30	Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Hereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-1.)
(D)10-31	Amendment No. 1 dated as of September 1, 1987 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company (now The Bank of New York), as Indenture Trustee, and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-46.)
(D)10-32	Amendment No. 3 dated as of May 16, 1988 to Participation Agreement dated as of March 16, 1987, as amended among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-47.)
(D)10-33	Amendment No. 4 dated as of November 1, 1991 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-47.)
(D)10-34	Amendment No. 5 dated as of November 24, 1992 to Participation Agreement dated as of March 16, 1987, as amended, among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company as Lessee. (1992 Form 10-K, Exhibit 10-49.)
(D)10-35	Amendment No. 6 dated as of January 12, 1993 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-50.)
(D)10-36	Amendment No. 7 dated as of October 12, 1994 to Participation Agreement dated as of March 16, 1987 as amended, among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-54.)
(D)10-37	Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (1986 Form 10-K, Exhibit 28-2.)
(D)10-38	Amendment No. 1 dated as of September 1, 1987 to Facility Lease dated as of March 16, 1997 between The First National Bank of Boston, as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-49.)
(D)10-39	Amendment No. 2 dated as of November 1, 1991, to Facility Lease dated as of March 16, 1987, between The First National Bank of Boston, as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-50.)
(D)10-40	Amendment No. 3 dated as of November 24, 1992 to Facility Lease dated as March 16, 1987 as amended, between The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited partnership, as Owner Participant and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-54.)

53

Exhibit

Number

(D)10-41	Amendment No. 4 dated as of January 12, 1993 to Facility Lease dated as of March 16, 1987 as amended, between, The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-59.)
(D)10-42	Amendment No. 5 dated as of October 12, 1994 to Facility Lease dated as of March 16, 1987 as amended, between, The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-60.)
(D)10-43	Letter Agreement dated as of March 19, 1987 between Ohio Edison Company, Lessee, and The First National Bank of Boston, Owner Trustee under a Trust dated March 16, 1987 with Chase Manhattan Realty Leasing Corporation, required by Section 3(d) of the Facility Lease. (1986 Form 10-K, Exhibit 28-3.)
(D)10-44	Ground Lease dated as of March 16, 1987 between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with the Owner Participant, Tenant. (1986 Form 10-K, Exhibit 28-4.)
(D)10-45	Trust Agreement dated as of March 16, 1987 between Perry One Alpha Limited Partnership, as Owner Participant, and The First National Bank of Boston. (1986 Form 10-K, Exhibit 28-5.)
(D)10-46	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of March 16, 1987 with Perry One Alpha Limited Partnership, and Irving Trust Company, as Indenture Trustee. (1986 Form 10-K, Exhibit 28-6.)
(D)10-47	Supplemental Indenture No. 1 dated as of September 1, 1987 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee and Irving Trust Company (now The Bank of New York), as Indenture Trustee. (1991 Form 10-K, Exhibit 10-55.)
(D)10-48	Supplemental Indenture No. 2 dated as of November 1, 1991 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and The Bank of New York, as Indenture Trustee. (1991 Form 10-K, Exhibit 10-56.)
(D)10-49	Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-7.)
(D)10-50	Amendment No. 1 dated as of November 1, 1991 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (1991 Form 10-K, Exhibit 10-58.)
(D)10-51	Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (1994 Form 10-K, Exhibit 10-69.)
(D)10-52	Amendment No. 3 dated as of October 12, 1994 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (1994 Form 10-K, Exhibit 10-70.)
(D)10-53	Partial Mortgage Release dated as of March 19, 1987 under the Indenture between Ohio Edison Company and Bankers Trust Company, as Trustee, dated as of the 1st day of August 1930. (1986 Form 10-K, Exhibit 28-8.)
(D)10-54	Assignment, Assumption and Further Agreement dated as of March 16, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (1986 Form 10-K, Exhibit 28-9.)

54

Exhibit

Number

(D)10-55	Additional Support Agreement dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, and Ohio Edison Company. (1986 Form 10-K, Exhibit 28-10.)
(D)10-56	Bill of Sale, Instrument of Transfer and Severance Agreement dated as of March 19, 1987 between Ohio Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership. (1986 Form 10-K, Exhibit 28-11.)
(D)10-57	Easement dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, Grantee. (1986 Form 10-K, File Exhibit 28-12.)
10-58	Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Hereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1986 Form 10-K, as Exhibit 28-13.)
10-59	Amendment No. 1 dated as of September 1, 1987 to Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, The Original Loan Participants Listed in Schedule 1 thereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-65.)
10-60	Amendment No. 4 dated as of November 1, 1991, to Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-66.)
10-61	Amendment No. 5 dated as of November 24, 1992 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNNP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-71.)
10-62	Amendment No. 6 dated as of January 12, 1993 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-80.)
10-63	Amendment No. 7 dated as of October 12, 1994 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-81.)
10-64	Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, Lessor, and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-14.)
10-65	Amendment No. 1 dated as of September 1, 1987 to Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-68.)

55

Exhibit

Number

10-66	Amendment No. 2 dated as of November 1, 1991 to Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-69.)
10-67	Amendment No. 3 dated as of November 24, 1992 to Facility Lease dated as of March 16, 1987, as amended, between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-75.)
10-68	Amendment No. 4 dated as of January 12, 1993 to Facility Lease dated as of March 16, 1987 as amended between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-76.)
10-69	Amendment No. 5 dated as of October 12, 1994 to Facility Lease dated as of March 16, 1987 as amended between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-87.)
10-70	Letter Agreement dated as of March 19, 1987 between Ohio Edison Company, as Lessee, and The First National Bank of Boston, as Owner Trustee under a Trust, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, required by Section 3(d) of the Facility Lease. (1986 Form 10-K, Exhibit 28-15.)
10-71	Ground Lease dated as of March 16, 1987 between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, Tenant. (1986 Form 10-K, Exhibit 28-16.)
10-72	Trust Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation, as Owner Participant, and The First National Bank of Boston. (1986 Form 10-K, Exhibit 28-17.)
10-73	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, and Irving Trust Company, as Indenture Trustee. (1986 Form 10-K, Exhibit 28-18.)
10-74	Supplemental Indenture No. 1 dated as of September 1, 1987 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and Irving Trust Company (now The Bank of New York), as Indenture Trustee. (1991 Form 10-K, Exhibit 10-74.)
10-75	Supplemental Indenture No. 2 dated as of November 1, 1991 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and The Bank of New York, as Indenture Trustee. (1991 Form 10-K, Exhibit 10-75.)
10-76	Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-19.)
10-77	Amendment No. 1 dated as of November 1, 1991 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (1991 Form 10-K, Exhibit 10-77.)
10-78	Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (1994 Form 10-K, Exhibit 10-96.)
10-79	Amendment No. 3 dated as of October 12, 1994 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (1994 Form 10-K, Exhibit 10-97.)

56

Exhibit

Number

10-80	Assignment, Assumption and Further Agreement dated as of March 16, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (1986 Form 10-K, Exhibit 28-20.)
10-81	Additional Support Agreement dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, and Ohio Edison Company. (1986 Form 10-K, Exhibit 28-21.)
10-82	Bill of Sale, Instrument of Transfer and Severance Agreement dated as of March 19, 1987 between Ohio Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, Buyer. (1986 Form 10-K, Exhibit 28-22.)
10-83	Easement dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, Grantee. (1986 Form 10-K, Exhibit 28-23.)
10-84	Refinancing Agreement dated as of November 1, 1991 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee, The Bank of New York, as Collateral Trust Trustee, The Bank of New York, as New Collateral Trust Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-82.)
10-85	Refinancing Agreement dated as of November 1, 1991 among Security Pacific Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee, The Bank of New York, as Collateral Trust Trustee, The Bank of New York as New Collateral Trust Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-83.)
10-86	Ohio Edison Company Master Decommissioning Trust Agreement for Perry Nuclear Power Plant Unit One, Perry Nuclear Power Plant Unit Two, Beaver Valley Power Station Unit One and Beaver Valley Power Station Unit Two dated July 1, 1993. (1993 Form 10-K, Exhibit 10-94.)
10-87	Nuclear Fuel Lease dated as of March 31, 1989, between OES Fuel, Incorporated, as Lessor, and Ohio Edison Company, as Lessee. (1989 Form 10-K, Exhibit 10-62.)
10-89	Guarantee Agreement entered into by Ohio Edison Company dated as of January 17, 1991. (1990 Form 10-K, Exhibit 10-64.)
(E)10-90	Participation Agreement dated as of September 15, 1987, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company as Lessee. (1987 Form 10-K, Exhibit 28-1.)
(E)10-91	Amendment No. 1 dated as of February 1, 1988, to Participation Agreement dated as of September 15, 1987, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-2.)
(E)10-92	Amendment No. 3 dated as of March 16, 1988 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-99.)

57

Exhibit

Number

(E)10-93	Amendment No. 4 dated as of November 5, 1992 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10K, Exhibit 10100.)
(E)10-94	Amendment No. 5 dated as of September 30, 1994 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-118.)
(E)10-95	Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-3.)
(E)10-96	Amendment No. 1 dated as of February 1, 1988, to Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (1987 Form 10K, Exhibit 284.)
(E)10-97	Amendment No. 2 dated as of November 5, 1992, to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10103.)
(E)10-98	Amendment No. 3 dated as of September 30, 1994 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10122.)
(E)10-99	Ground Lease and Easement Agreement dated as of September 15, 1987, between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, Tenant. (1987 Form 10-K, Exhibit 285.)
(E)10-100	Trust Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Limited Partnership, as Owner Participant, and The First National Bank of Boston. (1987 Form 10K, Exhibit 286.)
(E)10-101	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-7.)
(E)10-102	Supplemental Indenture No. 1 dated as of February 1, 1988 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with Beaver Valley Two Pi Limited Partnership and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-8.)
(E)10-103	Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-9.)
(E)10-104	Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-128.)
(E)10-105	Amendment No. 2 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-129.)

58

Exhibit

Number

(E)10-106	Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-10.)
(E)10-107	Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-131.)
(E)10-108	Amendment No. 2 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-132.)
(E)10-109	Assignment, Assumption and Further Agreement dated as of September 15, 1987, among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (1987 Form 10-K, Exhibit 28-11.)
(E)10-110	Additional Support Agreement dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, and Ohio Edison Company. (1987 Form 10-K, Exhibit 28-12.)
(F)10-111	Participation Agreement dated as of September 15, 1987, among Chrysler Consortium Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-13.)
(F)10-112	Amendment No. 1 dated as of February 1, 1988, to Participation Agreement dated as of September 15, 1987, among Chrysler Consortium Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-14.)
(F)10-113	Amendment No. 3 dated as of March 16, 1988 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-114.)
(F)10-114	Amendment No. 4 dated as of November 5, 1992 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-115.)
(F)10-115	Amendment No. 5 dated as of January 12, 1993 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-139.)
(F)10-116	Amendment No. 6 dated as of September 30, 1994 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-140.)
(F)10-117	Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, Lessor, and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-15.)

59

Exhibit

Number

(F)10-118	Amendment No. 1 dated as of February 1, 1988, to Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, Lessor, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-16.)
(F)10-119	Amendment No. 2 dated as of November 5, 1992 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-118.)
(F)10-120	Amendment No. 3 dated as of January 12, 1993 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-119.)
(F)10-121	Amendment No. 4 dated as of September 30, 1994 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-145.)
(F)10-122	Ground Lease and Easement Agreement dated as of September 15, 1987, between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, Tenant. (1987 Form 10-K, Exhibit 28-17.)
(F)10-123	Trust Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and The First National Bank of Boston. (1987 Form 10-K, Exhibit 28-18.)
(F)10-124	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-19.)
(F)10-125	Supplemental Indenture No. 1 dated as of February 1, 1988 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with Chrysler Consortium Corporation and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-20.)
(F)10-126	Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-21.)
(F)10-127	Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-151.)
(F)10-128	Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-152.)
(F)10-129	Amendment No. 3 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-153.)
(F)10-130	Assignment, Assumption and Further Agreement dated as of September 15, 1987, among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, and Toledo Edison Company. (1987 Form 10-K, Exhibit 28-22.)
(F)10-131	Additional Support Agreement dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, and Ohio Edison Company. (1987 Form 10-K, Exhibit 28-23.)

60

Exhibit

Number

10-132	Operating Agreement dated March 10, 1987 with respect to Perry Unit No. 1 between the CAPCO Companies. (1987 Form 10-K, Exhibit 28-24.)
10-133	Operating Agreement for Bruce Mansfield Units Nos. 1, 2 and 3 dated as of June 1, 1976, and executed on September 15, 1987, by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 28-25.)
10-134	Operating Agreement for W. H. Sammis Unit No. 7 dated as of September 1, 1971 by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 28-26.)
10-135	Electric Power Supply Agreement, between the Cleveland Electric Illuminating Company, Ohio Edison Company, Pennsylvania Power Company, the Toledo Edison Company, and First Energy Solutions Corp. (f.k.a. FirstEnergy Services Corp.), dated January 1, 2001. (2004 Form 10-K, Exhibit 10-9)
10-136	Revised Electric Power Supply Agreement, between FirstEnergy Solutions Corp., the Cleveland Electric Illuminating Company, Ohio Edison Company, Pennsylvania Power Company, and the Toledo Edison Company, dated October 1, 2003. (2004 Form 10-K, Exhibit 10-10)
10-137	OE Nuclear Capital Contribution Agreement by and between Ohio Edison Company and FirstEnergy Nuclear Generation Corp. (June 2005 10-Q, Exhibit 10.1)
10-138	OE Fossil Purchase and Sale Agreement by and between Ohio Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (June 2005 10-Q, Exhibit 10.2)
10-139	Consent Decree dated as of March 18, 2005. (Form 8-K dated March 18, 2005, Exhibit 10.1)
10-140	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)
10-141	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)
(A)12.3	Consolidated Fixed Charged Ratios.
(A)13.2	OE 2007 Annual Report to Stockholders (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed filed with the SEC.)
(A)23.2	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.
(B)	Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, OE has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of OE and its subsidiaries on a consolidated basis, but hereby agrees to furnish to the SEC on request any such instruments.
(C)	Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.
(D)	Substantially similar documents have been entered into relating to three additional Owner Participants.

61

Exhibit

Number

(E)	Substantially similar documents have been entered into relating to five additional Owner Participants.
(F)	Substantially similar documents have been entered into relating to two additional Owner Participants.

3.      Exhibits Common Exhibits for CEI and TE

Exhibit

Number

2(a)	Agreement and Plan of Merger between Ohio Edison and Centerior Energy dated as of September 13, 1996 (Exhibit (2)-1, Form S-4 File No. 333-21011, filed by FirstEnergy).
2(b)	Merger Agreement by and among Centerior Acquisition Corp., FirstEnergy and Centerior (Exhibit (2)-3, Form S-4 File No. 333-21011, filed by FirstEnergy).
4(a)	Rights Agreement (Exhibit 4, June 25, 1996 Form 8-K, File Nos. 1-9130, 1-2323 and 1-3583).
4(b)(1)	Form of Note Indenture between Cleveland Electric, Toledo Edison and The Chase Manhattan Bank, as Trustee dated as of June 13, 1997 (Exhibit 4(c), Form S-4 File No. 333-35931, filed by Cleveland Electric and Toledo Edison).
4(b)(2)	Form of First Supplemental Note Indenture between Cleveland Electric, Toledo Edison and The Chase Manhattan Bank, as Trustee dated as of June 13, 1997 (Exhibit 4(d), Form S-4 File No. 333-35931, filed by Cleveland Electric and Toledo Edison).
10b(1)(a)	CAPCO Administration Agreement dated November 1, 1971, as of September 14, 1967, among the CAPCO Group members regarding the organization and procedures for implementing the objectives of the CAPCO Group (Exhibit 5(p), Amendment No. 1, File No. 2-42230, filed by Cleveland Electric).
10b(1)(b)	Amendment No. 1, dated January 4, 1974, to CAPCO Administration Agreement among the CAPCO Group members (Exhibit 5(c)(3), File No. 2-68906, filed by Ohio Edison).
10b(2)	CAPCO Transmission Facilities Agreement dated November 1, 1971, as of September 14, 1967, among the CAPCO Group members regarding the installation, operation and maintenance of transmission facilities to carry out the objectives of the CAPCO Group (Exhibit 5(q), Amendment No. 1, File No. 2-42230, filed by Cleveland Electric).
10b(2)(1)	Amendment No. 1 to CAPCO Transmission Facilities Agreement, dated December 23, 1993 and effective as of January 1, 1993, among the CAPCO Group members regarding requirements for payment of invoices at specified times, for payment of interest on non-timely paid invoices, for restricting adjustment of invoices after a four-year period, and for revising the method for computing the Investment Responsibility charge for use of a members transmission facilities (Exhibit 10b(2)(1), 1993 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583).
10b(3)	CAPCO Basic Operating Agreement As Amended January 1, 1993 among the CAPCO Group members regarding coordinated operation of the members systems (Exhibit 10b(3), 1993 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583).
10b(4)	Agreement for the Termination or Construction of Certain Agreement By and Among the CAPCO Group members, dated December 23, 1993 and effective as of September 1, 1980 (Exhibit 10b(4), 1993 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583).
10b(5)	Construction Agreement, dated July 22, 1974, among the CAPCO Group members and relating to the Perry Nuclear Plant (Exhibit 5 (yy), File No. 2-52251, filed by Toledo Edison).
10b(6)	Contract, dated as of December 5, 1975, among the CAPCO Group members for the construction of Beaver Valley Unit No. 2 (Exhibit 5 (g), File No. 2-52996, filed by Cleveland Electric).

62

Exhibit

Number

10b(7)	Amendment No. 1, dated May 1, 1977, to Contract, dated as of December 5, 1975, among the CAPCO Group members for the construction of Beaver Valley Unit No. 2 (Exhibit 5(d)(4), File No. 2-60109, filed by Ohio Edison).
10d(1)(a)	Form of Collateral Trust Indenture among CTC Beaver Valley Funding Corporation, Cleveland Electric, Toledo Edison and Irving Trust Company, as Trustee (Exhibit 4(a), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
10d(1)(b)	Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10d(1)(a) above, including form of Secured Lease Obligation bond (Exhibit 4(b), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
10d(1)(c)	Form of Collateral Trust Indenture among Beaver Valley II Funding Corporation, The Cleveland Electric Illuminating Company and The Toledo Edison Company and The Bank of New York, as Trustee (Exhibit (4)(a), File No. 33-46665, filed by Cleveland Electric and Toledo Edison).
10d(1)(d)	Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10d(1)(c) above, including form of Secured Lease Obligation Bond (Exhibit (4)(b), File No. 33-46665, filed by Cleveland Electric and Toledo Edison).
10d(2)(a)	Form of Collateral Trust Indenture among CTC Mansfield Funding Corporation, Cleveland Electric, Toledo Edison and IBJ Schroder Bank & Trust Company, as Trustee (Exhibit 4(a), File No. 33-20128, filed by Cleveland Electric and Toledo Edison).
10d(2)(b)	Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10d(2)(a) above, including forms of Secured Lease Obligation bonds (Exhibit 4(b), File No. 33-20128, filed by Cleveland Electric and Toledo Edison).
10d(3)(a)	Form of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the limited partnership Owner Participant named therein, Lessor, and Cleveland Electric and Toledo Edison, Lessee (Exhibit 4(c), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
10d(3)(b)	Form of Amendment No. 1 to Facility Lease constituting Exhibit 10d(3)(a) above (Exhibit 4(e), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
10d(4)(a)	Form of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the corporate Owner Participant named therein, Lessor, and Cleveland Electric and Toledo Edison, Lessees (Exhibit 4(d), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
10d(4)(b)	Form of Amendment No. 1 to Facility Lease constituting Exhibit 10d(4)(a) above (Exhibit 4(f), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
10d(5)(a)	Form of Facility Lease dated as of September 30, 1987 between Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Lessor, and Cleveland Electric and Toledo Edison, Lessees (Exhibit 4(c), File No. 33-20128, filed by Cleveland Electric and Toledo Edison).
10d(5)(b)	Form of Amendment No. 1 to the Facility Lease constituting Exhibit 10d(5)(a) above (Exhibit 4(f), File No. 33-20128, filed by Cleveland Electric and Toledo Edison).
10d(6)(a)	Form of Participation Agreement dated as of September 15, 1987 among the limited partnership Owner Participant named therein, the Original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants, CTC Beaver Valley Fund Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Cleveland Electric and Toledo Edison, as Lessees (Exhibit 28(a), File No. 33-18755, filed by Cleveland Electric And Toledo Edison).
10d(6)(b)	Form of Amendment No. 1 to Participation Agreement constituting Exhibit 10d(6)(a) above (Exhibit 28(c), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).

63

Exhibit

Number

10d(7)(a)	Form of Participation Agreement dated as of September 15, 1987 among the corporate Owner Participant named therein, the Original Loan Participants listed in Schedule 1 thereto, as Owner Loan Participants, CTC Beaver Valley Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Cleveland Electric and Toledo Edison, as Lessees (Exhibit 28(b), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
10d(7)(b)	Form of Amendment No. 1 to Participation Agreement constituting Exhibit 10d(7)(a) above (Exhibit 28(d), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
10d(8)(a)	Form of Participation Agreement dated as of September 30, 1987 among the Owner Participant named therein, the Original Loan Participants listed in Schedule II thereto, as Owner Loan Participants, CTC Mansfield Funding Corporation, Meridian Trust Company, as Owner Trustee, IBJ Schroder Bank & Trust Company, as Indenture Trustee, and Cleveland Electric and Toledo Edison, as Lessees (Exhibit 28(a), File No. 33-0128, filed by Cleveland Electric and Toledo Edison).
10d(8)(b)	Form of Amendment No. 1 to the Participation Agreement constituting Exhibit 10d(8)(a) above (Exhibit 28(b), File No. 33-20128, filed by Cleveland Electric and Toledo Edison).
10d(9)	Form of Ground Lease dated as of September 15, 1987 between Toledo Edison, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Tenant (Exhibit 28(e), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
10d(10)	Form of Site Lease dated as of September 30, 1987 between Toledo Edison, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant (Exhibit 28(c), File No. 33-20128, filed by Cleveland Electric and Toledo Edison).
10d(11)	Form of Site Lease dated as of September 30, 1987 between Cleveland Electric, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant (Exhibit 28(d), File No. 33-20128, filed by Cleveland Electric and Toledo Edison).
10d(12)	Form of Amendment No. 1 to the Site Leases constituting Exhibits 10d(10) and 10d(11) above (Exhibit 4(f), File No. 33-20128, filed by Cleveland Electric and Toledo Edison).
10d(13)	Form of Assignment, Assumption and Further Agreement dated as of September 15, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Cleveland Electric, Duquesne, Ohio Edison, Pennsylvania Power and Toledo Edison (Exhibit 28(f), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
10d(14)	Form of Additional Support Agreement dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, and Toledo Edison (Exhibit 28(g), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
10d(15)	Form of Support Agreement dated as of September 30, 1987 between Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Toledo Edison, Cleveland Electric, Duquesne, Ohio Edison and Pennsylvania Power (Exhibit 28(e), File No. 33-20128, filed by Cleveland Electric and Toledo Edison).
10d(16)	Form of Indenture, Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between Toledo Edison, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Buyer (Exhibit 28(h), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).

64

Exhibit

Number

10d(17)	Form of Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between Toledo Edison, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Buyer (Exhibit 28(f), File No. 33-20128, filed by Cleveland Electric and Toledo Edison).
10d(18)	Form of Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between Cleveland Electric, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Buyer (Exhibit 28(g), File No. 33-20128, filed by Cleveland Electric and Toledo Edison).
10d(19)	Forms of Refinancing Agreement, including exhibits thereto, among the Owner Participant named therein, as Owner Participant, CTC Beaver Valley Funding Corporation, as Funding Corporation, Beaver Valley II Funding Corporation, as New Funding Corporation, The Bank of New York, as Indenture Trustee, The Bank of New York, as New Collateral Trust Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees (Exhibit (28)(e)(i), File No. 33-46665, filed by Cleveland Electric and Toledo Edison).
10d(20)(a)	Form of Amendment No. 2 to Facility Lease among Citicorp Lescaman, Inc., Cleveland Electric and Toledo Edison (Exhibit 10(a), Form S-4 File No. 333-47651, filed by Cleveland Electric).
10d(20)(b)	Form of Amendment No. 3 to Facility Lease among Citicorp Lescaman, Inc., Cleveland Electric and Toledo Edison (Exhibit 10(b), Form S-4 File No. 333-47651, filed by Cleveland Electric).
10d(21)(a)	Form of Amendment No. 2 to Facility Lease among US West Financial Services, Inc., Cleveland Electric and Toledo Edison (Exhibit 10(c), Form S-4 File No. 333-47651, filed by Cleveland Electric).
10d(21)(b)	Form of Amendment No. 3 to Facility Lease among US West Financial Services, Inc., Cleveland Electric and Toledo Edison (Exhibit 10(d), Form S-4 File No. 333-47651, filed by Cleveland Electric).
10d(22)	Form of Amendment No. 2 to Facility Lease among Midwest Power Company, Cleveland Electric and Toledo Edison (Exhibit 10(e), Form S-4 File No. 333-47651, filed by Cleveland Electric).
10e(1)	Centerior Energy Corporation Equity Compensation Plan (Exhibit 99, Form S-8, File No. 33-59635).

3.     Exhibits CEI

3a	Amended Articles of Incorporation of CEI, as amended, effective May 28, 1993 (Exhibit 3a, 1993 Form 10-K, File No. 1-2323).
3b	Regulations of CEI, dated April 29, 1981, as amended effective October 1, 1988 and April 24, 1990 (Exhibit 3b, 1990 Form 10-K, File No. 1-2323).
3c	Amended and Restated Code of Regulations, dated March 15, 2002, incorporated by reference to Exhibit 3-2, 2001 Form 10-K, File No. 1-02323.
(A)3d	Amended and Restated Articles of Incorporation of The Cleveland Electric Illuminating Company, Effective December 21, 2007
(A)3e	Amended and Restated Code of Regulations of The Cleveland Electric Illuminating Company, dated December 14, 2007
(B)4b(1)	Mortgage and Deed of Trust between CEI and Guaranty Trust Company of New York (now The Chase Manhattan Bank (National Association)), as Trustee, dated July 1, 1940 (Exhibit 7(a), File No. 2-4450).
	Supplemental Indentures between CEI and the Trustee, supplemental to Exhibit 4b(1), dated as follows:

65

Exhibit

Number

4b(2)	July 1, 1940 (Exhibit 7(b), File No. 2-4450).
4b(3)	August 18, 1944 (Exhibit 4(c), File No. 2-9887).
4b(4)	December 1, 1947 (Exhibit 7(d), File No. 2-7306).
4b(5)	September 1, 1950 (Exhibit 7(c), File No. 2-8587).
4b(6)	June 1, 1951 (Exhibit 7(f), File No. 2-8994).
4b(7)	May 1, 1954 (Exhibit 4(d), File No. 2-10830).
4b(8)	March 1, 1958 (Exhibit 2(a)(4), File No. 2-13839).
4b(9)	April 1, 1959 (Exhibit 2(a)(4), File No. 2-14753).
4b(10)	December 20, 1967 (Exhibit 2(a)(4), File No. 2-30759).
4b(11)	January 15, 1969 (Exhibit 2(a)(5), File No. 2-30759).
4b(12)	November 1, 1969 (Exhibit 2(a)(4), File No. 2-35008).
4b(13)	June 1, 1970 (Exhibit 2(a)(4), File No. 2-37235).
4b(14)	November 15, 1970 (Exhibit 2(a)(4), File No. 2-38460).
4b(15)	May 1, 1974 (Exhibit 2(a)(4), File No. 2-50537).
4b(16)	April 15, 1975 (Exhibit 2(a)(4), File No. 2-52995).
4b(17)	April 16, 1975 (Exhibit 2(a)(4), File No. 2-53309).
4b(18)	May 28, 1975 (Exhibit 2(c), June 5, 1975 Form 8-A, File No. 1-2323).
4b(19)	February 1, 1976 (Exhibit 3(d)(6), 1975 Form 10 K, File No. 1-2323).
4b(20)	November 23, 1976 (Exhibit 2(a)(4), File No. 2-57375).
4b(21)	July 26, 1977 (Exhibit 2(a)(4), File No. 2-59401).
4b(22)	September 7, 1977 (Exhibit 2(a)(5), File No. 2-67221).
4b(23)	May 1, 1978 (Exhibit 2(b), June 30, 1978 Form 10-Q, File No. 1-2323).
4b(24)	September 1, 1979 (Exhibit 2(a), September 30, 1979 Form 10-Q, File No. 1-2323).
4b(25)	April 1, 1980 (Exhibit 4(a)(2), September 30, 1980 Form 10-Q, File No. 1-2323).
4b(26)	April 15, 1980 (Exhibit 4(b), September 30, 1980 Form 10-Q, File No. 1-2323).
4b(27)	May 28, 1980 (Exhibit 2(a)(4), Amendment No. 1, File No. 2-67221).
4b(28)	June 9, 1980 (Exhibit 4(d), September 30, 1980 Form 10-Q, File No. 1-2323).
4b(29)	December 1, 1980 (Exhibit 4(b)(29), 1980 Form 10-K, File No. 1-2323).
4b(30)	July 28, 1981 (Exhibit 4(a), September 30, 1981, Form 10-Q, File No. 1-2323).
4b(31)	August 1, 1981 (Exhibit 4(b), September 30, 1981, Form 10-Q, File No. 1-2323).
4b(32)	March 1, 1982 (Exhibit 4(b)(3), Amendment No. 1, File No. 2-76029).
4b(33)	July 15, 1982 (Exhibit 4(a), September 30, 1982 Form 10-Q, File No. 1-2323).
4b(34)	September 1, 1982 (Exhibit 4(a)(1), September 30, 1982 Form 10-Q, File No. 1-2323).
4b(35)	November 1, 1982 (Exhibit (a)(2), September 30, 1982 Form 10-Q, File No. 1-2323).
4b(36)	November 15, 1982 (Exhibit 4(b)(36), 1982 Form 10-K, File No. 1-2323).
4b(37)	May 24, 1983 (Exhibit 4(a), June 30, 1983 Form 10-Q, File No. 1-2323).
4b(38)	May 1, 1984 (Exhibit 4, June 30, 1984 Form 10-Q, File No. 1-2323).
4b(39)	May 23, 1984 (Exhibit 4, May 22, 1984 Form 8-K, File No. 1-2323).
4b(40)	June 27, 1984 (Exhibit 4, June 11, 1984 Form 8-K, File No. 1-2323).
4b(41)	September 4, 1984 (Exhibit 4b(41), 1984 Form 10-K, File No. 1-2323).
4b(42)	November 14, 1984 (Exhibit 4b(42), 1984 Form 10 K, File No. 1-2323).
4b(43)	November 15, 1984 (Exhibit 4b(43), 1984 Form 10-K, File No. 1-2323).
4b(44)	April 15, 1985 (Exhibit 4(a), May 8, 1985 Form 8-K, File No. 1-2323).
4b(45)	May 28, 1985 (Exhibit 4(b), May 8, 1985 Form 8-K, File No. 1-2323).
4b(46)	August 1, 1985 (Exhibit 4, September 30, 1985 Form 10-Q, File No. 1-2323).
4b(47)	September 1, 1985 (Exhibit 4, September 30, 1985 Form 8-K, File No. 1-2323).
4b(48)	November 1, 1985 (Exhibit 4, January 31, 1986 Form 8-K, File No. 1-2323).
4b(49)	April 15, 1986 (Exhibit 4, March 31, 1986 Form 10-Q, File No. 1-2323).
4b(50)	May 14, 1986 (Exhibit 4(a), June 30, 1986 Form 10-Q, File No. 1-2323).
4b(51)	May 15, 1986 (Exhibit 4(b), June 30, 1986 Form 10-Q, File No. 1-2323).
4b(52)	February 25, 1987 (Exhibit 4b(52), 1986 Form 10-K, File No. 1-2323).
4b(53)	October 15, 1987 (Exhibit 4, September 30, 1987 Form 10-Q, File No. 1-2323).
4b(54)	February 24, 1988 (Exhibit 4b(54), 1987 Form 10-K, File No. 1-2323).
4b(55)	September 15, 1988 (Exhibit 4b(55), 1988 Form 10-K, File No. 1-2323).
4b(56)	May 15, 1989 (Exhibit 4(a)(2)(i), File No. 33-32724).
4b(57)	June 13, 1989 (Exhibit 4(a)(2)(ii), File No. 33-32724).
4b(58)	October 15, 1989 (Exhibit 4(a)(2)(iii), File No. 33-32724).
4b(59)	January 1, 1990 (Exhibit 4b(59), 1989 Form 10-K, File No. 1-2323).
4b(60)	June 1, 1990 (Exhibit 4(a). September 30, 1990 Form 10-Q, File No. 1-2323).
4b(61)	August 1, 1990 (Exhibit 4(b), September 30, 1990 Form 10-Q, File No. 1-2323).
4b(62)	May 1, 1991 (Exhibit 4(a), June 30, 1991 Form 10-Q, File No. 1-2323).
4b(63)	May 1, 1992 (Exhibit 4(a)(3), File No. 33-48845).
4b(64)	July 31, 1992 (Exhibit 4(a)(3), File No. 33-57292).

66

Exhibit

Number

4b(65)	January 1, 1993 (Exhibit 4b(65), 1992 Form 10-K, File No. 1-2323).
4b(66)	February 1, 1993 (Exhibit 4b(66), 1992 Form 10-K, File No. 1-2323).
4b(67)	May 20, 1993 (Exhibit 4(a), July 14, 1993 Form 8-K, File No. 1-2323).
4b(68)	June 1, 1993 (Exhibit 4(b), July 14, 1993 Form 8-K, File No. 1-2323).
4b(69)	September 15, 1994 (Exhibit 4(a), September 30, 1994 Form 10-Q, File No. 1-2323).
4b(70)	May 1, 1995 (Exhibit 4(a), September 30, 1995 Form 10-Q, File No. 1-2323).
4b(71)	May 2, 1995 (Exhibit 4(b), September 30, 1995 Form 10-Q, File No. 1-2323).
4b(72)	June 1, 1995 (Exhibit 4(c), September 30, 1995 Form 10-Q, File No. 1-2323).
4b(73)	July 15, 1995 (Exhibit 4b(73), 1995 Form 10-K, File No. 1-2323).
4b(74)	August 1, 1995 (Exhibit 4b(74), 1995 Form 10-K, File No. 1-2323).
4b(75)	June 15, 1997 (Exhibit 4(a), Form S-4 File No. 333-35931, filed by Cleveland Electric and Toledo Edison).
4b(76)	October 15, 1997 (Exhibit 4(a), Form S-4 File No. 333-47651, filed by Cleveland Electric).
4b(77)	June 1, 1998 (Exhibit 4b(77), Form S-4 File No. 333-72891).
4b(78)	October 1, 1998 (Exhibit 4b(78), Form S-4 File No. 333-72891).
4b(79)	October 1, 1998 (Exhibit 4b(79), Form S-4 File No. 333-72891).
4b(80)	February 24, 1999 (Exhibit 4b(80), Form S-4 File No. 333-72891).
4b(81)	September 29, 1999. (Exhibit 4b(81), 1999 Form 10-K, File No. 1-2323).
4b(82)	January 15, 2000. (Exhibit 4b(82), 1999 Form 10-K, File No. 1-2323).
4b(83)	May 15, 2002 (Exhibit 4b(83), 2002 Form 10-K, File No. 1-2323).
4b(84)	October 1, 2002 (Exhibit 4b(84), 2002 Form 10-K, File No. 1-2323).
4b(85)	Supplemental Indenture dated as of September 1, 2004 (Exhibit 4-1(85), September 2004 10-Q, File No. 1-2323).
4b(86)	Supplemental Indenture dated as of October 1, 2004 (Exhibit 4-1(86), September 2004 10-Q, File No. 1-2323).
4b(87)	Supplemental Indenture dated as of April 1, 2005 (Exhibit 4.1, June 2005 10-Q, File No. 1-2323)
4b(88)	Supplemental Indenture dated as of July 1, 2005 (Exhibit 4.2, June 2005 10-Q, File No. 1-2323)
4d	Form of Note Indenture between Cleveland Electric and The Chase Manhattan Bank, as Trustee dated as of October 24, 1997 (Exhibit 4(b), Form S-4 File No. 333-47651, filed by Cleveland Electric).
4d(1)	Form of Supplemental Note Indenture between Cleveland Electric and The Chase Manhattan Bank, as Trustee dated as of October 24, 1997 (Exhibit 4(c), Form S-4 File No. 333-47651, filed by Cleveland Electric).
4-1	Indenture dated as of December 1, 2003 between CEI and JPMorgan Chase Bank, as Trustee, Incorporated by reference to Exhibit 4-8, 2003 Annual Report on Form 10-K, SEC File No. 1-02323.
4-2	Officers Certificate (including the form of 5.95% Senior Notes due 2036), dated as of December 11, 2006. (Form 8-K dated December 11, 2006, Exhibit 4)
4-3	Officers Certificate (including the form of 5.70% Senior Notes due 2017), dated as of March 27, 2007 (Form 8-K dated March 28, 2007, Exhibit 4).
10-1	Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(2).)
10-2	Amendment No. 1 dated January 4, 1974 to Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-68906, Exhibit 5(c)(3).)
10-3	Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(3).)
10-4	Amendment No. 1 dated as of January 1, 1993 to Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (1993 Form 10-K, Exhibit 10-4.)
10-5	Agreement for the Termination or Construction of Certain Agreements effective September 1, 1980, October 15, 1997 (Exhibit 4(a), Form S-4 File No. 333-47651, filed by Cleveland Electric).

67

Exhibit

Number

10-6	Electric Power Supply Agreement, between the Cleveland Electric Illuminating Company, Ohio Edison Company, Pennsylvania Power Company, the Toledo Edison Company, and First Energy Solutions Corp. (f.k.a. FirstEnergy Services Corp.), dated January 1, 2001. (Filed as Ohio Edison Exhibit 10-145 in 2004 Form 10-K)
10-7	Revised Electric Power Supply Agreement, between FirstEnergy Solutions Corp., the Cleveland Electric Illuminating Company, Ohio Edison Company, Pennsylvania Power Company, and the Toledo Edison Company, dated October 1, 2003. (Filed as Ohio Edison Exhibit 10-146 in 2004 Form 10-K)
10-8	Master Facility Lease, between Ohio Edison Company, Pennsylvania Power Company, the Cleveland Electric Illuminating Company, the Toledo Edison Company, and FirstEnergy Generation Corp., dated January 1, 2001. (Filed as Ohio Edison Exhibit 10-147 in 2004 Form 10-K)
10-9	CEI Nuclear Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company and FirstEnergy Nuclear Generation Corp. (June 2005 10-Q, Exhibit 10.1)
10-10	CEI Fossil Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (June 2005 10-Q, Exhibit 10.2)
10-11	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)
10-12	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)
10-13	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)
(A)12.4	Consolidated fixed charge ratios.
(A)13.2	CEI 2007 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed filed with the SEC.)
(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.
(B)	Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, CEI has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of CEI, but hereby agrees to furnish to the Commission on request any such instruments.

3.     Exhibits TE

3a	Amended Articles of Incorporation of TE, as amended effective October 2, 1992 (Exhibit 3a, 1992 Form 10-K, File No. 1-3583).
3b	Amended and Restated Code of Regulations, dated March 15, 2002. (2001 Form 10-K, Exhibit 3b)
(A)3c	Amended and Restated Articles of Incorporation of The Toledo Edison Company, Effective December 18, 2007

68

Exhibit

Number

(A)3d	Amended and Restated Code of Regulations of The Toledo Edison Company, dated December 14, 2007
(B)4b(1)	Indenture, dated as of April 1, 1947, between TE and The Chase National Bank of the City of New York (now The Chase Manhattan Bank (National Association)) (Exhibit 2(b), File No. 2-26908).
4b(2)	September 1, 1948 (Exhibit 2(d), File No. 2-26908).
4b(3)	April 1, 1949 (Exhibit 2(e), File No. 2-26908).
4b(4)	December 1, 1950 (Exhibit 2(f), File No. 2-26908).
4b(5)	March 1, 1954 (Exhibit 2(g), File No. 2-26908).
4b(6)	February 1, 1956 (Exhibit 2(h), File No. 2-26908).
4b(7)	May 1, 1958 (Exhibit 5(g), File No. 2-59794).
4b(8)	August 1, 1967 (Exhibit 2(c), File No. 2-26908).
4b(9)	November 1, 1970 (Exhibit 2(c), File No. 2-38569).
4b(10)	August 1, 1972 (Exhibit 2(c), File No. 2-44873).
4b(11)	November 1, 1973 (Exhibit 2(c), File No. 2-49428).
4b(12)	July 1, 1974 (Exhibit 2(c), File No. 2-51429).
4b(13)	October 1, 1975 (Exhibit 2(c), File No. 2-54627).
4b(14)	June 1, 1976 (Exhibit 2(c), File No. 2-56396).
4b(15)	October 1, 1978 (Exhibit 2(c), File No. 2-62568).
4b(16)	September 1, 1979 (Exhibit 2(c), File No. 2-65350).
4b(17)	September 1, 1980 (Exhibit 4(s), File No. 2-69190).
4b(18)	October 1, 1980 (Exhibit 4(c), File No. 2-69190).
4b(19)	April 1, 1981 (Exhibit 4(c), File No. 2-71580).
4b(20)	November 1, 1981 (Exhibit 4(c), File No. 2-74485).
4b(21)	June 1, 1982 (Exhibit 4(c), File No. 2-77763).
4b(22)	September 1, 1982 (Exhibit 4(x), File No. 2-87323).
4b(23)	April 1, 1983 (Exhibit 4(c), March 31, 1983, Form 10-Q, File No. 1-3583).
4b(24)	December 1, 1983 (Exhibit 4(x), 1983 Form 10-K, File No. 1-3583).
4b(25)	April 1, 1984 (Exhibit 4(c), File No. 2-90059).
4b(26)	October 15, 1984 (Exhibit 4(z), 1984 Form 10-K, File No. 1-3583).
4b(27)	October 15, 1984 (Exhibit 4(aa), 1984 Form 10-K, File No. 1-3583).
4b(28)	August 1, 1985 (Exhibit 4(dd), File No. 33-1689).
4b(29)	August 1, 1985 (Exhibit 4(ee), File No. 33-1689).
4b(30)	December 1, 1985 (Exhibit 4(c), File No. 33-1689).
4b(31)	March 1, 1986 (Exhibit 4b(31), 1986 Form 10-K, File No. 1-3583).
4b(32)	October 15, 1987 (Exhibit 4, September 30, 1987 Form 10-Q, File No. 1-3583).
4b(33)	September 15, 1988 (Exhibit 4b(33), 1988 Form 10-K, File No. 1-3583).
4b(34)	June 15, 1989 (Exhibit 4b(34), 1989 Form 10-K, File No. 1-3583).
4b(35)	October 15, 1989 (Exhibit 4b(35), 1989 Form 10-K, File No. 1-3583).
4b(36)	May 15, 1990 (Exhibit 4, June 30, 1990 Form 10-Q, File No. 1-3583).
4b(37)	March 1, 1991 (Exhibit 4(b), June 30, 1991 Form 10-Q, File No. 1-3583).
4b(38)	May 1, 1992 (Exhibit 4(a)(3), File No. 33-48844).
4b(39)	August 1, 1992 (Exhibit 4b(39), 1992 Form 10-K, File No. 1-3583).
4b(40)	October 1, 1992 (Exhibit 4b(40), 1992 Form 10-K, File No. 1-3583).
4b(41)	January 1, 1993 (Exhibit 4b(41), 1992 Form 10-K, File No. 1-3583).
4b(42)	September 15, 1994 (Exhibit 4(b), September 30, 1994 Form 10-Q, File No. 1-3583).
4b(43)	May 1, 1995 (Exhibit 4(d), September 30, 1995 Form 10-Q, File No. 1-3583).
4b(44)	June 1, 1995 (Exhibit 4(e), September 30, 1995 Form 10-Q, File No. 1-3583).
4b(45)	July 14, 1995 (Exhibit 4(f), September 30, 1995 Form 10-Q, File No. 1-3583).
4b(46)	July 15, 1995 (Exhibit 4(g), September 30, 1995 Form 10-Q, File No. 1-3583).
4b(47)	August 1, 1997 (Exhibit 4b(47), 1998 Form 10-K, File No. 1-3583).
4b(48)	June 1, 1998 (Exhibit 4b (48), 1998 Form 10-K, File No. 1-3583).
4b(49)	January 15, 2000 (Exhibit 4b(49), 1999 Form 10-K, File No. 1-3583).
4b(50)	May 1, 2000 (Exhibit 4b(50), 2000 Form 10-K, File No. 1-3583).
4b(51)	September 1, 2000 (Exhibit 4b(51), 2002 Form 10-K, File No. 1-3583).
4b(52)	October 1, 2002 (Exhibit 4b(52), 2002 Form 10-K, File No. 1-3583).
4b(53)	April 1, 2003 (Exhibit 4b(53).
4b(55)	April 1, 2005 (Exhibit 4.1, June 2005 10-Q, File No. 1-3583).
4-1	Officers Certificate (including the form of 6.15% Senior Notes due 2037), dated November 16, 2006. (Form 8-K dated November 16, 2006, Exhibit 4)

69

Exhibit

Number

4-2	Indenture dated as of November 1, 2006, between TE and The Bank of New York Trust Company, N.A. (2006 Form 10-K, Exhibit 4)
10-1	TE Nuclear Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Nuclear Generation Corp. (Purchaser). (June 2005 10-Q, Exhibit 10.1)
10-2	TE Fossil Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (June 2005 10-Q, Exhibit 10.2)
10-3	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)
10-4	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)
10-5	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)
(A)12.5	Consolidated fixed charge ratios.
(A)13.2	TE 2007 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed filed with the SEC.)
(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.
(B)	Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, TE has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of TE, but hereby agrees to furnish to the Commission on request any such instruments.

3.      Exhibits JCP&L

3-A	Restated Certificate of Incorporation of JCP&L, as amended - Incorporated by reference to Exhibit 3-A, 1990 Annual Report on Form 10-K, SEC File No. 1-3141.
3-A-1	Certificate of Amendment to Restated Certificate of Incorporation of JCP&L, dated June 19, 1992 - Incorporated by reference to Exhibit A-2(a), Certificate Pursuant to Rule 24, SEC File No. 70-7949.
3-A-2	Certificate of Amendment to Restated Certificate of Incorporation of JCP&L, dated June 19, 1992 - Incorporated by reference to Exhibit A-2(a)(i), Certificate Pursuant to Rule 24, SEC File No. 70-7949.
3-B	By-Laws of JCP&L, as amended May 25, 1993 - Incorporated by reference to Exhibit 3-B, 1993 Annual Report on Form 10-K, SEC File No. 1-3141.
3-C	By-Laws of JCP&L, as amended July 11, 2007 (June 2007 10-Q,Exhibit 3)
(A)3-D	Amended and Restated Certificate of Incorporation of Jersey Central Power & Light Company, Filed February 14, 2008
(A)3-E	Amended and Restated Bylaws of Jersey Central Power & Light Company, dated January 9, 2008

70

Exhibit

Number

4-A	Indenture of JCP&L, dated March 1, 1946, between JCP&L and United States Trust Company of New York, Successor Trustee, as amended and supplemented by eight supplemental indentures dated December 1, 1948 through June 1, 1960 - Incorporated by reference to JCP&Ls Instruments of Indebtedness Nos. 1 to 7, inclusive, and 9 and 10 filed as part of Amendment No. 1 to 1959 Annual Report of GPU on Form U5S, SEC File Nos. 30-126 and 1-3292.
4-A-1	Ninth Supplemental Indenture of JCP&L, dated November 1, 1962 - Incorporated by reference to Exhibit 2-C, Registration No. 2-20732.
4-A-2	Tenth Supplemental Indenture of JCP&L, dated October 1, 1963 - Incorporated by reference to Exhibit 2-C, Registration No. 2-21645.
4-A-3	Eleventh Supplemental Indenture of JCP&L, dated October 1, 1964 - Incorporated by reference to Exhibit 5-A-3, Registration No. 2-59785.
4-A-4	Twelfth Supplemental Indenture of JCP&L, dated November 1, 1965 - Incorporated by reference to Exhibit 5-A-4, Registration No. 2-59785.
4-A-5	Thirteenth Supplemental Indenture of JCP&L, dated August 1, 1966 - Incorporated by reference to Exhibit 4-C, Registration No. 2-25124.
4-A-6	Fourteenth Supplemental Indenture of JCP&L, dated September 1, 1967 - Incorporated by reference to Exhibit 5-A-6, Registration No. 2-59785.
4-A-7	Fifteenth Supplemental Indenture of JCP&L, dated October 1, 1968 - Incorporated by reference to Exhibit 5-A-7, Registration No. 2-59785.
4-A-8	Sixteenth Supplemental Indenture of JCP&L, dated October 1, 1969 - Incorporated by reference to Exhibit 5-A-8, Registration No. 2-59785.
4-A-9	Seventeenth Supplemental Indenture of JCP&L, dated June 1, 1970 - Incorporated by reference to Exhibit 5-A-9, Registration No. 2-59785.
4-A-10	Eighteenth Supplemental Indenture of JCP&L, dated December 1, 1970 - Incorporated by reference to Exhibit 5-A-10, Registration No. 2-59785.
4-A-11	Nineteenth Supplemental Indenture of JCP&L, dated February 1, 1971 - Incorporated by reference to Exhibit 5-A-11, Registration No. 2-59785.
4-A-12	Twentieth Supplemental Indenture of JCP&L, dated November 1, 1971 - Incorporated by reference to Exhibit 5-A-12, Registration No. 2-59875.
4-A-13	Twenty-first Supplemental Indenture of JCP&L, dated August 1, 1972 - Incorporated by reference to Exhibit 5-A-13, Registration No. 2-59785.
4-A-14	Twenty-second Supplemental Indenture of JCP&L, dated August 1, 1973 - Incorporated by reference to Exhibit 5-A-14, Registration No. 2-59785.
4-A-15	Twenty-third Supplemental Indenture of JCP&L, dated October 1, 1973 - Incorporated by reference to Exhibit 5-A-15, Registration No. 2-59785.
4-A-16	Twenty-fourth Supplemental Indenture of JCP&L, dated December 1, 1973 - Incorporated by reference to Exhibit 5-A-16, Registration No. 2-59785.
4-A-17	Twenty-fifth Supplemental Indenture of JCP&L, dated November 1, 1974 - Incorporated by reference to Exhibit 5-A-17, Registration No. 2-59785.
4-A-18	Twenty-sixth Supplemental Indenture of JCP&L, dated March 1, 1975 - Incorporated by reference to Exhibit 5-A-18, Registration No. 2-59785.
4-A-19	Twenty-seventh Supplemental Indenture of JCP&L, dated July 1, 1975 - Incorporated by reference to Exhibit 5-A-19, Registration No. 2-59785.

71

Exhibit

Number

4-A-20	Twenty-eighth Supplemental Indenture of JCP&L, dated October 1, 1975 - Incorporated by reference to Exhibit 5-A-20, Registration No. 2-59785.
4-A-21	Twenty-ninth Supplemental Indenture of JCP&L, dated February 1, 1976 - Incorporated by reference to Exhibit 5-A-21, Registration No. 2-59785.
4-A-22	Supplemental Indenture No. 29A of JCP&L, dated May 31, 1976 - Incorporated by reference to Exhibit 5-A-22, Registration No. 2-59785.
4-A-23	Thirtieth Supplemental Indenture of JCP&L, dated June 1, 1976 - Incorporated by reference to Exhibit 5-A-23, Registration No. 2-59785.
4-A-24	Thirty-first Supplemental Indenture of JCP&L, dated May 1, 1977 - Incorporated by reference to Exhibit 5-A-24, Registration No. 2-59785.
4-A-25	Thirty-second Supplemental Indenture of JCP&L, dated January 20, 1978 - Incorporated by reference to Exhibit 5-A-25, Registration No. 2-60438.
4-A-26	Thirty-third Supplemental Indenture of JCP&L, dated January 1, 1979 - Incorporated by reference to Exhibit A-20(b), Certificate Pursuant to Rule 24, SEC File No. 70-6242.
4-A-27	Thirty-fourth Supplemental Indenture of JCP&L, dated June 1, 1979 - Incorporated by reference to Exhibit A-28, Certificate Pursuant to Rule 24, SEC File No. 70-6290.
4-A-28	Thirty-sixth Supplemental Indenture of JCP&L, dated October 1, 1979 - Incorporated by reference to Exhibit A-30, Certificate Pursuant to Rule 24, SEC File No. 70-6354.
4-A-29	Thirty-seventh Supplemental Indenture of JCP&L, dated September 1, 1984 - Incorporated by reference to Exhibit A-1(cc), Certificate Pursuant to Rule 24, SEC File No. 70-7001.
4-A-30	Thirty-eighth Supplemental Indenture of JCP&L, dated July 1, 1985 - Incorporated by reference to Exhibit A-1(dd), Certificate Pursuant to Rule 24, SEC File No. 70-7109.
4-A-31	Thirty-ninth Supplemental Indenture of JCP&L, dated April 1, 1988 - Incorporated by reference to Exhibit A-1(a), Certificate Pursuant to Rule 24, SEC File No. 70-7263.
4-A-32	Fortieth Supplemental Indenture of JCP&L, dated June 14, 1988 - Incorporated by reference to Exhibit A-1(ff), Certificate Pursuant to Rule 24, SEC File No. 70-7603.
4-A-33	Forty-first Supplemental Indenture of JCP&L, dated April 1, 1989 - Incorporated by reference to Exhibit A-1(gg), Certificate Pursuant to Rule 24, SEC File No. 70-7603.
4-A-34	Forty-second Supplemental Indenture of JCP&L, dated July 1, 1989 - Incorporated by reference to Exhibit A-1(hh), Certificate Pursuant to Rule 24, SEC File No. 70-7603.
4-A-35	Forty-third Supplemental Indenture of JCP&L, dated March 1, 1991 - Incorporated by reference to Exhibit 4-A-35, Registration No. 33-45314.
4-A-36	Forty-fourth Supplemental Indenture of JCP&L, dated March 1, 1992 - Incorporated by reference to Exhibit 4-A-36, Registration No. 33-49405.
4-A-37	Forty-fifth Supplemental Indenture of JCP&L, dated October 1, 1992 - Incorporated by reference to Exhibit 4-A-37, Registration No. 33-49405.
4-A-38	Forty-sixth Supplemental Indenture of JCP&L, dated April 1, 1993 - Incorporated by reference to Exhibit C-15, 1992 Annual Report of GPU on Form U5S, SEC File No. 30-126.
4-A-39	Forty-seventh Supplemental Indenture of JCP&L, dated April 10, 1993 - Incorporated by reference to Exhibit C-16, 1992 Annual Report of GPU on Form U5S, SEC File No. 30-126.
4-A-40	Forty-eighth Supplemental Indenture of JCP&L, dated April 15, 1993 - Incorporated by reference to Exhibit C-17, 1992 Annual Report of GPU on Form U5S, SEC File No. 30-126.

72

Exhibit

Number

4-A-41	Forty-ninth Supplemental Indenture of JCP&L, dated October 1, 1993 - Incorporated by reference to Exhibit C-18, 1993 Annual Report of GPU on Form U5S, SEC File No. 30-126.
4-A-42	Fiftieth Supplemental Indenture of JCP&L, dated August 1, 1994 - Incorporated by reference to Exhibit C-19, 1994 Annual Report of GPU on Form U5S, SEC File No. 30-126.
4-A-43	Fifty-first Supplemental Indenture of JCP&L, dated August 15, 1996 Incorporated by reference to Exhibit 4-A-43, 1996 Annual Report on Form 10-K, SEC File No. 1-6047.
4-A-44	Fifty-second Supplemental Indenture of JCP&L, dated July 1, 1999 - Incorporated by reference to Exhibit 4-B-44, Registration No. 333-88783.
4-A-45	Fifty-third Supplemental Indenture of JCP&L, dated November 1, 1999 - Incorporated by reference to Exhibit 4-A-45, 1999 Annual Report on Form 10-K, SEC File No. 1-3141.
4-A-46	Subordinated Debenture Indenture of JCP&L, dated May 1, 1995 - Incorporated by reference to Exhibit A-8(a), Certificate Pursuant to Rule 24, SEC File No. 70-8495.
4-A-47	Fifty-fourth Supplemental Indenture of JCP&L, dated May 1, 2001, Incorporated by reference to Exhibit 4-4, 2001 Annual Report on Form 10-K, SEC File No. 1-3141.
4-A-48	Fifty-fifth Supplemental Indenture of JCP&L, dated April 23, 2004. (2004 Form 10-K, Exhibit 4-A-48).
4-D	Amended and Restated Limited Partnership Agreement of JCP&L Capital, L.P., dated May 11, 1995 - Incorporated by reference to Exhibit A-5(a), Certificate Pursuant to Rule 24, SEC File No. 70-8495.
4-E	Action Creating Series A Preferred Securities of JCP&L Capital, L.P., dated May 11, 1995 - Incorporated by reference to Exhibit A-6(a), Certificate Pursuant to Rule 24, SEC File No. 70-8495.
4-F	Payment and Guarantee Agreement of JCP&L, dated May 18, 1995 - Incorporated by reference to Exhibit B-1(a), Certificate Pursuant to Rule 24, SEC File No. 70-8495.
4-G	Indenture dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and The Bank of New York as Trustee. (Form 8-K dated August 10, 2006, Exhibit 4-1)
4-H	2006-A Series Supplement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and The Bank of New York as Trustee. (Form 8-K dated August 10, 2006, Exhibit 4-2)
10-1	Form of Jersey Central Power & Light Company 6.40% Senior Note due 2036. (Form 8-K dated May 12, 2006, Exhibit 10-1)
10-2	Registration Rights Agreement, dated as of May 12, 2006, among Jersey Central Power & Light Company and UBS Securities LLC and Greenwich Capital Markets, Inc., as representatives of the several initial purchasers named in the Purchase Agreement. (Form 8-K dated May 12, 2006, Exhibit 10-3)
10-3	Bondable Transition Property Sale Agreement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and Jersey Central Power & Light Company as Seller. (Form 8-K dated August 10, 2006, Exhibit 10-1)
10-4	Bondable Transition Property Service Agreement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and Jersey Central Power & Light Company as Servicer. (Form 8-K dated August 10, 2006, Exhibit 10-2)
10-5	Administration Agreement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and FirstEnergy Service Company as Administrator. (Form 8-K dated August 10, 2006, Exhibit 10-3)
(A)12.6	Consolidated fixed charge ratios.

73

Exhibit

Number

(A)13.2	JCP&L 2007 Annual Report to Stockholders (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed filed with SEC.)
(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 electronic format as an exhibit.

3.      Exhibits - Met-Ed

3-C	Restated Articles of Incorporation of Met-Ed, dated March 8, 1999 Incorporated by reference to Exhibit 3-E, 1999 Annual Report on Form 10-K, SEC File No. 1-446.
3-D	By-Laws of Met-Ed as amended May 16, 2000, Incorporated by reference to Exhibit 3-F, 2000 Annual Report on Form 10-K, SEC File No. 1-06047.
(A)3-E	Amended and Restated Articles of Incorporation of Metropolitan Edison Company, Effective December 19, 2007
(A)3-F	Amended and Restated Bylaws of Metropolitan Edison Company, dated December 14, 2007
4-B	Indenture of Met-Ed, dated November 1, 1944, between Met-Ed and United States Trust Company of New York, Successor Trustee, as amended and supplemented by fourteen supplemental indentures dated February 1, 1947 through May 1, 1960 - Incorporated by reference to Met-Eds Instruments of Indebtedness Nos. 1 to 14 inclusive, and 16, filed as part of Amendment No. 1 to 1959 Annual Report of GPU on Form U5S, SEC File Nos. 30-126 and 1-3292.
4-B-1	Supplemental Indenture of Met-Ed, dated December 1, 1962 - Incorporated by reference to Exhibit 2-E(1), Registration No. 2-59678.
4-B-2	Supplemental Indenture of Met-Ed, dated March 20, 1964 - Incorporated by reference to Exhibit 2-E(2), Registration No. 2-59678.
4-B-3	Supplemental Indenture of Met-Ed, dated July 1, 1965 - Incorporated by reference to Exhibit 2-E(3), Registration No. 2-59678.
4-B-4	Supplemental Indenture of Met-Ed, dated June 1, 1966 - Incorporated by reference to Exhibit 2-B-4, Registration No. 2-24883.
4-B-5	Supplemental Indenture of Met-Ed, dated March 22, 1968 - Incorporated by reference to Exhibit 4-C-5, Registration No. 2-29644.
4-B-6	Supplemental Indenture of Met-Ed, dated September 1, 1968 - Incorporated by reference to Exhibit 2-E(6), Registration No. 2-59678.
4-B-7	Supplemental Indenture of Met-Ed, dated August 1, 1969 - Incorporated by reference to Exhibit 2-E(7), Registration No. 2-59678.
4-B-8	Supplemental Indenture of Met-Ed, dated November 1, 1971 - Incorporated by reference to Exhibit 2-E(8), Registration No. 2-59678.
4-B-9	Supplemental Indenture of Met-Ed, dated May 1, 1972 - Incorporated by reference to Exhibit 2-E(9), Registration No. 2-59678.
4-B-10	Supplemental Indenture of Met-Ed, dated December 1, 1973 - Incorporated by reference to Exhibit 2-E(10), Registration No. 2-59678.
4-B-11	Supplemental Indenture of Met-Ed, dated October 30, 1974 - Incorporated by reference to Exhibit 2-E(11), Registration No. 2-59678.

74

Exhibit

Number

4-B-12	Supplemental Indenture of Met-Ed, dated October 31, 1974 - Incorporated by reference to Exhibit 2-E(12), Registration No. 2-59678.
4-B-13	Supplemental Indenture of Met-Ed, dated March 20, 1975 - Incorporated by reference to Exhibit 2-E(13), Registration No. 2-59678.
4-B-14	Supplemental Indenture of Met-Ed, dated September 25, 1975 - Incorporated by reference to Exhibit 2-E(15), Registration No. 2-59678.
4-B-15	Supplemental Indenture of Met-Ed, dated January 12, 1976 - Incorporated by reference to Exhibit 2-E(16), Registration No. 2-59678.
4-B-16	Supplemental Indenture of Met-Ed, dated March 1, 1976 - Incorporated by reference to Exhibit 2-E(17), Registration No. 2-59678.
4-B-17	Supplemental Indenture of Met-Ed, dated September 28, 1977 - Incorporated by reference to Exhibit 2-E(18), Registration No. 2-62212.
4-B-18	Supplemental Indenture of Met-Ed, dated January 1, 1978 - Incorporated by reference to Exhibit 2-E(19), Registration No. 2-62212.
4-B-19	Supplemental Indenture of Met-Ed, dated September 1, 1978 - Incorporated by reference to Exhibit 4-A(19), Registration No. 33-48937.
4-B-20	Supplemental Indenture of Met-Ed, dated June 1, 1979 - Incorporated by reference to Exhibit 4-A(20), Registration No. 33-48937.
4-B-21	Supplemental Indenture of Met-Ed, dated January 1, 1980 - Incorporated by reference to Exhibit 4-A(21), Registration No. 33-48937.
4-B-22	Supplemental Indenture of Met-Ed, dated September 1, 1981 - Incorporated by reference to Exhibit 4-A(22), Registration No. 33-48937.
4-B-23	Supplemental Indenture of Met-Ed, dated September 10, 1981 - Incorporated by reference to Exhibit 4-A(23), Registration No. 33-48937.
4-B-24	Supplemental Indenture of Met-Ed, dated December 1, 1982 - Incorporated by reference to Exhibit 4-A(24), Registration No. 33-48937.
4-B-25	Supplemental Indenture of Met-Ed, dated September 1, 1983 - Incorporated by reference to Exhibit 4-A(25), Registration No. 33-48937.
4-B-26	Supplemental Indenture of Met-Ed, dated September 1, 1984 - Incorporated by reference to Exhibit 4-A(26), Registration No. 33-48937.
4-B-27	Supplemental Indenture of Met-Ed, dated March 1, 1985 - Incorporated by reference to Exhibit 4-A(27), Registration No. 33-48937.
4-B-28	Supplemental Indenture of Met-Ed, dated September 1, 1985 - Incorporated by reference to Exhibit 4-A(28), Registration No. 33-48937.
4-B-29	Supplemental Indenture of Met-Ed, dated June 1, 1988 - Incorporated by reference to Exhibit 4-A(29), Registration No. 33-48937.
4-B-30	Supplemental Indenture of Met-Ed, dated April 1, 1990 - Incorporated by reference to Exhibit 4-A(30), Registration No. 33-48937.
4-B-31	Amendment dated May 22, 1990 to Supplemental Indenture of Met-Ed, dated April 1, 1990 - Incorporated by reference to Exhibit 4-A(31), Registration No. 33-48937.
4-B-32	Supplemental Indenture of Met-Ed, dated September 1, 1992 - Incorporated by reference to Exhibit 4-A(32)(a), Registration No. 33-48937.

75

Exhibit

Number

4-B-33	Supplemental Indenture of Met-Ed, dated December 1, 1993 - Incorporated by reference to Exhibit C-58, 1993 Annual Report of GPU on Form U5S, SEC File No. 30-126.
4-B-34	Supplemental Indenture of Met-Ed, dated July 15, 1995 - Incorporated by reference to Exhibit 4-B-35, 1995 Annual Report on Form 10-K, SEC File No. 1-446.
4-B-35	Supplemental Indenture of Met-Ed, dated August 15, 1996 - Incorporated by reference to Exhibit 4-B-35, 1996 Annual Report on Form 10-K, SEC File No. 1-446.
4-B-36	Supplemental Indenture of Met-Ed, dated May 1, 1997 - Incorporated by reference to Exhibit 4-B-36, 1997 Annual Report on Form 10-K, SEC File No. 1-446.
4-B-37	Supplemental Indenture of Met-Ed, dated July 1, 1999 Incorporated by reference to Exhibit 4-B-38, 1999 Annual Report on Form 10-K, SEC File No. 1-446.
4-B-38	Indenture between Met-Ed and United States Trust Company of New York, dated May 1, 1999 - Incorporated by reference to Exhibit A-11(a), Certificate Pursuant to Rule 24, SEC File No. 70-9329.
4-B-39	Senior Note Indenture between Met-Ed and United States Trust Company of New York, dated July 1, 1999 Incorporated by reference to Exhibit C-154 to GPU, Inc.s Annual Report on Form U5S for the year 1999, SEC File No. 30-126.
4-B-40	First Supplemental Indenture between Met-Ed and United States Trust Company of New York, dated August 1, 2000 Incorporated by reference to Exhibit 4-A, June 30, 2000 Quarterly Report on Form 10-Q, SEC File No. 1-446.
4-B-41	Supplemental Indenture of Met-Ed, dated May 1, 2001 Incorporated by reference to Exhibit 4-5, 2001 Annual Report on Form 10-K, SEC File No. 1-446.
4-B-42	Supplemental Indenture of Met-Ed, dated March 1,2003 Incorporated by reference to Exhibit 4-10, 2003 Annual Report on Form 10-K, SEC File No. 1-446.
4-G	Payment and Guarantee Agreement of Met-Ed, dated May 28, 1999 - Incorporated by reference to Exhibit B-1(a), Certificate Pursuant to Rule 24, SEC No. 70-9329.
4-H	Amendment No. 1 to Payment and Guarantee Agreement of Met-Ed, dated November 23, 1999 - Incorporated by reference to Exhibit 4-H, 1999 Annual Report on Form 10-K, SEC File No. 1-446.
(A)12.7	Consolidated fixed charge ratios.
(A)13.2	Met-Ed 2007 Annual Report to Stockholders (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed filed with SEC.)
(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 electronic format as an exhibit.

3.      Exhibits - Penelec

3-E	Restated Articles of Incorporation of Penelec, dated March 8, 1999 Incorporated by reference to Exhibit 3-G, 1999 Annual Report on Form 10-K, SEC File No. 1-3522.
3-F	By-Laws of Penelec as amended May 16, 2000, Incorporated by reference to Exhibit 3-F, 2000 Annual Report on Form 10-K, SEC File No. 1-03522.

76

Exhibit

Number

(A)3-G	Amended and Restated Articles of Incorporation of Pennsylvania Electric Company, Effective December 19, 2007
(A)3-H	Amended and Restated Bylaws of Pennsylvania Electric Company, dated December 14, 2007
4-C	Mortgage and Deed of Trust of Penelec, dated January 1, 1942, between Penelec and United States Trust Company of New York, Successor Trustee, and indentures supplemental thereto dated March 7, 1942 through May 1, 1960 - Incorporated by reference to Penelecs Instruments of Indebtedness Nos. 1-20, inclusive, filed as a part of Amendment No. 1 to 1959 Annual Report of GPU on Form U5S, SEC File Nos. 30-126 and 1-3292.
4-C-1	Supplemental Indentures to Mortgage and Deed of Trust of Penelec, dated May 1, 1961 through December 1, 1977 - Incorporated by reference to Exhibit 2-D(1) to 2-D(19), Registration No. 2-61502.
4-C-2	Supplemental Indenture of Penelec, dated June 1, 1978 - Incorporated by reference to Exhibit 4-A(2), Registration No. 33-49669.
4-C-3	Supplemental Indenture of Penelec, dated June 1, 1979 - Incorporated by reference to Exhibit 4-A(3), Registration No. 33-49669.
4-C-4	Supplemental Indenture of Penelec, dated September 1, 1984 - Incorporated by reference to Exhibit 4-A(4), Registration No. 33-49669.
4-C-5	Supplemental Indenture of Penelec, dated December 1, 1985 - Incorporated by reference to Exhibit 4-A(5), Registration No. 33-49669.
4-C-6	Supplemental Indenture of Penelec, dated December 1, 1986 - Incorporated by reference to Exhibit 4-A(6), Registration No. 33-49669.
4-C-7	Supplemental Indenture of Penelec, dated May 1, 1989 - Incorporated by reference to Exhibit 4-A(7), Registration No. 33-49669.
4-C-8	Supplemental Indenture of Penelec, dated December 1, 1990-Incorporated by reference to Exhibit 4-A(8), Registration No. 33-45312.
4-C-9	Supplemental Indenture of Penelec, dated March 1, 1992 - Incorporated by reference to Exhibit 4-A(9), Registration No. 33-45312.
4-C-10	Supplemental Indenture of Penelec, dated June 1, 1993 - Incorporated by reference to Exhibit C-73, 1993 Annual Report of GPU on Form U5S, SEC File No. 30-126.
4-C-11	Supplemental Indenture of Penelec, dated November 1, 1995 - Incorporated by reference to Exhibit 4-C-11, 1995 Annual Report on Form 10-K, SEC File No. 1-3522.
4-C-12	Supplemental Indenture of Penelec, dated August 15, 1996 - Incorporated by reference to Exhibit 4-C-12, 1996 Annual Report on Form 10-K, SEC File No. 1-3522.
4-C-13	Senior Note Indenture between Penelec and United States Trust Company of New York, dated April 1, 1999 - Incorporated by reference to Exhibit 4-C-13, 1999 Annual Report on Form 10-K, SEC File No. 1-3522.
4-C-14	Supplemental Indenture of Penelec, dated May 1, 2001.
4-C-15	Supplemental Indenture No. 1 of Penelec, dated May 1, 2001.
4-I	Payment and Guarantee Agreement of Penelec, dated June 16, 1999 - Incorporated by reference to Exhibit B-1(a), Certificate Pursuant to Rule 24, SEC File No. 70-9327.
4-J	Amendment No. 1 to Payment and Guarantee Agreement of Penelec, dated November 23, 1999 - Incorporated by reference to Exhibit 4-J, 1999 Annual Report on Form 10-K, SEC File No. 1-3522.

77

Exhibit

Number

4-K	Form of Pennsylvania Electric Company 6.05% Senior Notes due 2017 (incorporated by reference to a Form 8-K dated August 31, 2007)
10.1	Term Loan Agreement, dated as of March 15, 2005, among Pennsylvania Electric Company, Union Bank of California, N.A., as Administrative Agent, Lead Arranger and Lender, and National City Bank as Arranger, Syndication Agent and Lender. (March 18, 2005 Form 8-K, Exhibit 10.1).
(A)12.8	Consolidated fixed charge ratios.
(A)13.2	Penelec 2007 Annual Report to Stockholders (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed filed with SEC.)
(A)23.3	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 here in electronic format as an exhibit.

3.      Exhibits - Common Exhibits for Met-Ed and Penelec

10-1	First Amendment to Restated Partial Requirements Agreement, between Met-Ed, Penelec, and FES, dated January 1, 2003. (2004 Form 10-K, Exhibit 10-1).
10-2	Notice of Termination Tolling Agreement, Restated Partial Requirements Agreement (September 2005 10-Q, Exhibit 10-1).
10-3	Notice of Termination Tolling Agreement dated as of April 7, 2006; Restated Partial Requirements Agreement, dated January 1, 2003, by and among, Metropolitan Edison Company, Pennsylvania Electric Company, The Waverly Electric Power and Light Company and FirstEnergy Solutions Corp., as amended by a First Amendment to Restated Requirements Agreement, dated August 29, 2003 and by a Second Amendment to Restated Requirements Agreement, dated June 8, 2004 (Partial Requirements Agreement). (March 2006 10-Q, Exhibit 10-5)
10-4	Second Restated Partial Requirements Agreement, between Met-Ed, Penelec and FES, dated January 1, 2007. (2006 Form 10-K, Exhibit 10.6)
(A)	Provided here in electronic format as an exhibit.

3.     Exhibits - Common Exhibits for FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec

10-1	$2,750,000,000 Credit Agreement dated as of August 24, 2006 among FirstEnergy Corp.,FirstEnergy Solutions Corp., American Transmission Systems, Inc., Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company, as Borrowers, the banks party thereto, the fronting banks party thereto and the swing line lenders party thereto. (Form 8-K dated August 24, 2006, Exhibit 10-1)
(A)10-2	Consent and Amendment to $2,750,000,000 Credit Agreement dated November 2, 2007
(A)	Provided here in electronic format as an exhibit

78

Report of Independent Registered Public Accounting Firm

on

Financial Statement Schedules

To the Stockholders and Board of Directors of

FirstEnergy Corp.:

Our audits of the consolidated financial statements, and of the effectiveness of internal control over financial reporting referred to in our report dated February 28, 2008 appearing in the 2007 Annual Report to Stockholders of FirstEnergy Corp. (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

79

Report of Independent Registered Public Accounting Firm

on

Financial Statement Schedules

To the Stockholder and Board of Directors of

FirstEnergy Solutions Corp.:

Our audits of the consolidated financial statements, referred to in our report dated February 28, 2008appearing in the 2007 Annual Report to Stockholders of FirstEnergy Solutions Corp. (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

80

Report of Independent Registered Public Accounting Firm

on

Financial Statement Schedules

To the Stockholder and Board of Directors of

Ohio Edison Company:

Our audits of the consolidated financial statements, referred to in our report dated February 28, 2008 appearing in the 2007 Annual Report to Stockholders of Ohio Edison Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

81

Report of Independent Registered Public Accounting Firm

on

Financial Statement Schedules

To the Stockholder and Board of Directors of

The Cleveland Electric Illuminating Company:

Our audits of the consolidated financial statements, referred to in our report dated February 28, 2008appearing in the 2007 Annual Report to Stockholders of The Cleveland Electric Illuminating Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

82

Report of Independent Registered Public Accounting Firm

on

Financial Statement Schedules

To the Stockholder and Board of Directors of

The Toledo Edison Company:

Our audits of the consolidated financial statements, referred to in our report dated February 28, 2008appearing in the 2007 Annual Report to Stockholders of The Toledo Edison Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

83

Report of Independent Registered Public Accounting Firm

on

Financial Statement Schedules

To the Stockholder and Board of Directors of

Jersey Central Power & Light Company:

Our audits of the consolidated financial statements, referred to in our report dated February 28, 2008appearing in the 2007 Annual Report to Stockholders of Jersey Central Power & Light Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

84

Report of Independent Registered Public Accounting Firm

on

Financial Statement Schedules

To the Stockholder and Board of Directors of

Metropolitan Edison Company:

Our audits of the consolidated financial statements, referred to in our report dated February 28, 2008appearing in the 2007 Annual Report to Stockholders of Metropolitan Edison Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

85

Report of Independent Registered Public Accounting Firm

on

Financial Statement Schedules

To the Stockholder and Board of Directors of

Pennsylvania Electric Company:

Our audits of the consolidated financial statements, referred to in our report dated February 28, 2008appearing in the 2007 Annual Report to Stockholders of Pennsylvania Electric Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

86

SCHEDULE II

FIRSTENERGY CORP.
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
			Additions
						Charged
	Beginning		Charged			to Other							Ending
Description	Balance		to Income			Accounts				Deductions			Balance
						(In thousands)
Year Ended December 31, 2007:
Accumulated provision for
uncollectible accounts customers	$	43,214	$	53,522		$	50,165		(a)	$	111,334	(b)	$	35,567
other	$	23,964	$	4,933		$	406		(a)	$	7,379	(b)	$	21,924
Loss carryforward
tax valuation reserve	$	415,531	$	8,819		$	(393,734	)	(c)	$	-		$	30,616
Year Ended December 31, 2006:
Accumulated provision for
uncollectible accounts customers	$	37,733	$	60,461		$	34,259		(a)	$	89,239	(b)	$	43,214
other	$	26,566	$	3,956		$	2,554		(a)	$	9,112	(b)	$	23,964
Loss carryforward
tax valuation reserve	$	402,142	$	-		$	13,389			$	-		$	415,531
Year Ended December 31, 2005:
Accumulated provision for
uncollectible accounts customers	$	34,476	$	52,653		$	33,216		(a)	$	82,612	(b)	$	37,733
other	$	26,069	$	(49	)	$	11,098		(a)	$	10,552	(b)	$	26,566
Loss carryforward
tax valuation reserve	$	419,978	$	(4,758	)	$	(13,078	)		$	-		$	402,142
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.
(c) Represents the reversal of tax capital loss carryforward reserves (offset to goodwill) due to the utilitzation of the carryforward in 2007.

87

SCHEDULE II

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
			Additions
						Charged
	Beginning		Charged			to Other							Ending
Description	Balance		to Income			Accounts				Deductions			Balance
						(In thousands)
Year Ended December 31, 2007:
Accumulated provision for
uncollectible accounts customers	$	7,938	$	94		$	532		(a)	$	492	(b)	$	8,072
other	$	5,593	$	9		$	-			$	5,593	(b)	$	9
Year Ended December 31, 2006:
Accumulated provision for
uncollectible accounts customers	$	11,531	$	2,244		$	789		(a)	$	6,626	(b)	$	7,938
other	$	5,599	$	15		$	7		(a)	$	28	(b)	$	5,593
Year Ended December 31, 2005:
Accumulated provision for
uncollectible accounts customers	$	13,661	$	-		$	1,357		(a)	$	3,487	(b)	$	11,531
other	$	6,330	$	(74	)	$	(638	)	(a)	$	19	(b)	$	5,599
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

88

SCHEDULE II

OHIO EDISON COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
			Additions
					Charged
	Beginning		Charged		to Other							Ending
Description	Balance		to Income		Accounts				Deductions			Balance
					(In thousands)
Year Ended December 31, 2007:
Accumulated provision for
uncollectible accounts customers	$	15,033	$	10,513	$	30,234		(a)	$	47,748	(b)	$	8,032
other	$	1,985	$	4,117	$	(240	)	(a)	$	223	(b)	$	5,639
Year Ended December 31, 2006:
Accumulated provision for
uncollectible accounts customers	$	7,619	$	22,466	$	11,817		(a)	$	26,869	(b)	$	15,033
other	$	4	$	2,218	$	473		(a)	$	710	(b)	$	1,985
Year Ended December 31, 2005:
Accumulated provision for
uncollectible accounts customers	$	6,302	$	17,250	$	8,548		(a)	$	24,481	(b)	$	7,619
other	$	64	$	182	$	90		(a)	$	332	(b)	$	4
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

89

SCHEDULE II

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
			Additions
					Charged
	Beginning		Charged		to Other							Ending
Description	Balance		to Income		Accounts				Deductions			Balance
					(In thousands)
Year Ended December 31, 2007:
Accumulated provision for
uncollectible accounts customers	$	6,783	$	17,998	$	7,842		(a)	$	25,083	(b)	$	7,540
other	$	-	$	431	$	124		(a)	$	122	(b)	$	433
Year Ended December 31, 2006:
Accumulated provision for
uncollectible accounts customers	$	5,180	$	14,890	$	10,067		(a)	$	23,354	(b)	$	6,783
other	$	-	$	22	$	138		(a)	$	160	(b)	$	-
Year Ended December 31, 2005:
Accumulated provision for
uncollectible accounts customers	$	-	$	12,238	$	13,704		(a)	$	20,762	(b)	$	5,180
other	$	293	$	92	$	(12	)	(a)	$	373	(b)	$	-
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

90

SCHEDULE II

THE TOLEDO EDISON COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
			Additions
					Charged
	Beginning		Charged		to Other							Ending
Description	Balance		to Income		Accounts				Deductions			Balance
					(In thousands)
Year Ended December 31, 2007:
Accumulated provision for
uncollectible accounts	$	430	$	361	$	13		(a)	$	189	(b)	$	615
Year Ended December 31, 2006:
Accumulated provision for
uncollectible accounts	$	-	$	440	$	118		(a)	$	128	(b)	$	430
Year Ended December 31, 2005:
Accumulated provision for
uncollectible accounts	$	2	$	-	$	(2	)	(a)	$	-		$	-
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

91

SCHEDULE II

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
			Additions
						Charged
	Beginning		Charged			to Other						Ending
Description	Balance		to Income			Accounts			Deductions			Balance
						(In thousands)
Year Ended December 31, 2007:
Accumulated provision for
uncollectible accounts customers	$	3,524	$	8,563		$	4,049	(a)	$	12,445	(b)	$	3,691
other	$	-	$	-		$	-		$	-		$	-
Year Ended December 31, 2006:
Accumulated provision for
uncollectible accounts customers	$	3,830	$	4,945		$	4,643	(a)	$	9,894	(b)	$	3,524
other	$	204	$	(201	)	$	866	(a)	$	869	(b)	$	-
Year Ended December 31, 2005:
Accumulated provision for
uncollectible accounts customers	$	3,881	$	5,997		$	2,783	(a)	$	8,831	(b)	$	3,830
other	$	162	$	112		$	949	(a)	$	1,019	(b)	$	204
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

92

SCHEDULE II

METROPOLITAN EDISON COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
			Additions
					Charged
	Beginning		Charged		to Other						Ending
Description	Balance		to Income		Accounts			Deductions			Balance
					(In thousands)
Year Ended December 31, 2007:
Accumulated provision for
uncollectible accounts customers	$	4,153	$	9,971	$	3,548	(a)	$	13,345	(b)	$	4,327
other	$	2	$	245	$	18	(a)	$	264	(b)	$	1
Year Ended December 31, 2006:
Accumulated provision for
uncollectible accounts customers	$	4,352	$	7,070	$	4,108	(a)	$	11,377	(b)	$	4,153
other	$	-	$	15	$	36	(a)	$	49	(b)	$	2
Year Ended December 31, 2005:
Accumulated provision for
uncollectible accounts customers	$	4,578	$	8,704	$	3,503	(a)	$	12,433	(b)	$	4,352
other	$	-	$	-	$	-		$	-		$	-
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

93

SCHEDULE II

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
			Additions
					Charged
	Beginning		Charged		to Other						Ending
Description	Balance		to Income		Accounts			Deductions			Balance
					(In thousands)
Year Ended December 31, 2007:
Accumulated provision for
uncollectible accounts customers	$	3,814	$	8,351	$	3,958	(a)	$	12,218	(b)	$	3,905
other	$	3	$	181	$	3	(a)	$	82	(b)	$	105
Year Ended December 31, 2006:
Accumulated provision for
uncollectible accounts customers	$	4,184	$	6,381	$	4,368	(a)	$	11,119	(b)	$	3,814
other	$	2	$	105	$	173	(a)	$	277	(b)	$	3
Year Ended December 31, 2005:
Accumulated provision for
uncollectible accounts customers	$	4,712	$	8,464	$	3,296	(a)	$	12,288	(b)	$	4,184
other	$	4	$	70	$	2	(a)	$	74	(b)	$	2
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

94

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

FIRSTENERGY CORP.

BY:  /s/Anthony J. Alexander

Anthony J. Alexander

President and Chief Executive Officer

Date:  February 28, 2008

95

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:

/s/    George M. Smart	/s/    Anthony J. Alexander
George M. Smart	Anthony J. Alexander
Chairman of the Board	President and Chief Executive Officer
	and Director (Principal Executive Officer)
/s/    Richard H. Marsh	/s/    Harvey L. Wagner
Richard H. Marsh	Harvey L. Wagner
Senior Vice President and Chief Financial	Vice President, Controller and Chief Accounting
Officer (Principal Financial Officer)	Officer (Principal Accounting Officer)
/s/    Paul T. Addison	/s/    Ernest J. Novak, Jr.
Paul T. Addison	Ernest J. Novak, Jr.
Director	Director
/s/    Michael J. Anderson	/s/    Catherine A. Rein
Michael J. Anderson	Catherine A. Rein
Director	Director
/s/    Carol A. Cartwright	/s/    Wes M. Taylor
Carol A. Cartwright	Wes M. Taylor
Director	Director
/s/    William T. Cottle	/s/    Jesse T. Williams, Sr.
William T. Cottle	Jesse T. Williams, Sr.
Director	Director
/s/    Robert B. Heisler, Jr.
Robert B. Heisler, Jr.
Director

Date:  February 28, 2008

96

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

FIRSTENERGY SOLUTIONS CORP.

BY:    /s/  Charles E. Jones

Charles E. Jones

President

Date:  February 28, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:

/s/    Charles E. Jones	/s/    Richard H. Marsh
Charles E. Jones	Richard H. Marsh
President	Senior Vice President and Chief
(Principal Executive Officer)	Financial Officer and Director
	(Principal Financial Officer)
/s/    Anthony J. Alexander	/s/    Harvey L. Wagner
Anthony J. Alexander	Harvey L. Wagner
Director	Vice President and Controller
	(Principal Accounting Officer)
/s/    Joseph J. Hagan
Joseph J. Hagan
Director

Date:  February 28, 2008

97

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

OHIO EDISON COMPANY

BY:    /s/  Anthony J. Alexander

Anthony J. Alexander

President

Date:  February 28, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:

/s/    Anthony J. Alexander	/s/    Richard R. Grigg
Anthony J. Alexander	Richard R. Grigg
President and Director	Executive Vice President and Chief
(Principal Executive Officer)	Operating Officer and Director
/s/    Richard H. Marsh	/s/    Harvey L. Wagner
Richard H. Marsh	Harvey L. Wagner
Senior Vice President and Chief	Vice President and Controller
Financial Officer and Director	(Principal Accounting Officer)
(Principal Financial Officer)

Date:  February 28, 2008

98

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

BY:    /s/  Anthony J. Alexander

Anthony J. Alexander

President

Date:  February 28, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:

/s/    Anthony J. Alexander	/s/    Richard R. Grigg
Anthony J. Alexander	Richard R. Grigg
President and Director	Executive Vice President and Chief
(Principal Executive Officer)	Operating Officer and Director
/s/    Richard H. Marsh	/s/    Harvey L. Wagner
Richard H. Marsh	Harvey L. Wagner
Senior Vice President and Chief	Vice President and Controller
Financial Officer and Director	(Principal Accounting Officer)
(Principal Financial Officer)

Date:  February 28, 2008

99

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

THE TOLEDO EDISON COMPANY

BY:    /s/  Anthony J. Alexander

Anthony J. Alexander

President

Date:  February 28, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:

/s/    Anthony J. Alexander	/s/    Richard R. Grigg
Anthony J. Alexander	Richard R. Grigg
President and Director	Executive Vice President and Chief
(Principal Executive Officer)	Operating Officer and Director
/s/    Richard H. Marsh	/s/    Harvey L. Wagner
Richard H. Marsh	Harvey L. Wagner
Senior Vice President and Chief	Vice President and Controller
Financial Officer and Director	(Principal Accounting Officer)
(Principal Financial Officer)

Date:  February 28, 2008

100

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

JERSEY CENTRAL POWER & LIGHT COMPANY

BY:    /s/  Stephen E. Morgan

Stephen E. Morgan

President

Date:  February 28, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:

/s/    Stephen E. Morgan	/s/    Paulette R. Chatman
Stephen E. Morgan	Paulette R. Chatman
President and Director (Principal Executive Officer)	Controller (Principal Financial and Accounting Officer)
/s/    Bradley S. Ewing	/s/    Donald R. Schneider
Bradley S. Ewing	Donald R. Schneider
Director	Director
/s/    Mark A. Julian	/s/    Jesse T. Williams, Sr.
Mark A. Julian	Jesse T. Williams, Sr.
Director	Director
/s/    Gelorma E. Persson
Gelorma E. Persson
Director

Date:  February 28, 2008

101

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

METROPOLITAN EDISON COMPANY

BY:    /s/  Anthony J. Alexander

Anthony J. Alexander

President

Date:  February 28, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:

/s/    Anthony J. Alexander	/s/    Richard R. Grigg
Anthony J. Alexander	Richard R. Grigg
President and Director	Executive Vice President and Chief
(Principal Executive Officer)	Operating Officer and Director
/s/    Richard H. Marsh	/s/    Harvey L. Wagner
Richard H. Marsh	Harvey L. Wagner
Senior Vice President and Chief	Vice President and Controller
Financial Officer and Director	(Principal Accounting Officer)
(Principal Financial Officer)

Date:  February 28, 2008

102

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PENNSYLVANIA ELECTRIC COMPANY

BY:    /s/  Anthony J. Alexander

Anthony J. Alexander

President

Date:  February 28, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:

/s/    Anthony J. Alexander	/s/    Richard R. Grigg
Anthony J. Alexander	Richard R. Grigg
President and Director	Executive Vice President and Chief
(Principal Executive Officer)	Operating Officer and Director
/s/    Richard H. Marsh	/s/    Harvey L. Wagner
Richard H. Marsh	Harvey L. Wagner
Senior Vice President and Chief	Vice President and Controller
Financial Officer and Director	(Principal Accounting Officer)
(Principal Financial Officer)

 Date:  February 28, 2008

103

EX-10.1

                                                                                                  December 31, 2007

Mr. Richard R. Grigg

4140 Far-O-Way Lane

Richfield, OH 44286

Special Severance Agreement

Dear Dick:

The Board of Directors (the "Board") of FirstEnergy Corp. (the "Company") recognizes that, as is the case with many publicly held corporations, there always exists the possibility of a changein control of the Company.  This possibility and the uncertainty it creates may result in the loss or distraction of members of management of the Company and its subsidiaries to the detriment of the Company and its shareholders.

The Board considers the establishment, maintenance, and continuity of a sound and vital management to be essential to protecting and enhancing the best interests of the Company and its shareholders. The Board also believes that when a change in control is perceived as imminent, or is occurring, the Board should be able to receive and rely on disinterested advice from management regarding the best interests of the Company and its shareholders without concern that members of management might be distracted or concerned by the personal uncertainties and risks created by their perception of an imminent or occurring change in control.

Accordingly, the Board has determined that appropriate steps should be taken to assure the Company of the continued employment and attention and dedication to duty of certain members of management of the Company and to ensure the availability of their disinterested advice, notwithstanding the possibility, threat or occurrence of a change in control.

Therefore, in order to fulfill the above purposes, the Board has designated you as eligible for severance benefits as set forth below.

                        1.        Offer

  In order to induce you to remain in the employ of the Company and to provide continued services to the Company now and in the event that a Change in Control is imminent or occurring, this letter agreement (the "Agreement") sets forth severance and other benefits which the Company offers to pay to you in the event of your Termination of Employment under certain circumstances (in the manner described in Section 5 below) subsequent to a Change in Control of the Company (as defined in Section 4 below). For purposes of this Agreement, “Termination of Employment” shall mean a separation from service within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended, (“Section 409A”) with the Company and all of its affiliates, for any reason, including without limitation, quit, discharge, retirement, leave of absence (including military leave, sick leave, or other bona fide leave of absence such as temporary employment by the government if the period of such leave exceeds the greater of six months, or the period for which your right to reemployment is provided either by statute or by contract) or permanent decrease in service to a level that is no more than twenty percent (20%) of its prior level. For this purpose, whether a Termination of Employment has occurred is determined based on whether it is reasonably anticipated that no further services will be performed by you after a certain date or that the level of bona fide services you will perform after such date (whether as an employee or as an independent contractor) would permanently decrease to no more than twenty percent (20%) of the average level of bona fide services performed (whether as an employee or an independent contractor) over the immediately preceding 36-month period (or the full period of services if you have been providing services for less than 36 months).

                        2.        Operation

This Agreement shall become effective as of the date of commencement of the term set forth in Section 3 below, but anything in this Agreement to the contrary notwithstanding, neither this Agreement nor any of its provisions shall be operative unless and until there has been a Change in Control while you are still an employee of the Company, nor shall this Agreement govern or affect your employment relationship with the Company except as explicitly set forth herein.  Upon a Change in Control, if you are still employed by the Company, this Agreement and all of its provisions shall become operative immediately on the later of (a) the date of the Change in Control or (b) the first day of the term of this Agreement.  If your employment relationship with the Company is terminated before a Change in Control, you shall have no rights or obligations under this Agreement.

3.        Term

(a)    Term of Agreement:  The term of this Agreement shall commence immediately upon the date hereof and continue until December 31, 2009.  This Agreement shall supersede all other agreements of a like or similar nature.  Such former agreements are considered null and void as of the date on which the term of this Agreement commences.

(b)    One-Year Evergreen Provision:  Subject to Subsection (c) below, this Agreement shall be reviewed annually commencing in 2008 by the Board at a regular meeting held between September 1 and December 31 of each year.  At such yearly review, the Board shall consider whether or not to extend the term of this Agreement for an additional year.  Unless the Board affirmatively votes not to extend this Agreement at such yearly review, the term of this Agreement shall be extended for a period of one (1) year from the previous termination date.  In the event the Board so votes not to extend this Agreement, the termination date of this Agreement shall not be extended and shall remain the same termination date as in effect previously.

(c)     Subsection (b) above notwithstanding, upon the occurrence of a Change in Control, this Agreement shall be automatically extended for a period of twenty-four (24) full calendar months commencing on the date of such Change in Control.  At the end of such twenty-four (24) month period, this Agreement shall terminate.

4.        Change in Control

For the purpose of this Agreement, a "Change in Control" shall mean:

(a)     The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act")) (a "Person") of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 50% (25% if such Person proposes any individual for election to the Board or any member of the Board is the representative of such Person) or more of either (i) the then outstanding shares of common stock of the Company (the "Outstanding Company Common Stock") or (ii) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the "Outstanding Company Voting Securities"); provided, however, that the following acquisitions shall not constitute a Change in Control:  (i) any acquisition directly from the Company (excluding an acquisition by virtue of the exercise of a conversion privilege), (ii) any acquisition by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (iv) any acquisition by any corporation pursuant to a reorganization, merger or consolidation, if, following such reorganization, merger or consolidation, the conditions described in clauses (i), (ii) and (iii) of Subsection (c) of this Section 4 are satisfied; or

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(b)     Individuals who, as of the date hereof, constitute the Board (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company's shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of either an actual or threatened election contest (within the meaning of solicitations subject to Rule 14a-12(c) of Regulation 14A promulgated under the Exchange Act or any such successor rule) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or

(c)     Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company, in each case, unless, following such reorganization, merger, consolidation or sale or other disposition of assets, (i) more than 75% of, respectively, the then outstanding shares of common stock of the corporation resulting from such reorganization, merger or consolidation or acquiring such assets and the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors is then beneficially owned, directly or indirectly, by all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such reorganization, merger, consolidation or sale or other disposition of assets in substantially the same proportions as their ownership, immediately prior to such reorganization, merger, consolidation or sale or other disposition of assets, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (ii) no Person (excluding the Company, any employee benefit plan (or related trust) of the Company or such corporation resulting from such reorganization, merger, consolidation or acquiring such assets and any Person beneficially owning, immediately prior to such reorganization, merger, consolidation or sale or other disposition of assets, directly or indirectly, 25% or more of the Outstanding Company Common Stock or Outstanding Company Voting Securities, as the case may be) beneficially owns, directly or indirectly, 25% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such reorganization, merger or consolidation or acquiring such assets or the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors and (iii) at least a majority of the members of the board of directors of the corporation resulting from such reorganization, merger or consolidation or acquiring such assets were members of the Incumbent Board at the time of the execution of the initial agreement providing for such reorganization, merger, consolidation or sale or other disposition of assets; or

(d)     Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.

5.        Employment Termination

(a)     Termination of Employment Following a Change in Control: If a Change in Control occurs, you shall be entitled to the benefits described in Section 6 if, at any time during the twenty-four (24) month period following the Change in Control:

                                              (1)     You incur an involuntary Termination of Employment for any reason other than for Cause; or

                                              (2)     You incur a voluntary Termination of Employment for Good Reason within thirty days following an event that constitutes Good Reason as defined below.

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           (b)      Definition of Good Reason:   For purposes of this Agreement, “Good Reason” shall mean the initial occurrence, without your consent, of one or more of the following events:

(1) a material diminution in your base pay;

(2) a material diminution in your authority, duties or responsibilities;

(3) a material diminution in the authority, duties or responsibilities of the supervisor to whom you are required to report, including a requirement that you report to a corporate officer or employee instead of reporting directly to the Board if you reported to the Board directly immediately before the Change in Control;

(4) a material diminution in the budget over which you retain authority;

(5) a material change in the geographic location at which you must perform services; and

(6) any other action or inaction that constitutes a material breach by the Company of any employment agreement under which you provide services;

  provided, however, that “Good Reason” shall not be deemed to exist unless:

(A) you have provided notice to the Company of the existence of one or more of the conditions listed in (1) through (6) above within 90 days after the initial occurrence of such condition or conditions; and

(B) such condition or conditions have not been cured by the Company within 30 days after receipt of such notice.

  (c)     Definition of Cause:   For purposes of this Agreement, the term Cause shall meanthat, prior to any Termination of Employment, you shall have committed:

(i) and been convicted of a criminal violation involving fraud, embezzlement or theft in connection with your duties or in the course of your employment with the Company or any subsidiary;

(ii) intentional wrongful damage to property of the Company or any subsidiary;

(iii) intentional wrongful disclosure of secret processes or confidential information of the Company or any subsidiary;

(iv) intentional wrongful competition with Company as set forth in Section 8 below; or

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(v) gross negligence in the performance of your material duties to the Company;

and any such act or omission shall have been demonstrably and materially harmful to the Company.  For purposes of this Agreement, no act or failure to act on your part shall be deemed “intentional” if it was due primarily to an error in judgment or negligence, but shall be deemed “intentional” only if done or omitted to be done by you not in good faith and without reasonable belief that your action or omission was in the best interest of the Company.  Notwithstanding the foregoing, you shall not be deemed to have been terminated for “Cause” hereunder unless and until there shall have been delivered to you a copy of a resolution duly adopted by the affirmative vote of not less than three quarters of the Board then in office at a meeting of the Board called and held for such purpose, after reasonable notice to you and an opportunity for you, together with your counsel (if you choose to have counsel present at such meeting), to be heard before the Board, finding that, in the good faith opinion of the Board, you had committed an act constituting “Cause” as herein defined and specifying the particulars thereof in detail.  Nothing herein will limit your right or your beneficiaries to contest the validity or propriety of any such determination.

(d)     Notice of Termination:   Any termination by the Company for Cause, or by you for Good Reason, shall be communicated by Notice of Termination to the other party hereto given in accordance with Section 12 hereof.  For purposes of this Agreement, a "Notice of Termination" means a written notice which (i) indicates the specific termination provision in this Agreement relied upon, and (ii) to the extent applicable, sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of your employment under the provision so indicated.

(e)     Date of Termination:  "Date of Termination" shall mean the effective date of your Termination of Employment.

(f)      Normal Retirement:   If your employment with the Company is terminated due to Normal Retirement, you shall not be entitled to severance benefits under this Agreement, regardless of the occurrence of a Change in Control.  A termination by Normal Retirement shall have occurred where your termination is caused by the fact that you have reached the first date on which you are entitled to receive a pension benefit that is not reduced for early payment under the FirstEnergy Corp. Master Pension Plan or any successor pension plan.

(g)     Termination for Cause:  If subsequent to a Change in Control, your employment is terminated by the Company for Cause, the Company shall pay you your full base salary through the Date of Termination at the rate in effect at the time Notice of Termination is given, and you shall also receive all accrued or vested benefits of any kind to which you are, or would otherwise have been, entitled through the Date of Termination (as defined in Subsection (e) of this Section 5), and the Company shall thereupon have no further obligation to you under this Agreement.

(h)     Disability or Death:  If termination of your employment with the Company results from your Disability or death, you shall not be entitled to severance benefits under this Agreement, regardless of the occurrence of a Change in Control.  You or your designated beneficiary, in the case of your death, shall receive all accrued or vested benefits of any kind to which you are, or would otherwise have been, entitled through the date your employment with the Company is terminated, and the Company shall thereupon have no further obligation to you under this Agreement.

5

For purposes of this Agreement, "Disability" shall mean,  a disability as defined in the FirstEnergy Corp. Master Pension Plan or successor qualified pension plan under the pertinent provisions of the plan that apply to you  except for purposes of this provision you need not have completed ten (10) years of service with the Company.

6.        Severance Benefits

If, within a period of twenty-four (24) full calendar months after a Change in Control of the Company, you incur a Termination of Employment under circumstances described in Section 5(a) of this Agreement, the following shall be applicable:

(a)       The Company shall pay to you as soon as possible but not later than thirty (30) business days following the Termination of Employment a lump sum severance benefit, payable in cash, in the amounts determined as provided below:

(1)          Your full base salary through the date of your Termination of Employment at the rate in effect at the time Notice of Termination is given.

(2)          In lieu of further salary payments to you for periods subsequent to your Termination of Employment and, in part, as consideration for the non-competition agreement set forth in Section 8 of this Agreement, an amount equal to 2.99 multiplied by the sum of: (i) your annual base salary at the rate in effect as of the date of your Termination of Employment (or, if higher, at the rate in effect as of the time of the Change in Control) plus (ii) the target annual short-term incentive amount in effect  for you under the FirstEnergy Corp. 2007 Incentive Compensation Plan or any successor incentive compensation plan (“ICP”) in the year during which your Termination of Employment occurs whether or not fully paid.

(b)        For purposes of the ICP, you shall be considered to have retired and will be paid the pro rata portion of any incentive award earned, if any, and any long-term deferred incentive awards earned, if any, per the terms of the plan.

(c)        For purposes of FirstEnergy stock options issued pursuant to the FirstEnergy Executive and Director Incentive Compensation Plan or any successor plan, all outstanding options will follow the terms of the option agreement(s).

(d)        For purposes of the Company's group health and life insurance plans:

(1)        If, on the date of your Termination of Employment, the addition of three (3) years to your age would make you eligible to qualify for retiree health or life insurance coverage under the Company’s then-in-effect group health or life insurance plans, then you shall be considered as having retired for purposes of retiree health or life insurance coverage under such plan or plans for which the addition of three (3) years to your age would make you so eligible and for purposes of such coverage you shall be credited with three (3) additional years of age and service.  You shall be responsible for paying the normal retiree share of the applicable premiums for retiree coverage under the group health and life insurance plans.

            (2)        If you are not entitled to retiree health or life insurance coverage under Subsection (d)(1), then you shall be entitled to continue to participate, on the same terms and conditions as active employee participants, in such plan or plans for which you are not so entitled to retiree coverage for a period of three (3) years after the date of your Termination of Employment.  During such continuation period, you shall be responsible for paying the normal employee share of the applicable premiums for coverage under the health and life insurance plans.

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(3)        The Company shall have the right to modify, amend or discontinue the Company’s group health and life insurance plans following the date of your Termination of Employment and your continued participation therein, and the continued participation of any other person therein under Subsection (h) below, shall be subject to such modification, amendment or discontinuation if such modification, amendment or discontinuation applies generally to the then-current participants in such plan.

(4)        If the Company is not permitted to provide continuing coverage under the terms of the Company’s group health and life insurance plans and related trusts, then the Company may purchase health and/or life insurance for you for the period specified in Subsection (d)(1) or (d)(2), as applicable, with coverage comparable to the applicable coverage under the Company’s group health or life insurance plan, as applicable, then in effect, as the same may have been modified amended or discontinued in accordance with the terms and provisions of the applicable plan under this Subsection (d).

(5)        The health benefit continuation provided under this Subsection (d) shall satisfy the Company’s obligations to provide, and any rights that you may have to, COBRA coverage continuation under the health care continuation requirements under the federal Consolidated Omnibus Budget Reconciliation Act, as amended, Part VI of Subtitle B of Title I of the Employee Retirement Income Security Act of 1974, as amended, and Section 4980B(f) of the Internal Revenue Code of 1986, as amended (the "Code"), or any successor provisions thereto.

(e)        As further provided in the FirstEnergy Corp. Executive Deferred Compensation Plan ("Deferred Compensation Plan"), you shall be credited with three (3) additional years of age and service.  Notwithstanding anything in this Agreement or the Deferred Compensation Plan to the contrary, the additional age and service credits provided hereunder shall not accelerate the payout under such plans if such acceleration would violate the rules under Section 409A.

(f)         If, on the date of your Termination of Employment you are a participant in the FirstEnergy Corp. Supplemental Executive Retirement Plan ("SERP"), and as further provided in the SERP, you shall be credited with three (3) additional years of age and service, and your accrued benefit, if any, shall be fully vested.  Notwithstanding anything in this Agreement or the SERP to the contrary, the additional age and service credits provided hereunder shall not accelerate the payout under such plans if such acceleration would violate the rules under Section 409A.

(g)        In the event that because of their relationship to you, members of your family or other individuals are covered by any plan, program, or arrangement described in Subsection (d) above immediately prior to the date of your Termination of Employment, the provisions set forth in Subsection (d) shall apply equally to require the continued coverage of such persons; provided, however, that if under the terms of any such plan, program or arrangement, any such person would have ceased to be eligible for coverage other than because of your Termination of Employment during the period in which the Company is obligated to continue coverage for you, nothing set forth herein shall obligate the Company to continue to provide coverage which would have ceased even if you had remained an employee of the Company.

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(h)        Other Benefits Payable:  The severance benefits described in Subsections (a), (b), (c), (d), (e), (f), and (g) above shall be payable in addition to, and not in lieu of, all other accrued or vested or earned but deferred compensation, rights, options or other benefits which may be owed to you following your Termination of Employment (and are not contingent on any Change in Control preceding such Termination of Employment), including but not limited to, accrued and/or banked vacation, amounts or benefits payable, if any, under any bonus or other compensation plans, stock option plan, stock ownership plan, stock purchase plan, life insurance plan, health plan, disability plan or similar plan.

(i)         Payment Obligations:  Other than as set forth in the Deferred Compensation Plan or the SERP, upon a Change in Control the Company's obligations to pay the severance benefits or make any other payments described in this Section 6 shall not be affected by any set-off, counterclaim, recoupment, defense or other right which the Company or any of its subsidiaries may have against you or anyone else.

(j)         Legal Fees and Expenses:   For a period of five (5) years following your Termination of Employment and subject to and contingent upon the occurrence of a Change in Control, the Company agrees to pay promptly as incurred, to the full extent permitted by law, all legal fees and expenses which you may reasonably thereafter incur as a result of any contest, litigation or arbitration (regardless of the outcome thereof) by the Company, you or others of the validity or enforceability of, or liability under, any provision of this Agreement, the Deferred Compensation Plan, or the SERP (including any contest by you about the amount of any payment pursuant to this Agreement, the Deferred Compensation Plan or the SERP), plus in each case interest on any delayed payment at the rate of 150% of the Prime Rate as published in the Wall Street Journal in the Money Rates Table on the business day immediately preceding the conclusion of any such contest, litigation or arbitration.

(k)         Certain Additional Payments by the Company:

(1)       Anything in this Agreement to the contrary notwithstanding, in the event that you become entitled to severance benefits under this Section 6 hereof, the Deferred Compensation Plan, the SERP or otherwise, and it shall be determined that any payment or distribution by the Company to you or for your benefit, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement, the Deferred Compensation Plan, the SERP or otherwise (a "Payment"), would be subject to the excise tax imposed by Section 4999 of the Code or any interest or penalties with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the "Excise Tax"), then you shall be entitled to receive an additional payment (a "Gross-Up Payment") in an amount such that after payment by you of all taxes (including any interest or penalties imposed with respect to such taxes), including any Excise Tax, imposed upon the Gross-Up Payment, you retain an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments.  Such Gross-Up Payment shall be made by the Company to you by the end of your taxable year next following the taxable year in which such taxes are remitted by you.

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(2)       All determinations required to be made under this Subsection (l), including whether a Gross-Up Payment is required and the amount of such Gross-Up Payment, shall be made in good faith by the Company which shall provide detailed supporting calculations to you within thirty (30) business days after the date of your Termination of Employment, if applicable, or such earlier time as is requested by the Company.  If the Company determines that no Excise Tax is payable by you, it shall furnish you with an opinion of counsel that you have substantial authority not to report any Excise Tax on your federal income tax return.  Except as hereinafter provided, any determination by the Company shall be binding upon the Company and you.  As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Company hereunder, it is possible that Gross-Up Payments which will not have been made by the Company should have been made ("Underpayment"), consistent with the calculations required to be made hereunder.  In the event that you are required to make a payment of any Excise Tax, the Company shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be promptly paid by the Company to you or for your benefit.

7.         Assignability

This Agreement is binding on and is for the benefit of the parties hereto and their respective successors, heirs, executors, administrators and other legal representatives.  Neither this Agreement nor any right or obligation hereunder may be assigned by the Company (except to any subsidiary or affiliate) or by you.

8.         Non-Competition

                  If, subsequent to a Change in Control of the Company, you incur a Termination of Employment under circumstances described in Section 5(a) of this Agreement, then for a period of twenty-four (24) months after your Termination of Employment, you shall not on your own account without the consent of the Company, or as a shareholder, employee, officer, director, consultant or otherwise, engage directly or indirectly in any business or enterprise which is in competition with the Company.  For all purposes of this Agreement the words "competition with the Company" shall mean:

(a)   Directly participate or engage, on the behalf of other parties, in the purchase or sale of products, supplies or services of the kind, nature or description of those sold by the Company,

(b)   Solicit, divert, take away or attempt to take away any of the Company’s Customers or the business or patronage of any such Customers of the Company;

(c)   Solicit, entice, lure, employ or endeavor to employ any of the Company’s employees;

(d)   Divulge to others or use for your own benefit any confidential information obtained during the course of your employment with Company relative to sales, services, processes, methods, machines, manufacturers, compositions, ideas, improvements, patents, trademarks, or inventions belonging to or relating to the affairs of Company;

(e)   Divulge to others or use to your own benefit any trade secrets belonging to the Company obtained during the course of your employment or that you became aware of as a consequence of your employment.

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The term “Customer” shall mean any person, firm, association, corporation or other entity to which you or the Company has sold the Company’s products or services within the twenty-four (24) month period immediately preceding your Termination of Employment with the Company or to which you or the Company is in the process of selling its products or services, or to which you or the Company has submitted a bid, or is in the process of submitting a bid to sell the Company’s products or services.

However, nothing herein contained shall prevent you from purchasing and holding for investment less than 5% of the shares of any corporation the shares of which are regularly traded either on a national securities exchange or in the over-the-counter market, and notwithstanding any provision hereof, you may disclose to any and all persons, without limitation of any kind, the tax treatment and any facts that may be relevant to the tax structure of the transactions contemplated by this Agreement, other than any information for which nondisclosure is reasonably necessary in order to comply with applicable federal or state securities laws, and except that, with respect to any document or other information that in either case contains information concerning the tax treatment or tax structure of such transactions as well as other information, this paragraph shall apply only to such portions of the document or similar item that is relevant to an understanding of such tax treatment or tax structure.

 9 .      Non-Disparagement

                                   You and the Company agree that neither party shall disparage the other nor shall either party communicate to any person and/or entity in a manner that is disrespectful, demeaning, and/or insulting toward the other party.

10.      Successor

The Company shall require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to assume expressly and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place.  As used in this Agreement, "Company" shall mean the Company as herein before defined and any successor to its business and/or assets as aforesaid which assumes and agrees to perform this Agreement by operation of law, or otherwise.  Failure of the Company to obtain such agreement prior to the effectiveness of such succession shall be a breach of this Agreement and shall entitle you to compensation from the Company in the same amount and on the same terms as you would be entitled hereunder if you incurred a Termination of Employment under Section 5(a)(2) of this Agreement.

This Agreement shall inure to the benefit of and be enforceable by your personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees.  If you should die while any amounts would still be payable to you hereunder if you had continued to live, all such amounts, unless otherwise provided herein, shall be paid to such beneficiary or beneficiaries as you shall have designated by written notice delivered to the Company prior to your death or, failing such written notice, to your estate.

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11.      Amendment; Waiver

This Agreement may be amended only by an instrument in writing signed by the parties hereto, and any provision hereof may be waived only by an instrument in writing signed by the party or parties against whom or which enforcement of such waiver is sought.  The failure of either party hereto at any time to require the performance by the other party hereto of any provision hereof shall in no way affect the full right to require such performance at any time thereafter, nor shall the waiver by either party hereto of a breach of any provision hereof be taken or held to be a waiver of any succeeding breach of such provision or a waiver of the provision itself or a waiver of any other provision of this Agreement.

12.      Notices

All notices and other communications hereunder shall be in writing and shall be given by hand delivery to the other party or by registered or certified mail, return receipt requested, postage prepaid, addressed as follows:

If to you:

Mr. Richard R. Grigg

4140 Far-O-Way Lane

Richfield, OH44286

If to the Company:

Secretary

FirstEnergy

76 South Main Street

Akron, Ohio44308

or to such other address as either party shall have furnished to the other in writing in accordance herewith.  Notice and communications shall be effective when actually received by the addressee.

13.      Validity

The invalidity or unenforceability of any provision or provisions of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect, nor shall the invalidity or unenforceability of a portion of any provision of this Agreement affect the validity or enforceability of the balance of such provision.  If any provision of this Agreement, or portion thereof is so broad, in scope or duration, as to be unenforceable, such provision or portion thereof shall be interpreted to be only so broad as is enforceable.

14.      Withholding

The Company may withhold from any amounts payable under this Agreement such Federal, state or local taxes as shall be required to be withheld pursuant to any applicable law or regulation.

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15.      Section 409A

(a)       If you are a “specified employee,” as determined under the Company’s policy for determining specified employees on the date of your Termination of Employment, all payments, benefits, or reimbursements provided under this Agreement that would otherwise be paid or provided during the first six (6) months following such Termination of Employment (other than payments, benefits, or reimbursements that are treated as separation pay under Section 1.409A-1(b)(9)(v) of the Treasury Regulations or short-term deferrals) shall be accumulated through and paid or provided (together with interest at the applicable federal rate under Section 7872(f)(2)(A) of the Internal Revenue Code of 1986, as amended, in effect on the date of the Termination of Employment) on the first business day following the six (6) month anniversary of such Termination of Employment. Notwithstanding the foregoing, payments delayed pursuant to this Section 14(a) shall commence on your death prior to the end of the six (6) month period.

(b)       Any reimbursement of expenses or in-kind benefits provided under this Agreement (other than reimbursements or in-kind benefits that are treated as separation pay under Section 1.409A-1(b)(9)(v) of the Treasury Regulations), shall be subject to the following additional rules: (i) any reimbursement of eligible expenses shall be paid as they are incurred (but not prior to the end of the six-month delay period set forth in Section 14(a)); provided that you first provide documentation thereof in reasonable detail not later than sixty (60) days following the end of the calendar year in which the eligible expenses were incurred: (ii) the amount of expenses eligible for reimbursement, or in-kind benefits provided, during any calendar year shall not affect the amount of expenses eligible for reimbursement, or in-kind benefits to be provided, during any other calendar year; and (iii) the right to reimbursement or in-kind benefits shall not be subject to liquidation or exchange for another benefit.

(c)       It is intended that the payments and benefits provided under this Agreement shall either be exempt from application of, or comply with, the requirements of Section 409A of the Code.  This agreement shall be construed, administered, and governed in a manner that effects such intent, and the Company shall not take any action that would be inconsistent with such intent. Without limiting the foregoing, the payments and benefits provided under this Agreement may not be deferred, accelerated, extended, paid out, or modified in a manner that would result in the imposition of an additional tax under Section 409A of the Code upon you. Although the Company shall use its best efforts to avoid the imposition of taxation, interest and penalties under Section 409A of the Code, the tax treatment of the benefits provided under this Plan is not warranted or guaranteed. Neither the Company, its Affiliates nor their respective boards of directors shall be held liable for any taxes, interest, penalties, or other monetary amounts owed by you or other taxpayers as a result of the Agreement.

16.      Entire Agreement

This Agreement contains the entire understanding of the Company and you with respect to the subject matter hereof and, upon the date this Agreement becomes effective pursuant to Section 3, supercedes all other agreements of like or similar nature.

17.      Applicable Law

This Agreement shall be governed by and construed in accordance with the substantive internal law and not the conflict of law provisions of the State of Ohio.

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If the terms of the foregoing Agreement are acceptable to you, please sign and return to the Company the enclosed copy of this Agreement whereupon this Agreement shall become a valid and legally binding contract between you and the Company.

Very truly yours,

FIRSTENERGY CORP.

By:________________________________________

Anthony J. Alexander

President and Chief Executive Officer

Accepted and Agreed as of the date first above written

__________________________________________

                              Richard R. Grigg

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EX-10.2

EXECUTION VERSION

ASSET PURCHASE AGREEMENT

By and Between

CALPINE CORPORATION

AS SELLER

And

FIRSTENERGY GENERATION CORP.

AS BUYER

Dated as of January 28, 2008

TABLE OF CONTENTS

Page

  ARTICLE 1 PURCHASE AND SALE OF THE ACQUIRED ASSETS   5

1.1. Transfer of Acquired Assets    5

1.2. Excluded Assets    7

1.3. Assumption of Liabilities    9

1.4. Excluded Liabilities  10

1.5. Non-Assignment of Assigned Contracts.  10

  ARTICLE 2 CONSIDERATION 10

2.1. Consideration  10

2.2. Deposits  11

2.3. Guaranty  11

  ARTICLE 3 CLOSING AND DELIVERIES 11

3.1. Closing  11

3.2. Seller’s Deliveries  11

3.3. Buyer’s Deliveries  12

 ARTICLE 4 REPRESENTATIONS AND WARRANTIES OF SELLER 13

4.1. Corporate Organization  13

4.2. Authorization and Validity  13

4.3. No Conflict or Violation  13

4.4. Governmental Consents and Approvals  14

4.5. Compliance with Law  14

4.6. Litigation  14

4.7. Material Contracts  14

4.8. Permits  15

4.9. Environmental Matters  15

4.10. Owned Real Property  15

4.11. Employee Benefits  15

4.12. Insurance  16

4.13. Utilities.  16

  ARTICLE 5 REPRESENTATIONS AND WARRANTIES OF BUYER 16

5.1. Corporate Organization  16

5.2. Authorization and Validity  16

5.3. No Conflict or Violation  17

5.4. Consents, Approvals and Notifications  17

5.5. Availability of Funds  17

5.6. Adequate Assurances Regarding Assigned Contracts  17

5.7. Licenses, Permits, etc.  17

5.8. Investigation by Buyer  18

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 ARTICLE 6 COVENANTS OF SELLER 18

6.1. Actions Before Closing  18

6.2. Maintenance of Assets Before the Closing Date  19

6.3. Sale Order  19

6.4. Consents and Approvals  19

6.5. Access to Properties and Records; Confidentiality  20

6.6. Rejection of Assigned Contracts  20

6.7. Further Assurances  20

6.8. Notices  21

6.9. Casualty Loss  21

  ARTICLE 7 COVENANTS OF BUYER 21

7.1. Actions Before Closing Date  21

7.2. Consents, Approvals and Notifications  21

7.3. Adequate Assurances Regarding Assigned Contracts  21

7.4. Cure of Defaults  22

7.5. Availability of Business Records  22

7.6. Calpine Marks  22

7.7. Employee and Benefits Matters  23

7.8. Notices  23

  ARTICLE 8 BANKRUPTCY PROCEDURES 24

8.1. Bankruptcy Actions  24

8.2. Consultation with Buyer  24

  ARTICLE 9 REGULATORY MATTERS 24

9.1. Regulatory Filings  24

9.2. Cooperation; Confidentiality Agreement  24

9.3. Objections or Other Challenges  25

9.4. Permit Transfers  25

  ARTICLE 10 TAXES 26

10.1. Taxes Related to Purchase of Assets  26

10.2. Proration of Real and Personal Property Taxes  26

10.3. Cooperation on Tax Matters  26

10.4. Retention of Tax Records  27

10.5. Allocation of Purchase Price and Purchase Price Allocation Forms  27

10.6. Unbilled Transactional Taxes  27

  ARTICLE 11 CONDITIONS PRECEDENT TO PERFORMANCE BY PARTIES 28

11.1. Conditions Precedent to Performance by Seller and Buyer  28

11.2. Conditions Precedent to Performance by Seller  28

11.3. Conditions Precedent to the Performance by Buyer  29

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  ARTICLE 12 TERMINATION AND EFFECT OF TERMINATION 30

12.1. Right of Termination  30

12.2. Termination Without Default  30

12.3. Effect of Failure of Seller’s Conditions to Closing  31

12.4. Effect of Failure of Buyer’s Conditions to Closing  31

12.5. Damages  31

  ARTICLE 13 MISCELLANEOUS 32

13.1. Successors and Assigns  32

13.2. Governing Law; Jurisdiction  32

13.3. Disclosure Schedule Supplements  32

13.4. Warranties Exclusive  33

13.5. Survival of Representations and Warranties  33

13.6. No Recourse Against Third Parties  33

13.7. Mutual Drafting  34

13.8. Expenses  34

13.9. Broker’s and Finder’s Fees  34

13.10. Severability  34

13.11. Notices  34

13.12. Amendments; Waivers  36

13.13. Schedules  36

13.14. Public Announcements  36

13.15. Entire Agreement  36

13.16. Parties in Interest  37

13.17. Headings  37

13.18. Construction  37

13.19. Currency  37

13.20. Time of Essence  37

13.21. Counterparts  37

  ARTICLE 14 DEFINITIONS 38

14.1. Certain Terms Defined  38

14.2. All Terms Cross-Referenced  44

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EXHIBITS 

Exhibit A	Guaranty
Exhibit B-1	Form of Bill of Sale
Exhibit B-2	Form of Assignment and Assumption Agreement
Exhibit B-3	Form of Deed
Exhibit B-4	Form of Non-Fee Property Assignment and Conveyance Agreement
Exhibit B-5	Form of Seller’s Officer’s Certificate
Exhibit B-6	Form of Non-Foreign Status Certificate
Exhibit C	Reserved
Exhibit D	Form of Sale Order
Exhibit E	Bidding Procedures Order

DISCLOSURE SCHEDULES

Schedule 1.1(a)	Owned Real Property
Schedule 1.1(b)	Real Estate Leases
Schedule 1.1(d)	Entitled Real Property
Schedule 1.1(d)	Equipment
Schedule 1.1(e)	Supplier Contracts
Schedule 1.1 (f)	Other Contracts
Schedule 1.1(g)	Inventory
Schedule 1.1(i)	Permits
Schedule 1.2(l)	Calpine Marks
Schedule 1.2(r)	Excluded Assets
Schedule 1.4	Excluded Liabilities
Schedule 4.4	Governmental Consents and Approvals
Schedule 4.5	Compliance with Law
Schedule 4.6	Litigation
Schedule 4.7	Material Contracts
Schedule 4.8	License and Permit Exceptions
Schedule 4.9	Environmental Matters
Schedule 4.11	Employee Benefits Plans
Schedule 4.13	Utilities
Schedule 7.4	Cure Amounts
Schedule 11.1(b)	Regulatory Approvals
Schedule 14.1	Permitted Liens

  iv

ASSET PURCHASE AGREEMENT

THIS ASSET PURCHASE AGREEMENT (this “Agreement”), dated as of January 28, 2008, is made by and between Calpine Corporation, a Delaware corporation (the “Seller”), and FirstEnergy Generation Corp., an Ohio corporation (the “Buyer”).  Capitalized terms used in this Agreement are defined or cross-referenced in Article 14.

BACKGROUND INFORMATION

WHEREAS, on December 20, 2005 Seller and its debtor Affiliates, filed voluntary petitions for relief under the Bankruptcy Code in the Bankruptcy Court;

WHEREAS, Seller has determined it is in its best interest to sell the partially completed power plant located in Fremont, Ohio, which previously did business as Fremont Energy Center LLC;

WHEREAS, on the terms and subject to the conditions set forth in this Agreement, Buyer desires to purchase from Seller, and Seller desires to sell to Buyer, the Acquired Assets, in a sale authorized by the Bankruptcy Court pursuant to, inter alia, sections 105, 363, and 365 of the Bankruptcy Code;

WHEREAS, it is intended that the acquisition of the Acquired Assets would be accomplished through the sale, transfer and assignment of the Acquired Assets by Seller to Buyer;

WHEREAS, Buyer also desires to assume, and Seller desires to assign and transfer to Buyer, the Assumed Liabilities;

NOW, THEREFORE, in consideration of the foregoing and their respective representations, warranties, covenants and undertakings herein contained, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Seller and Buyer hereby agree as follows:

ARTICLE 1 

PURCHASE AND SALE OF THE ACQUIRED ASSETS

1.1.Transfer of Acquired Assets.  At the Closing, and upon the terms and conditions herein set forth, Seller shall sell to Buyer, and Buyer shall acquire from Seller, all of Seller’s right, title and interest in, to and under the Acquired Assets free and clear of all Liens, claims and other interests (except for Permitted Liens and Assumed Liabilities) pursuant to sections 105, 363 and 365 of the Bankruptcy Code. “Acquired Assets” shall mean solely the following property, but shall exclude the Excluded Assets:

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(a)the real property owned by Seller and listed on Schedule1.1(a)of the disclosure schedules accompanying this Agreement (the “Disclosure Schedules”), together with any Improvements owned by Seller erected thereon (the “Owned Real Property”);

(b)all of Seller’s rights under the leases of real property (the “Real Estate Leases”) listed on Schedule1.1(b)of the Disclosure Schedules (the real property leased by Seller pursuant to the Real Estate Leases, the “Leased Real Property”);

(c)all of Seller’s rights under the easements, rights of way, real property licenses, and other real property entitlements listed on Schedule1.1(c) of the Disclosure Schedules (the “Entitled Real Property” and, together with the Owned Real Property and the Leased Real Property, the “Real Property”);

(d)all of (i) Seller’s owned equipment, spare parts, machinery, furniture, fixtures, and other personal property used exclusively in the Power Plant, located on the Real Property or listed on Schedule 1.1(d) (the “Equipment”); and (ii) any rights of Seller, to the extent transferable, to the warranties and licenses received from manufacturers and sellers of the Equipment (if any);

(e)all of Seller’s rights under outstanding purchase orders or other similar Contracts used exclusively in connection with the Power Plant entered into by Seller with any supplier that are listed on Schedule 1.1(e) of the Disclosure Schedules (“Supplier Contracts”);

(f)all of Seller’s rights under the Contracts (including rights to transmission credits, if any), and Contracts with respect to the development of the Power Plant that are listed on Schedule1.1(f) of the Disclosure Schedules (the “Other Contracts” and, together with the Real Estate Leases, and the Supplier Contracts, the “Assigned Contracts”);

(g)all (i) inventories of chemicals and gases, supplies, materials and spares located at or in transit to the Real Property and owned by Seller on the Closing Date that are used exclusively for the Power Plant or as listed on Schedule1.1(g)(the “Inventory”) and (ii) any rights of Seller, to the extent transferable, to the warranties received from suppliers with respect to such Inventory;

(h)any computer software or systems located at the Owned Real Property and owned exclusively by Seller and licenses held exclusively by Seller including, but not limited to, Seller’s Target Solutions inventory control software, solely to the extent transferable, in each case that pertain solely to the Power Plant;

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(i)to the extent transferable under applicable Law, all rights of Seller under the permits, authorizations, approvals, registrations, and licenses relating exclusively to the Power Plant issued by any Government (and pending applications for the foregoing) listed on Schedule 1.1(i) of the Disclosure Schedules (“Permits”);

(j)copies, including copies in electronic form, of all Business Records, including engineering plans and contracts for the development of the Power Plant;  documents, blueprints, as built plans, specifications, quality assurance records, inventory records, purchasing reports, and equipment repair, maintenance and service records of Seller relating to the design, construction, licensing or operation of the Power Plant, operating safety and maintenance manuals, inspection reports and environmental assessments.

(k)rights to and goodwill represented by the name Fremont Energy Center; provided, that nothing in this Section 1.1(k) will give Buyer any rights to any name that includes a Calpine Mark;

(l)all assets to be acquired by Buyer pursuant to this Agreement.

(m) the Power Plant, and

(n) if any, Seller’s rights to any Emissions Allowances relating to the Power Plant.

1.2.           Excluded Assets.  Notwithstanding anything to the contrary in this Agreement, the Acquired Assets are the only properties and assets transferred to Buyer under this Agreement.  Without limiting the generality of the foregoing, the Acquired Assets do not include (i) any right, title or interest of any Person other than Seller in any property or asset, and (ii) the properties and assets of Seller listed or described in this Section 1.2 (all properties and assets not being acquired by Buyer are herein referred to as the “Excluded Assets”):

(a)all of Seller’s cash and cash equivalents, marketable securities, prepaid expenses, advance payments, surety accounts, deposits and other similar prepaid items (including for the purchase of natural gas);

(b)all of Seller’s accounts and notes receivable as of 11:59 p.m. (local time) on the Closing Date, if any (the “Accounts Receivable“);

(c)assets, property and other rights held or owned by Calpine and its Affiliates that is (i) not located on the Real Property and (ii) is not used exclusively by Seller in the development oroperation of the Power Plant;

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(d)forecasts, financial information or financial statements and proprietary manuals (except rights to use manuals specific to and necessary for the operation of the Power Plant) prepared by or used by Seller or its Affiliates to the extent not relating exclusively to the Power Plant;

(e)all of Seller’s rights under Contracts that are not Assigned Contracts;

(f)all rights to Claims, refunds or adjustments, and all other refunds or adjustments with respect to Excluded Assets relating to any proceeding before any Government relating to the period prior to the Closing and all rights to insurance proceeds or other insurance recoveries (i) that relate to, or are reimbursement for, Seller’s or Seller’s Affiliate’s expenditures made prior to the Closing Date or (ii) to the extent relating to Excluded Assets or Excluded Liabilities;

(g)any asset of Seller that would constitute an Acquired Asset (if owned by Seller on the Closing Date) that is conveyed or otherwise disposed of during the period from the date hereof until the Closing Date either (i) at the direction of the Bankruptcy Court or (ii) as otherwise permitted by the terms of this Agreement;

(h)all losses, loss carry forwards and rights to receive refunds, credits and loss carry forwards with respect to any and all Taxes of Seller incurred or accrued on or prior to the Closing Date, including interest receivable with respect thereto;

(i)any and all rights, demands, claims, credits, allowances, rebates, causes of action, known or unknown, pending or threatened (including all causes of action arising under sections 510, 544 through 551 and 553 of the Bankruptcy Code or under similar state Laws including fraudulent conveyance claims, and all other causes of action of a trustee and debtor-in-possession under the Bankruptcy Code) or rights of set-off (collectively, “Claims”), of Seller or any Affiliate of Seller arising out of or relating to events prior to the Closing Date (except to the extent relating to the Assumed Liabilities), including but not limited to Claims arising out of or relating in any way to the Chapter 11 Case or any of the transactions contemplated thereby or entered into as a consequence thereof, including any claims (as defined in section 101(5) of the Bankruptcy Code) filed, scheduled or otherwise arising in the Chapter 11 Case;

(j)all shares of capital stock or other equity interests of Seller and all Affiliates of Seller;

(k)all rights of Seller arising under this Agreement and under any other agreement between Seller and Buyer entered into in connection with this Agreement;

(l)all rights to or goodwill represented by or pertaining to all names, marks, trade names, trademarks and service marks incorporating the name Calpine or any other name set forth on Schedule 1.2(l) (the “Calpine Marks”) and any brand names or derivatives thereof no matter how used, whether as a corporate name, domain name or otherwise and including the corporate design logo associated with any Calpine Mark or variant of any Calpine Mark other than Fremont Energy Center;

8

(m) all rights under any Contract, except an Assigned Contract, that has been guaranteed by Seller or an Affiliate of Seller or to which Seller is a party;

(n)all rights under any Contract, except an Assigned Contract, that is, at the time of Closing, secured by any collateral owned by Seller’s Affiliates, Excluded Assets, or letters of credit;

(o)all Retained Books and Records;

(p)all of Seller’s rights to recovery of collateral given to obtain letters of credit and rights to recover amounts drawn or paid on letters of credit;

(q)all amounts due to Seller from any Affiliate of Seller and all rights and Claims of Seller against any Affiliate of Seller; and

(r)any assets set forth on Schedule1.2(r)of the Disclosure Schedules.

1.3.     Assumption of Liabilities.  At the Closing, Buyer shall assume, and Buyer shall hereafter pay, perform and discharge when due, the liabilities and obligations of Seller related to the Power Plant as listed below (collectively, the “Assumed Liabilities”):

(a)all liabilities and obligations of Seller under the Assigned Contracts arising after the Closing Date and the cure costs for such Assigned Contracts as set forth on Schedule 7.4;

(b)all liabilities and obligations of Seller under the Permits arising after the Closing Date;

(c)to the extent provided in Article 10, all liabilities and obligations of Seller for Transaction Taxes payable in connection with the transactions contemplated by this Agreement;

(d)to the extent provided in Article 10, all liabilities and obligations for real estate Taxes and assessments with respect to the Acquired Assets that are not yet due and payable and all liabilities and obligations for any Taxes relating to the Acquired Assets for periods after the Closing Date;

(e)all liabilities and obligations of Seller, any of its Affiliates or any of their respective Related Persons arising under or relating to any environmental, health or safety matter (including any liability or obligation arising under any Environmental Law) relating to the Power Plant and the Acquired Assets arising after the Closing Date; and

(f)all liabilities and obligations relating to or arising from the completion of construction or the ownership of the Power Plant and the Acquired Assets after the Closing Date.

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1.4.          Excluded Liabilities shall retain the following liabilities (the “Excluded Liabilities”) (i) all liabilities and obligations with respect to accounts payable (other than those under the Assigned Contracts) arising in connection with the Acquired Assets and in existence at 11:59 p.m. (local time) on the Closing Date (the “Accounts Payable”), (ii) liabilities directly and solely arising in connection with Excluded Assets, (iii) liabilities related to employees and former employees (except as provided in Section 7.7), (iv) liabilities which are not Assumed Liabilities, and (v) those listed on Schedule 1.4 of the Disclosure Schedules.

1.5.    Non-Assignment of Assigned Contracts.  Anything contained herein to the contrary notwithstanding, (i) this Agreement shall not constitute an agreement to assign any Assigned Contract if, after giving effect to the provisions of sections 363 and 365 of the Bankruptcy Code, an attempted assignment thereof, without obtaining a Consent, would constitute a breach thereof or in any way negatively affect the rights of Seller or Buyer, as the assignee of such Assigned Contract and (ii) no breach of this Agreement shall have occurred by virtue of such nonassignment.  If, after giving effect to the provisions of sections 363 and 365 of the Bankruptcy Code, such Consent is required but not obtained, Seller shall, at Buyer’s sole cost and expense, cooperate with Buyer in any reasonable arrangement, including Buyer’s provision of credit support, designed to provide for Buyer the benefits and obligations of or under any such Assigned Contract, including enforcement for the benefit of Buyer of any and all rights of Seller against a third party thereto arising out of the breach or cancellation thereof by such third party; provided, that nothing in this Section 1.5 shall (x) require Seller to make any significant expenditure or incur any significant obligation on its own or on Buyer’s behalf or (y) prohibit Seller from ceasing operations or winding up its affairs following the Closing.  Any assignment to Buyer of any Assigned Contract that shall, after giving effect to the provisions of sections 363 and 365 of the Bankruptcy Code, require the Consent of any third party for such assignment as aforesaid shall be made subject to such Consent being obtained.  Any contract that would be an Assigned Contract but is not assigned in accordance with the terms of this Section 1.5 shall not be considered an “Assigned Contract” for purposes hereof unless and until such contract is assigned to Buyer following the Closing Date upon receipt of the requisite consents to assignment and Bankruptcy Court approval.

ARTICLE 2 

CONSIDERATION

2.1.Consideration.  The aggregate consideration for the sale and transfer of the Acquired Assets shall be (a) $253,600,000 in cash (the “Purchase Price”), which price is payable and deliverable at the Closing in accordance with Section 3.3and (b) the assumption by Buyer of the Assumed Liabilities.

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2.2.Deposits.  Buyer and Seller have executed and delivered the Purchase Notice, and Buyer has deposited with the Escrow Agent $12,400,000 (the “Deposit”).  The Deposit shall be held and disbursed pursuant to the terms of the Master Escrow Agreement, the Purchase Notice, and this Agreement.

2.3.Guaranty.  On the date hereof, the Guarantor has executed and delivered to Seller the Guaranty substantially in the form of Exhibit A hereto.

ARTICLE 3

CLOSING AND DELIVERIES

3.1.Closing.  The consummation of the transactions contemplated hereby (the “Closing”) shall take place at the offices of Kirkland & Ellis LLP, 153 East 53rd Street, New York, New York at 10:00 a.m. EST on the third Business Day following the satisfaction or waiver by the appropriate party of all the conditions contained in Article 11 hereof, or on such other date or at such other place and time as may be agreed to by the parties hereto (the “Closing Date”).  The Closing will be deemed to be effective at 11:59 p.m. (local time) on the Closing Date.

3.2.Seller’s Deliveries

(a)The sale, transfer, assignment and delivery by Seller of the Acquired Assets to Buyer, as herein provided, shall be effected on the Closing Date.  At the Closing, Seller shall deliver to Buyer the following documents which shall be consistent with the terms of this Agreement:

(i)a bill of sale with respect to the Acquired Assets (other than the Assigned Contracts, Permits, Real Property and assets set forth in Sections 1.1(d)(ii) and 1.1(g)(ii)), duly executed by Seller and in the form of Exhibit B-1 hereto

(ii)an assignment and assumption agreement with respect to the Assigned Contracts and Assumed Liabilities, duly executed by Seller and in the form of Exhibit B-2 hereto;

(iii)the Business Records (it being understood that any Business Records located at the Power Plant need not be physically delivered, but shall be deemed delivered at the Closing), provided that, for any Business Records not located at the Power Plant, Seller shall be entitled to deliver such Business Records to Buyer promptly after the Closing Date;

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(iv)the deeds with respect to the Owned Real Property, duly executed by Seller and in the form of Exhibit B-3 hereto;

(v)an assignment and conveyance agreement with regard to the Real Estate Leases, duly executed by Seller and in the form of Exhibit B-4 hereto;

(vi)a secretary’s certificate certifying as to the resolutions of the board of directors of Seller approving and authorizing this Agreement and the transactions contemplated by this Agreement and in the form of Exhibit B-5 hereto;

(vii)an affidavit of non-foreign status that complies with section 1445 of the Code, duly executed by Seller and in the form of Exhibit B-6 hereto.  

(b)Notwithstanding anything in this Agreement or any Ancillary Agreement to the contrary, Seller’s obligation to convey to Buyer all rights of Seller under the Permits listed on Schedule 1.1(i) shall consist of providing: (i) if required by Law, notices of intent to transfer the Permit to Buyer in accordance with the Government regulations governing such Permit transfer, (ii) information as required by the Government regulations governing such Permit transfer and (iii) assistance to Buyer in obtaining the transfer of such Permits in accordance with Section 6.7.

3.3.Buyer’s Deliveries.  On the Closing Date, in payment for the Acquired Assets:

(a)the Escrow Agent shall pay to Seller the Deposit in accordance with the terms of the Master Escrow Agreement and the Purchase Notice, by wire transfer of immediately available funds to a bank account designated by Seller in writing to Buyer (the “Seller’s Account”);

(b)Buyer shall pay to Seller the Purchase Price, reduced by the amount of the Deposit paid pursuant to Section3.3(a), by wire transfer of immediately available funds to Seller’s Account;

(c)Buyer shall execute and deliver to Seller an instrument of assumption of liabilities with respect to the Assumed Liabilities substantially in the form of the Assumption Agreement attached as Exhibit B-2 hereto; and

(d)Buyer shall execute and deliver to Seller an assignment and conveyance agreement with regard to the Real Estate Leases, in the form of Exhibit B-4 hereto.

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ARTICLE 4

REPRESENTATIONS AND WARRANTIES OF SELLER

With respect to the Acquired Assets and the Power Plant, Seller hereby represents and warrants to Buyer as follows, except in all cases as disclosed in the Disclosure Schedules, as the same may be amended or modified in accordance with Section 13.3 hereof:

4.1.Corporate Organization.  Seller is duly organized and validly existing under the Laws of the jurisdiction of its organization.  Subject to any necessary authority from the Bankruptcy Court, Seller has all requisite power and authority to own its properties and assets and to conduct its business as now conducted and to perform all of its obligations under this Agreement.

4.2.Authorization and Validity.  Subject to the Bankruptcy Court’s entry of the Sale Order and the receipt of the Consents set forth on Schedule 4.4 of the Disclosure Schedules, Seller has all requisite power and authority to enter into this Agreement and the Purchase Notice to which it is or will be a party and, to carry out its obligations hereunder and thereunder.  Subject to the entry of the Sale Order, the execution and delivery of this Agreement and the Purchase Notice and the performance by Seller of its obligations hereunder and thereunder have been duly authorized by all necessary action by the board of directors of Seller, and no other proceedings on the part of Seller are necessary to authorize such execution, delivery and performance.  This Agreement and the Purchase Notice have been duly executed by Seller and, subject to the Bankruptcy Court’s entry of the Sale Order, constitutes its valid and binding obligation, enforceable against it in accordance with the terms herein and therein.

4.3.No Conflict or Violation.  Subject to (a) the receipt of all Consents set forth on Schedule 4.4 of the Disclosure Schedules and (b) the Bankruptcy Court’s entry of the Sale Order, the execution, delivery and performance by Seller of this Agreement do not and will not (i) violate or conflict with any provision of the bylaws or certificate of incorporation (or equivalent organizational documents) (collectively, the “Organizational Documents”) of Seller, (ii) violate any provision of law, regulation, rule or other legal requirement of any Government (“Law”) or any order, judgment or decree of any court or Government (“Order”) applicable to Seller, or (iii) violate or result in a breach of or constitute (with due notice or lapse of time or both) a default under any Assigned Contract, which violation, conflict, breach or default in any such case would reasonably be expected to have a Material Adverse Effect.  

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4.4.Governmental Consents and Approvals.  Schedule 4.4 of the Disclosure Schedules sets forth a true and complete list of each Consent and each declaration to or filing or registration with any Government that is required in connection with the execution and delivery of this Agreement and the Purchase Notice by Seller or the performance by Seller of its obligations hereunder or thereunder, the failure of which to obtain would reasonably be expected to have a Material Adverse Effect.

4.5.Compliance with Law.  Except as set forth on Schedule 4.5 of the Disclosure Schedules and as may result from the Chapter 11 Case, since December 31, 2002, Seller has not received written notice of any violation of any Law (other than with respect to Environmental Law, as to which the only representations and warranties made by Seller are those contained in Section 4.9) with respect to the Power Plant, nor is Seller in default with respect to any Order, applicable to any of the Acquired Assets, other than violations and defaults the consequences of which would not reasonably be expected to have a Material Adverse Effect.

4.6                                 Litigation.  As of the date of this Agreement and except as set forth on Schedules 4.6 or 4.9of the Disclosure Schedules, there are no Claims, suits or proceedings pending or, to the Knowledge of Seller, threatened in writing, before any Government brought by or against Seller that, if adversely determined, could reasonably be expected to have a Material Adverse Effect or materially impair the ability of Seller to consummate the transactions contemplated by this Agreement.

                 4.7.Material Contracts

(a)  Schedule 4.7 of the Disclosure Schedules sets forth a complete and correct list of each of the Assigned Contracts that:\

   (i)  creates a right to lease, use or occupy real estate that is material to the Power Plant or the Acquired Assets; or

  (ii)  the consequences of a default under or termination of such Assigned Contract would reasonably be expected to have a Material Adverse Effect (collectively, the “Material Contracts”).

                                                      (b)Other than as set forth on Schedule 4.7 of the Disclosure Schedules, neither Seller nor, to Seller’s Knowledge, any other party to any of the Material Contracts has commenced any action against any of the parties to such Material Contracts or given or received any written notice of any material default or violation under any Material Contract that was not withdrawn or dismissed, except only for those defaults that will be cured in accordance with the Sale Order (or that need not be cured under the Bankruptcy Code to permit the assumption and assignment of the Assigned Contracts).  To Seller’s Knowledge, each of the Material Contracts is, or will be at the Closing, valid, binding and in full force and effect against Seller, except as otherwise set forth on Schedule 4.7 of the Disclosure Schedules.

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4.8.Permits.  Schedule 4.8(a) of the Disclosure Schedules sets forth a complete and correct list of all material Permits and all pending applications therefor obtained by Seller in connection with the Power Plant or the Acquired Assets.  As of the date of this Agreement, except as set forth on Schedule 4.8(b) and as would not reasonably be expected to have a Material Adverse Effect, each such Permit is valid and in full force and effect, and is not subject to any pending or, to Seller’s Knowledge, threatened administrative or judicial proceeding to revoke, cancel, suspend or declare such Permit invalid in any respect.

4.9.Environmental Matters.  To Seller’s Knowledge, except as set forth on Schedule 4.9 of the Disclosure Schedules:

(a)Seller is in compliance with applicable Environmental Laws applicable to the Power Plant, except where such non-compliance would not reasonably be expected to have a Material Adverse Effect.

(b)Since December 31, 2002, Seller has not received a written complaint, Order, directive, Claim, request for information, citation or notice of violation from any Government or any other Person relating to any actual or alleged noncompliance with or liability under any Environmental Law with respect to any release, spill, leak, discharge or emission of any Hazardous Materials to the air, surface water, groundwater or soil of the Real Property, except where such matter would not reasonably be expected to have a Material Adverse Effect.

(c)The representations and warranties contained in this Section 4.9 are the only representations and warranties made by Seller with respect to matters arising under Environmental Laws or relating to Hazardous Materials.

4.10.                             Owned Real Property.  Schedule 1.1(a) of the Disclosure Schedules sets forth a complete and correct list of all material real property owned in whole or in part (and states the ownership percentage of all partially owned real property) by Seller and used in connection with the operation of the Power Plant.  Seller has made available to Buyer, to the extent within Seller’s possession or control, a copy of all certificates of occupancy for the Owned Real Property and a copy of any variance granted with respect to the Owned Real Property pursuant to applicable zoning laws or ordinances, all of which documents are true and complete copies thereof.  Seller has made available to Buyer all material existing surveys or topographical maps for the Owned Real Property, title policies, engineering reports and Environmental Reports in Seller’s possession or control.

4.11.                             Employee Benefits.  Set forth on Schedule 4.11 of the Disclosure Schedules is a list of all Employee Benefit Plans which Seller maintains or to which Seller contributes for the Employee.

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4.12.                  Insurance.  All material policies of property, damage, fire, liability, workers’ compensation and other forms of insurance owned or held by Seller and insuring the Acquired Assets are in full force and effect, all premiums with respect thereto covering the periods up to the date as of which this representation is being made have been paid, and no written notice of cancellation, non-renewal or termination has been received with respect to any such policy which has not replaced on substantially similar terms prior to the date of such cancellation.

4.13.                             Utilities.  Seller has no Knowledge of and has not received any notice of the curtailment of any utility service supplied to the Real Property.  Except as set forth on Schedule 4.13, to Seller’s Knowledge, all water and all electrical, telecommunication, sanitary and storm sewer and drainage lines, systems and hook ups located upon, under, at or adjacent to the Real Property necessary for the operation of the facilities as currently contemplated and for construction of the Power Plant are installed and connected under valid permits.

ARTICLE 5

REPRESENTATIONS AND WARRANTIES OF BUYER

Buyer hereby represents and warrants to Seller as follows, except in all cases as disclosed in the Disclosure Schedules.

5.1.Corporate Organization.  Buyer is an Ohio corporation, duly organized, validly existing and in good standing under the Laws of the jurisdiction of its incorporation, and has all requisite power and authority to own its properties and assets and to conduct its business as now conducted.

5.2.   Authorization and Validity.  Buyer has all requisite power and authority to enter into this Agreement and to execute and deliver the Purchase Notice and to carry out its obligations hereunder and thereunder.  The execution and delivery of this Agreement and the Purchase Notice and the performance of Buyer’s obligations hereunder and thereunder have been duly authorized by all necessary action by the board of directors of Buyer, and no other proceedings on the part of Buyer are necessary to authorize such execution, delivery and performance.  This Agreement and the Purchase Notice have been duly executed by Buyer and constitutes its valid and binding obligation, enforceable against it in accordance with the terms herein and therein, except as such enforceability may be limited by applicable bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium or other similar laws affecting or relating to the enforcement of creditors’ rights generally and subject, as to enforceability, to general principles of equity.

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5.3.No Conflict or Violation.  The execution, delivery and performance by Buyer of this Agreement and the execution and delivery of the Purchase Notice does not and will not violate or conflict with any provision of the Organizational Documents of Buyer and does not and will not violate any provision of Law, or any Order applicable to Buyer, nor will it result in a breach of or constitute (with due notice or lapse of time or both) a default under any Material Contract to which Buyer is a party or by which it is bound or to which any of its properties or assets is subject.

5.4.Consents, Approvals and Notifications.  The execution, delivery and performance of this Agreement and the Purchase Notice by Buyer does not require the Consent of, or filing with or notification of, any Government or any other Person except:  (a) for the Regulatory Approvals listed on Schedule 11.1(b) of the Disclosure Schedules; (b) for entry of the Sale Order by the Bankruptcy Court; or (c) for such Consents and filings, the failure to obtain or make would not reasonably be expected to have a material adverse effect on the ability of Buyer to consummate the transactions contemplated hereby.

5.5.Availability of Funds.  Buyer (a) has, and on the Closing Date will have, sufficient funds available to finance and consummate the transactions contemplated by this Agreement.

5.6.   Adequate Assurances Regarding Assigned Contracts.  Buyer is and will be capable of satisfying the conditions contained in sections 365(f)(2)(B) of the Bankruptcy Code with respect to the Assigned Contracts.

5.7.                                Licenses, Permits, etc.  Buyer has, or will have as of the Closing Date, all licenses, permits, franchises and authority, whether from a Government or otherwise, including Regulatory Approvals, and has provided any requisite notice to customers necessary to purchase the Acquired Assets and to assume the Assumed Liabilities.

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5.8.                                Investigation by Buyer.  Buyer has conducted its own independent review and analysis of (i) the Acquired Assets and the Power Plant (including the business, operations, technology, financial condition and prospects related to the operation of the Acquired Assets and the Power Plant), (ii) the Assumed Liabilities and (iii) the value of such Acquired Assets. Buyer acknowledges that Seller has provided Buyer with access to the personnel, properties, premises and records of the Acquired Assets for this purpose.  Buyer has conducted its own independent review of all Orders of, and all motions, pleadings, and other submissions to, the Bankruptcy Court in connection with the Chapter 11 Case.  Buyer acknowledges that the price being paid under this Agreement for the Acquired Assets is the fair value for acquiring the Acquired Assets under the circumstances and that such value, rather than replacement cost, is the appropriate measure of damages if and to the extent Buyer may have had any recourse for any failure to deliver the Acquired Assets in accordance with the terms of this Agreement.  In entering into this Agreement, Buyer has relied solely upon its own investigation and analysis, and Buyer acknowledges that (a) neither Seller nor any of its Related Persons or Affiliates makes or has made any representation or warranty, either express or implied, as to the accuracy or completeness of any of the information provided or made available to Buyer or any of its Related Persons or Affiliates, except as and only to the extent expressly set forth in Article 4 (which are subject to the limitations and restrictions contained in this Agreement), and (b) to the fullest extent permitted by Law, neither Seller nor any of its Related Persons or Affiliates shall have any liability or responsibility whatsoever to Buyer or its Related Persons or Affiliates on any basis (including in contract or tort, under securities Laws or otherwise) based upon any information provided or made available, or statements made, to Buyer or Related Persons or Affiliates (or any omissions therefrom), including in respect of the specific representations and warranties of Seller set forth in this Agreement, except, with regard to Seller, as and only to the extent expressly set forth in Article 4 (which are subject to the limitations and restrictions contained in this Agreement).  Buyer has no knowledge of any condition, event or circumstance that constitutes a breach of any representation, warranty or covenant of Seller in this Agreement.

ARTICLE 6  

COVENANTS OF SELLER

Seller hereby covenants to Buyer as follows:

6.1.Actions Before Closing.  Seller shall use commercially reasonable efforts to perform and satisfy all conditions to Buyer’s obligations to consummate the transactions contemplated by this Agreement that are to be performed or satisfied by Seller under this Agreement.

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6.2.Maintenance of Assets Before the Closing Date

                      (a)Without the prior written consent of Buyer or the authorization of the Bankruptcy Court, after notice and a hearing, between the date hereof and the Closing Date, Seller shall not, except as required or expressly permitted pursuant to the terms hereof or of any Ancillary Agreement, (i) make any material change in the Acquired Assets, taken as a whole, or (ii) enter into any material transaction other than in the Ordinary Course of Business consistent with past practices.  Without limitation of the foregoing, except as may be required by the Bankruptcy Court, from the date hereof until the Closing, Seller shall use commercially reasonable efforts to maintain the Acquired Assets in substantially the same manner as conducted by Seller in the Ordinary Course of Business, taking into account business exigencies arising as a result of Seller’s financial condition and status as a filer under Chapter 11 of the Bankruptcy Code.

                                      (b)Without limiting the generality of Section 6.2(a), prior to the Closing Seller shall not, and shall not permit its Affiliates to, without the prior written consent of Buyer: (i) sell, lease or transfer any of the Acquired Assets or parts thereof, (ii) amend, modify, terminate or change in any material respects any Assigned Contract, (iii) fail to maintain in full force and effect insurance policies covering the Acquired Assets, in form and amount consistent with past practice or (iv) grant a consensual Lien (other than a Permitted Lien) on the Acquired Assets.

                           (c)In the event Seller is directed by the Bankruptcy Court to convey or dispose of an asset that would be an Acquired Asset, Calpine shall either provide the proceeds of such asset conveyance to Buyer or reduce the Purchase Price by the fair market value of such asset.

6.3.Sale Order.  Seller shall use commercially reasonable efforts to obtain entry by the Bankruptcy Court of an Order in the form of Exhibit D hereto (the “Sale Order”).

6.4.Consents and Approvals.  Seller shall use commercially reasonable efforts to obtain all necessary material consents, waivers, authorizations and approvals of all Governments, and of all other Persons, required to be obtained by Seller in connection with the execution, delivery and performance by them of this Agreement.

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6.5.Access to Properties and Records; Confidentiality.  Seller shall afford to Buyer, and to the accountants, counsel and representatives of Buyer, reasonable access during normal business hours throughout the period prior to the Closing Date (or the earlier termination of this Agreement pursuant to Article 12) to all books and records of Seller relating to the Acquired Assets and the Power Plant if (w) permitted under Law (x) such books and records are not subject to confidentiality agreements, (y) disclosing such books and records would not adversely affect any attorney client, work product or similar privilege and (z) such books and records do not relate to any confidential proprietary models or other information of Seller or any of its Affiliates pertaining to energy project evaluation, energy or natural gas price curves or projections or other economic or other predictive models.  Upon reasonable prior notice, Seller shall also afford Buyer reasonable access, during normal business hours, to all Acquired Assets throughout the period prior to the Closing Date.  The rights of access contained in this Section 6.5 are granted subject to, and on, the following terms and conditions:  (A) any such investigation shall not include physical testing or samplings; (B) during the period from the date hereof to the Closing Date, all information provided to Buyer or its agents or representatives by or on behalf of Seller or their agents or representatives (whether pursuant to this Section 6.5 or otherwise) shall be governed by and subject to the Confidentiality Agreement, dated as of May 24, 2007, by and among Buyer and  Seller (the “Confidentiality Agreement”); (C) such rights of access shall not affect or modify the conditions set forth in Article 11 in any way; and (D) all such rights of access shall be at Buyer’s sole cost, expense and risk; and Buyer shall indemnify Seller for any damages, suits, claims, proceedings, fines, judgments, costs or expenses (including attorneys’ fees and incidental, consequential or punitive damages (collectively, “Losses”)) that Seller or any third party may suffer as a result of Buyer’s exercise of its rights under this Section 6.5; and (E) Buyer shall comply with and adhere to all of Seller’s safety policies and procedures.

6.6.                     Rejection of Assigned Contracts.  Seller shall not reject any Assigned Contracts pursuant to the Chapter 11 Case without the prior written consent of Buyer.

6.7.Further Assurances.  Upon the request and at the sole expense of Buyer at any time before or after the Closing Date, Seller shall execute and deliver such documents and take such actions as Buyer or its counsel may reasonably request to effectuate the purposes of this Agreement including, maintaining Permits.  Upon the request and at the sole expense of Buyer, Seller shall reasonably cooperate with Buyer’s attempt to obtain a bridge agreement that would enable Buyer to utilize software on any computers which make up part of the Acquired Assets, provided that, Seller shall have no obligation to (i) expend any funds or (ii) provide such software or an equivalent or replacement thereof should Buyer fail to obtain the rights to use any software.  Seller shall notify Buyer as to any software being removed from computers which make up part of the Acquired Assets, allow Buyer to have personnel present during such removal, and coordinate such removal with Buyer to ensure preservation of all data on any such computers.

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6.8.Notices.  Seller shall provide Buyer with prompt written notice of Seller’s Knowledge of (i) any breach of any representation or warranty by Buyer or (ii) any other material failure by Buyer to comply with the obligations of this Agreement.

6.9.Casualty Loss.  Notwithstanding any provision in this Agreement to the contrary, if, before the Closing, all or any portion of the Acquired Assets is (a) condemned or taken by eminent domain, or (b) a material portion is damaged or destroyed by fire or other casualty, Seller shall notify Buyer promptly in writing of such fact, and (i) in the case of condemnation or taking, Seller shall assign or pay, as the case may be, any proceeds thereof to Buyer at the Closing, and (ii) in the case of fire or other casualty, Seller shall either restore such damage or assign the insurance proceeds therefrom to Buyer at Closing.  If Seller chooses to assign the insurance proceeds to Buyer, Seller agrees that the Purchase Price shall be reduced by the amount of the deductible for the insurance policy paying proceeds to Seller for such loss.  Notwithstanding the foregoing, the provisions of this Section 6.9 shall not in any way modify Buyer’s other rights under this Agreement, including any applicable right to terminate the Agreement if any condemnation, taking, damage or other destruction resulted in a Material Adverse Effect.

ARTICLE 7  

COVENANTS OF BUYER

Buyer hereby covenants to Seller as follows:

7.1.Actions Before Closing Date.  Buyer shall use commercially reasonable efforts to perform and satisfy all conditions to Seller’s obligations to consummate the transactions contemplated by this Agreement that are to be performed or satisfied by Buyer under this Agreement.

7.2.Consents, Approvals and Notifications.  Buyer shall use commercially reasonable efforts to obtain all consents and approvals of all Governments, and all other Persons, required to be obtained by Buyer and provide notifications to all Persons required to be notified by Buyer to effect the transactions contemplated by this Agreement.  Buyer shall promptly take all actions as are reasonably requested by Seller to assist in obtaining the Bankruptcy Court’s entry of the Sale Order, including furnishing affidavits, financial information or other documents or information for filing with the Bankruptcy Court and making Buyer’s employees and representatives available to testify before the Bankruptcy Court.

7.3.Adequate Assurances Regarding Assigned Contracts.  With respect to each Assigned Contract, to the extent requested by the Bankruptcy Court, Seller or the counterparty to such Assigned Contract, Buyer shall provide the Bankruptcy Court, Seller or such counterparty, as the case may be, adequate assurance of the future performance of such Assigned Contract by Buyer.

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7.4.Cure of Defaults.  Buyer shall, on or prior to the Closing, cure any and all defaults under the Assigned Contracts that are required to be cured under the Bankruptcy Code and set forth on Schedule 7.4, so that such Assigned Contracts may be assumed by Seller and assigned to Buyer in accordance with the provisions of section 365 of the Bankruptcy Code.  To the extent the cure costs for the Assigned Contracts exceed the amounts set forth on Schedule 7.4 as of the date of this Agreement, the Seller will be solely responsible for the payment of such additional amounts.

7.5.Availability of Business Records.  After the Closing Date, Buyer shall provide to Seller and Related Persons (after reasonable notice and during normal business hours and without charge to Seller) access to all Business Records for periods prior to the Closing and shall preserve such Business Records until the later of (a) six (6) years after the Closing Date or (b) the required retention period for all government contact information, records or documents.  Such access shall include access to any information in electronic form to the extent reasonably available.  Buyer acknowledges that Seller has the right to retain originals or copies of Business Records for periods prior to the Closing.  Prior to destroying any Business Records for periods prior to the Closing, Buyer shall notify Seller thirty (30) days in advance of any such proposed destruction of its intent to destroy such Business Records, and Buyer will permit Seller to retain such Business Records.  With respect to any litigation and claims that are Excluded Liabilities, Buyer shall render all reasonable assistance that Seller may request in defending such litigation or claim and shall make available to Seller’s personnel most knowledgeable about the matter in question.  If after the Closing Buyer (or any Affiliate or creditor of Buyer) shall receive any payment or revenue that belongs to Seller pursuant to this Agreement, Buyer shall promptly remit or caused to be remitted the same to Seller, without set-off or deduction of any kind or nature.

7.6.Calpine Marks.  The Calpine Marks may appear on some of the Acquired Assets, including on signage.  Buyer acknowledges and agrees that it does not have and, upon consummation of the transactions contemplated by this Agreement, will not have, any right, title, interest, license or other right to use the Calpine Marks.  Buyer will promptly after the Closing Date use its commercially reasonable efforts to remove the Calpine Marks from, or cover or conceal the Calpine Marks on, the Acquired Assets other than Business Records, or otherwise refrain from the use and display of the Acquired Assets other than Business Records on which the Calpine Marks are affixed.  On or after the Closing, the Business Records shall not be held out as Business Records of Seller.

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7.7.                                Employee and Benefits Matters

(a)Intent to Employ.  Buyer shall have the right at least five (5) Business Days after the entry of the Sales Order on the Bankruptcy Court’s docket to interview the Employee, and shall then notify Seller at least thirty (30) days prior to the Closing Date (or such shorter period as available) whether Buyer intends to cause Employee to be employed by it or its Affiliate.  If Buyer elects to so employ Employee (hereinafter referred to as the “Accepting Employee“), such employment offer shall be at the same or substantially similar position.  The employment offer will be timed with the intention of making the Accepting Employee’s first day of employment effective as of the Closing Date.  However, employment will be contingent upon the Accepting Employee’s passing of a pre-employment physical, drug test, drivers license and background check and Employee’s executing of such agreements dealing with confidentiality, conflicts of interest and other matters as Buyer shall require.  Nothing herein shall prevent Seller or its Affiliates from offering employment to Employee if Buyer elects not to employ Employee pursuant to the foregoing.

(b)Employment Offer.  Such offer of employment shall be at the same base salary applicable to the Accepting Employee as of October 12, 2007 and Buyer shall not reduce such base salary during the 12-month period following the Closing so long as Employee is employed during such period.  Buyer also agrees, or shall cause its applicable Affiliate, to provide the Accepting Employee and his covered dependents with welfare and retirement benefits that are the same as those for the employees of Buyer or its Affiliate.  Accepting Employee’s employment with Buyer or its Affiliate, as the case may be, will be “at-will” and nothing contained in this Agreement or any other communication shall constitute a contract of employment and Employee shall not be a third party beneficiary of this Agreement.

(c)Benefit Plans.  Accepting Employee will be enrolled in Buyer’s, or its applicable Affiliate’s, benefit and retirement plan(s) on the first day of employment.  Benefits will be effective on the date specified in the official plan documents.  To the extent permitted under HIPAA law and Buyer’s, or its applicable Affiliate’s, welfare benefit plans, Buyer shall , or cause its Affiliate, to waive pre-existing condition requirements, evidence of insurability provisions, waiting period requirements or any similar provisions under any welfare benefit plans maintained for the Accepting Employee after the Closing Date.

(d)Welfare Benefit Claims.  Claims of the Accepting Employee and his eligible beneficiaries and dependents for medical, dental, prescription drug, life insurance, Worker’s Compensation, and/or other welfare benefits (“Welfare Benefits“) that are incurred before the Closing Date shall be the sole responsibility of Seller and Seller’s welfare benefit plans.  Seller shall provide any COBRA or other notices required under Seller’s welfare benefit and retirement plans.

7.8.Notices.  Buyer shall provide Seller with prompt written notice of Buyer’s knowledge of (i) any breach of any representation or warranty by Seller or (ii) any other material failure by Seller to comply with the obligations of this Agreement.

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ARTICLE 8

BANKRUPTCY PROCEDURES

8.1.Bankruptcy Actions.  Seller shall use its reasonable best efforts to obtain the entry of the Sale Order on the Bankruptcy Court’s docket.  Buyer covenants and agrees that it shall reasonably cooperate with Seller in connection with furnishing information or documents to Seller to satisfy the requirements of adequate assurance of future performance under section 365(f)(2)(B) of the Bankruptcy Code.

8.2.Consultation with Buyer.  To the extent practicable, Seller shall provide Buyer, at least three (3) days in advance of filing with the Bankruptcy Court, a draft of any motions, orders or other pleadings that Seller proposes to file with the Bankruptcy Court in connection with this Agreement.  To the extent practicable, Seller shall reasonably cooperate with Buyer, and consider in good faith the views of Buyer, with respect to all such filings.

ARTICLE 9

REGULATORY MATTERS

Buyer hereby covenants to Seller, and Seller hereby covenants to Buyer, as follows:

9.1.Regulatory Filings.  Subject to the terms and conditions of this Agreement, each party shall use its reasonable best efforts to take, or cause to be taken, all actions and to do, or cause to be done, all things necessary under applicable Laws to consummate the transactions contemplated by this Agreement.

9.2.          Cooperation; Confidentiality Agreement.  In connection with the efforts referenced in Section 9.1 to obtain all requisite approvals and authorizations for the transactions contemplated by this Agreement, any Antitrust Law, or any state law, each of the parties shall use reasonable best efforts to (a) cooperate with each other in connection with any filing or submission and in connection with any investigation or other inquiry, including any proceeding initiated by a private party; (b) keep the other parties informed in all material respects of any material communication received by such party from, or given by such party to, any Government and of any material communication received or given in connection with any proceeding by a private party, in each case regarding any of the transactions contemplated hereby and (c) permit the other party to review any material communication given to it by, and consult with each other in advance of any meeting or conference with any Government, including in connection with any proceeding by a private party.  The foregoing obligations in this Section 9.2 shall be subject to the Confidentiality Agreement and any attorney-client, work product or other privilege, and each of the parties hereto shall coordinate and cooperate fully with the other parties hereto in exchanging such information and providing such assistance as such other parties may reasonably request in connection with the foregoing.  The parties will not take any action that will have the effect of delaying, impairing or impeding the receipt of any required authorizations, consents, Orders or approvals.  “Antitrust Law” means the Sherman Act, as amended, the Clayton Act, as amended, the HSR Act, the Federal Trade Commission Act, as amended, and all other Laws and Orders that are designed or intended to prohibit, restrict or regulate actions having the purpose or effect of monopolization or restraint of trade or lessening of competition through merger or acquisition.  

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9.3.Objections or Other Challenges.  If any objections are asserted with respect to the transactions contemplated hereby under any Antitrust Law or if any suit is instituted by any Government or any private party challenging any of the transactions contemplated hereby as violative of any Antitrust Law or if the filing pursuant to Section 9.1 is reasonably likely to be rejected or conditioned by federal or a state Government, each of the parties shall use reasonable best efforts to resolve such objections or challenge as such Government or private party may have to such transactions, including to vacate, lift, reverse or overturn any Order, whether temporary, preliminary or permanent, so as to permit consummation of the transactions contemplated by this Agreement.  Without limiting the generality of the foregoing, Buyer shall promptly take and diligently pursue any or all of the following actions to the extent necessary to eliminate any concerns on the part of, or to satisfy any conditions imposed by, any Government with jurisdiction over the enforcement of any applicable Law, including any Antitrust Law and applicable state Law, regarding the legality of Buyer’s acquisition of the Acquired Assets or the Assumed Liabilities:  (a) entering into negotiations, providing information, making proposals, entering into and performing agreements or submitting to Orders, or, pursuant to any such agreement or Order or otherwise, selling or otherwise disposing of, or holding separate (through the establishment of a trust or otherwise), particular assets or categories of assets (including, after the Closing, any of the Acquired Assets), or operations (including, after the Closing, the Acquired Assets or any portion thereof), of Buyer or any of its Affiliates; (b) using its reasonable best efforts to prevent the entry in a judicial or administrative proceeding brought under any Law, including any Antitrust Law, applicable federal or state Law, by any Government or any other Person of any permanent, temporary or preliminary injunction or other Order that would make consummation of the acquisition of all or a portion of the Acquired Assets or the Assumed Liabilities in accordance with the terms of this Agreement unlawful or that would prevent or delay such consummation; (c) taking promptly and diligently pursuing, in the event that an injunction or Order has been issued as referred to in Section 9.3(b), any and all steps, including the appeal thereof, the posting of a bond and/or the steps contemplated by Section 9.3(b), necessary to vacate, modify or suspend such injunction or Order so as to permit such consummation as promptly as possible and (d) promptly take and diligently pursue all other actions and do all other things necessary and proper to avoid or eliminate each and every impediment under any Law, including any Antitrust Law, that may be asserted by any Government or any other Person to the consummation of the acquisition of the Acquired Assets or the Assumed Liabilities by Buyer in accordance with the terms of this Agreement.

9.4.Permit Transfers.  Prior to and following the Closing, Seller shall provide commercially reasonable assistance to Buyer to assist Buyer in (i) obtaining or (ii) the transfer of Permits from Seller to Buyer.  Any and all fees required by any Government or any Person to obtain or for the transfer of a Permit shall be the sole responsibility of Buyer.

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ARTICLE 10 

TAXES

10.1.                             Taxes Related to Purchase of Assets.  All state and local sales, use, gross-receipts, transfer, gains, excise, value-added or other similar Taxes in connection with the transfer of the Acquired Assets and the assumption of the Assumed Liabilities, and all recording and filing fees that may be imposed by reason of the sale, transfer, assignment and delivery of the Acquired Assets and are not exempt under section 1146(a) of the Bankruptcy code (collectively, “Transaction Taxes”), shall be paid by Buyer on or prior to their due date.

10.2.                             Proration of Real and Personal Property Taxes.  All real and personal property taxes and assessments on the Acquired Assets for any taxable period commencing prior to the day immediately preceding the Closing Date (the “Adjustment Date”) and ending after the Adjustment Date (a “Straddle Period”) shall be prorated between Buyer and Seller as of the close of business on the Adjustment Date based on the best information then available, with (a) Seller being liable for such Taxes attributable to any portion of a Straddle Period ending prior to the Adjustment Date and (b) Buyer being liable for such Taxes attributable to any portion of a Straddle Period beginning on or after the Adjustment Date.  Information available after the Adjustment Date that alters the amount of Taxes due with respect to the Straddle Period will be taken into account and any change in the amount of such Taxes shall be prorated between Buyer and Seller as set forth in the next sentence.  All such prorations shall be allocated so that items relating to the portion of a Straddle Period ending prior to the Adjustment Date shall be allocated to Seller based upon the number of days in the Straddle Period prior to the Adjustment Date and items related to the portion of a Straddle Period beginning on or after the Adjustment Date shall be allocated to Buyer based upon the number of days in the Straddle Period from and after the Adjustment Date; provided, however, that the parties shall allocate any real property Tax in accordance with Section 164(d) of the Code.  The amount of all such prorations that must be paid in order to convey the Acquired Assets to Buyer free and clear of all Liens other than Permitted Liens shall be calculated and paid on the Closing Date; all other prorations shall be calculated and paid as soon as practicable thereafter.

10.3.      Cooperation on Tax Matters.  Seller and Buyer shall (and shall cause their respective Affiliates to) cooperate fully with each other and make available or cause to be made available to each other for consultation, inspection and copying (at such other party’s expense) in a timely fashion such personnel, Tax data, relevant Tax Returns or portions thereof and filings, files, books, records, documents, financial, technical and operating data, computer records and other information as may be reasonably required (a) for the preparation by such other party of any Tax Returns or (b) in connection with any Tax audit or proceeding including one party (or an Affiliate thereof) to the extent such Tax audit or proceeding relates to or arises from the transactions contemplated by this Agreement.

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10.4.      Retention of Tax Records.  After the Closing Date and until the expiration of all statutes of limitation applicable to Seller’s liabilities for Taxes, Buyer shall retain possession of all accounting, business, financial and Tax records and information that (a) relate to the Acquired Assets and are in existence on the Closing Date and (b) come into existence after the Closing Date but relate to the Acquired Assets before the Closing Date, and Buyer shall give Seller notice and a reasonable opportunity to retain any such records in the event that Buyer determines to destroy or dispose of them during such period.  In addition, from and after the Closing Date, Buyer shall provide to Seller and their Related Persons (after reasonable notice and during normal business hours and without charge to Seller) access to the books, records, documents and other information relating to the Acquired Assets as Seller may reasonably deem necessary to (i) properly prepare for, file, prove, answer, prosecute and defend any Tax Return, claim, filing, tax audit, tax protest, suit, proceeding or answer or (ii) administer or complete any cases under chapter 11 of the Bankruptcy Code of or including Seller.  Such access shall include access to any computerized information systems that contain data regarding the Acquired Assets.

10.5.      Allocation of Purchase Price and Purchase Price Allocation Forms.  The Purchase Price, the Assumed Liabilities and other relevant items shall be allocated among the Acquired Assets and among Seller in accordance with Section 1060 of the Code.  Buyer shall prepare and deliver to Seller an allocation schedule setting forth Buyer’s determination of the allocation (the “Allocation Schedule”) within 60 days after the date hereof, which Allocation Schedule shall be subject to the reasonable approval of Seller.  The Allocation Schedule shall identify the transferor and transferee thereof, and shall be prepared in accordance with Treas. Reg. Section 1.1060-1 (or any comparable provision of state or local tax Law) or any successor provision.  The parties agree that they will report the federal, state, local and other Tax consequences of the purchase and sale hereunder (including in filings on IRS Form 8594) in a manner consistent with such allocation and that they will not take any position inconsistent therewith in connection with any Tax Return, refund claim, litigation or otherwise, unless and to the extent required to do so pursuant to applicable law.  Seller and Buyer shall cooperate in the filing of any forms (including Form 8594) with respect to such allocation.  Notwithstanding any other provision of this Agreement, this Section 10.5 shall survive any termination or expiration of this Agreement.

10.6.                             Unbilled Transactional Taxes.  If a Tax assessment is levied upon any party by an authorized tax jurisdiction for unbilled transactional Taxes that are the obligation of the other party under this Agreement, then the non-assessed party shall reimburse the assessed party for those taxes including any interest and penalty.

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ARTICLE 11

CONDITIONS PRECEDENT TO PERFORMANCE BY PARTIES

11.1.                             Conditions Precedent to Performance by Seller and Buyer.  The respective obligations of Seller and Buyer to consummate the transactions contemplated by this Agreement are subject to the satisfaction or waiver (other than the condition contained in Section 11.1(a), the satisfaction of which cannot be waived), on or prior to the Closing Date, of the following conditions:

(a)Sale Order.  The Bankruptcy Court shall have entered the Sale Order, and no Order staying, reversing, modifying or amending the Sale Order shall be in effect on the Closing Date.

(b)Regulatory Approvals.  The Regulatory Approvals on Schedule 11.1(b) of the Disclosure Schedules shall have been obtained and requisite notice has been provided by Buyer to relevant Government authorities.

(c)No Violation of Orders.  No preliminary or permanent injunction or other Order that declares this Agreement, the Master Escrow Agreement, or the Purchase Notice invalid or unenforceable in any respect or that prevents the consummation of the transactions contemplated hereby or thereby shall be in effect.

11.2.                             Conditions Precedent to Performance by Seller.  The obligations of Seller to consummate the transactions contemplated by this Agreement are subject to the satisfaction, on or before the Closing Date, of the following conditions, any one or more of which may be waived by Seller in its sole discretion:

(a)Representations and Warranties of Buyer.  All representations and warranties made by Buyer in this Agreement shall be true and correct in all material respects on and as of the Closing Date as if again made by Buyer on and as of such date (or, if made as of a specific date, at and as of such date), and Seller shall have received a certificate dated the Closing Date and signed by the President or a Vice President of Buyer to that effect.

(b)Performance of the Obligations of Buyer.  Buyer shall have performed in all material respects all obligations required under this Agreement to be performed by it on or before the Closing Date (except with respect to the obligation to pay the Purchase Price in accordance with the terms of this Agreement, which obligation shall be performed in all respects as required under this Agreement), and Seller shall have received a certificate dated the Closing Date and signed by the President or a Vice President of Buyer to that effect.

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(c)Cure of Defaults.  Buyer shall, on or prior to the Closing, have cured any and all defaults under the Assigned Contracts that are required to be cured under the Bankruptcy Code and have provided all assurances of future performance required to be provided by Buyer hereunder, so that the Assigned Contracts may be assumed by Seller and assigned to Buyer in accordance with the provisions of section 365 of the Bankruptcy Code.

(d)Buyer’s Deliveries.  Buyer shall have delivered, and Seller shall have received, all of the items set forth in Section 3.3 of this Agreement.

11.3.                             Conditions Precedent to the Performance by Buyer.  The obligations of Buyer to consummate the transactions contemplated by this Agreement are subject to the satisfaction, on or before the Closing Date, of the following conditions, any one or more of which may be waived by Buyer in its sole discretion:

(a)Representations and Warranties of Seller.  The representations and warranties made by Seller in Article 4 of this Agreement shall be true and correct as of the Closing, in each case as though made at and as of such time (or, if made as of a specific date, at and as of such date), except to the extent such failures to be true and correct do not constitute a Material Adverse Effect, and Buyer shall have received a certificate dated the Closing Date and signed by the President or a Vice President of Seller to that effect.

(b)Performance of the Obligations of Seller.  Seller shall have performed in all respects all obligations required under this Agreement to be performed by them on or before the Closing Date, except for such failures to perform that do not constitute a Material Adverse Effect, and Buyer shall have received a certificate dated the Closing Date and signed by the President or a Vice President of Seller to that effect.

(c)Material Adverse Effect.  No Material Adverse Effect shall have occurred and be continuing.

(d)Bankruptcy Matters.  The Sale Order shall have been entered by the Bankruptcy Court and such order shall have become a Final Order.

(e)Seller’s Deliveries.  Seller shall have delivered, and Buyer shall have received, all of the items set forth in Section 3.2 of this Agreement other than those Business Records to be delivered after the Closing.

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ARTICLE 12  

TERMINATION AND EFFECT OF TERMINATION

12.1.                             Right of Termination.  Notwithstanding anything to the contrary contained herein, this Agreement may be terminated only as provided in this Article 12.  In the case of any such termination, the terminating party shall give notice to the other party specifying the provision pursuant to which the Agreement is being terminated.

12.2.                             Termination Without Default

(a)This Agreement may be terminated at any time before Closing:

 (i)by mutual written consent of Seller and Buyer;

(ii)by Buyer, if a Sale Order has not been entered within 90 days after the entry of the Bidding Procedures Order;

(iii)by Buyer, on any date that is more than 365days after the date hereof (the “Termination Date”), if any condition contained in Section 11.1 has not been satisfied or waived as of such time; provided,however, that Buyer shall not have the right to terminate this Agreement under this Section 12.2(a)(iii) if Buyer’s failure to fulfill any of its obligations under this Agreement is the reason that the Closing has not occurred on or before said date;

                    (iv) by Seller, on any date that is after the Termination Date, if any condition contained in Section 11.1 has not been satisfied or waived as of such time; provided, however, that Seller shall not have the right to terminate this Agreement under this Section 12.2(a)(iv) if Seller’s failure to fulfill any of their obligations under this Agreement is the reason that the Closing has not occurred on or before said date; or

                    (v) by either Buyer or Seller, immediately upon an Order becoming final and non-appealable that declares this Agreement or the Purchase Notice invalid or unenforceable in any material respect or that prevents the consummation of the transactions contemplated hereby or thereby (a “Termination Order”); provided, however, that neither Seller nor Buyer shall have the right to terminate this Agreement pursuant to this Section12.2(a)(v) if such party or any of its Affiliates has sought entry of, or has failed to use all commercially reasonable efforts to oppose entry of, such Termination Order.

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(b)If this Agreement is terminated pursuant to Section 12.2(a), (i) the Deposit, together with any interest accrued thereon less fees and expenses of the Escrow Agent, shall be returned to Buyer, (ii) this Agreement shall become null and void and have no effect (other than this Article 12, Article 13 and Article 14, which shall survive termination) and (iii) none of Seller, Buyer or any of their respective Related Persons shall have any liability or obligation arising under or in connection with this Agreement.

12.3.Effect of Failure of Seller’s Conditions to Closing 

                         (a)Seller may terminate this Agreement at any time after the Termination Date and before Closing if any condition contained in Section 11.2(a), Section 11.2(b) or Section 11.2(c) has not been satisfied or waived by Seller as of such time; provided, however, that Seller shall not have the right to terminate this Agreement under this Section 12.3 if Seller’s failure to fulfill any of its obligations under this Agreement has been the reason that the Closing has not been consummated on or before such date.

(b)If this Agreement is terminated pursuant to this Section 12.3, Buyer acknowledges that a monetary remedy may be inadequate or impracticable and that Seller may have been caused irreparable harm and, if Seller so determines, Seller shall have the right, subject to the waiver by Seller or satisfaction of the conditions contained in Section 11.1, to obtain an Order requiring Buyer to specifically perform all of its obligations under this Agreement.

(c)If Seller determines that a monetary remedy is adequate and practicable, Seller may terminate this Agreement, retain the Deposit, together with any interest accrued thereon and pursue any other remedies available to Seller at Law.

12.4.Effect of Failure of Buyer’s Conditions to Closing.  Buyer may terminate this Agreement at any time after the Termination Date and before Closing if any condition contained in Section 11.3 has not been satisfied or waived as of such time; provided, however, that Buyer shall not have the right to terminate this Agreement under this Section 12.4 if Buyer’s failure to fulfill any of its obligations under this Agreement has been the reason that the Closing has not been consummated on or before said date.  If this Agreement is terminated pursuant to this Section 12.4: (i) the Deposit, together with any interest accrued thereon less any fees and expenses of the Escrow Agent, shall be returned to Buyer, (ii) this Agreement shall become null and void and have no effect (other than this Article 12, Article 13 and Article 14, which shall survive termination) and (iv) except as provided in this Section12.4, none of Seller, Buyer or any of their respective Related Persons shall have any liability or obligation arising under or in connection with this Agreement.

12.5.Damages.  In no event shall Seller or its Affiliates have any liability to Buyer or any other Person for any special, consequential or punitive damages, and any such claim, right or cause of action for any damages that are special, consequential or punitive or for specific performance of this Agreement is hereby fully waived, released and forever discharged.

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ARTICLE 13 

MISCELLANEOUS

13.1.  Successors and Assigns.  Except as otherwise provided in this Agreement, no party hereto shall assign this Agreement or any rights or obligations hereunder without the prior written consent of the other party hereto, and any such attempted assignment without such prior written consent shall be void and of no force and effect.  This Agreement shall inure to the benefit of and shall be binding upon the successors and permitted assigns of the parties hereto.

13.2.  Governing Law; Jurisdiction.  This Agreement shall be construed, performed and enforced in accordance with, and governed by, the Laws of the State of New York (without giving effect to the principles of conflicts of Laws thereof), except to the extent that the Laws of such State are superseded by the Bankruptcy Code; provided that, the validity and enforceability of all conveyance documents or instruments executed and delivered pursuant to this Agreement insofar as they affect title to real property shall be governed by and construed in accordance with the Laws of the jurisdiction in which such property is located.  For so long as Seller is subject to the jurisdiction of the Bankruptcy Court, the parties hereto irrevocably elect as the sole judicial forum for the adjudication of any matters arising under or in connection with the Agreement, and consent to the exclusive jurisdiction of, the Bankruptcy Court.  After Seller is no longer subject to the jurisdiction of the Bankruptcy Court, any legal action or proceeding with respect to this Agreement or the transactions contemplated hereby may be brought in the courts of the State of New York sitting in Manhattan or of the United States for the Southern District of New York, and by execution and delivery of this Agreement, each of the Parties consents to the non-exclusive jurisdiction of those courts.  Each of the Parties irrevocably waives any objection, including any objection to the laying of venue or based on the grounds of forum non conveniens, which it may now or hereafter have to the bringing of any action or proceeding in such jurisdiction in respect of this Agreement or the transactions contemplated hereby.

13.3.  Disclosure Schedule Supplements.  From time to time prior to the Closing, Seller shall supplement or amend the Disclosure Schedules to this Agreement with respect to any matter that, if existing, occurring or known at the date of this Agreement, would have been required to be set forth or described in the Disclosure Schedules.  The Disclosure Schedules shall be deemed amended by all such supplements and amendments for all purposes, unless within ten (10) days from the receipt of such supplement or amendment Buyer provides notice in good faith that the facts described in such supplement or amendment will have a Material Adverse Effect on the Acquired Assets.  If Buyer provides such notice, the Disclosure Schedules shall be deemed amended by all such supplements and amendments for all purposes, except for purposes of determining whether the conditions set forth in Section 11.3(a) of the Agreement have been satisfied.

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13.4.  Warranties Exclusive.  The representations and warranties contained herein are the only representations or warranties given by Seller and all other express or implied warranties are disclaimed.  Without limiting the foregoing, Buyer acknowledges that the Acquired Assets are conveyed “AS IS,’’ “WHERE IS” and “WITH ALL FAULTS” and that all warranties of merchantability, usage or suitability or fitness for a particular purpose are disclaimed.  Without limiting the foregoing, Buyer further acknowledges that no material or information provided by or communications made by Seller or its agents will create any representation or warranty of any kind, whether express or implied, with respect to the Acquired Assets and the title thereto, the operation of the Acquired Assets, or the prospects (financial and otherwise), risks and other incidents of the Power Plant, including without limitation the actual or rated generating capability of the Power Plant or the ability of Buyer to generate or sell electrical energy.

13.5.  Survival of Representations and Warranties

None of the representations or warranties of Seller set forth in this Agreement or in any certificate delivered pursuant to Section 11.3(a) or Section 11.3(b) shall survive the Closing.

13.6.  No Recourse Against Third Parties

Buyer agrees for itself and for all of its officers, directors,  shareholders, Affiliates, attorneys, agents and any other parties making any claim by, through or under the rights of such persons (collectively, the “Buyer Group”) that no member of Buyer Group shall have any rights against any officer, director, shareholder, Affiliate, attorney or agent of Seller (each, individually, a “Non-Recourse Person”) for any Losses that any member of Buyer Group may suffer in connection with this Agreement.  Buyer and all members of Buyer Group hereby waive any rights, recourse or remedy against Seller under any Environmental Laws, including any arising under the Comprehensive Environmental Response, Compensation and Liability Act, any analogous state law, or the common law, with respect to any environmental health or safety matter relating to the Acquired Assets in the Power Plant.  If any member of Buyer Group makes a claim against any person or entity that is not a Non-Recourse Person (a “Third Person”) that in any way gives rise to a claim by such Third Person against any Non-Recourse Person asserting that such Non-Recourse Person is or may be liable to such Third Person with respect to any Losses arising in connection with this Agreement (whether by way of indemnification, contribution, or otherwise on any theory whatever) (a “Claim Over”), such member of Buyer Group shall reduce or credit against any judgment or settlement such member of Buyer Group may obtain against such Third Person the full amount of any judgment or settlement such Third Person may obtain against the Non-Recourse Person on such Claim Over, and shall, as part of any settlement with such Third Person, obtain from such Third Person for the benefit of such Non-Recourse Person a satisfaction in full of such Third Person’s Claim Over against the Non-Recourse Person.

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13.7.  Mutual Drafting.  This Agreement is the result of the joint efforts of Buyer and Seller, and each provision hereof has been subject to the mutual consultation, negotiation and agreement of the parties and there is to be no construction against either party based on any presumption of that party’s involvement in the drafting thereof.

13.8.  Expenses.  Except as otherwise provided herein, each of the parties hereto shall pay its own expenses in connection with this Agreement and the transactions contemplated hereby, including any legal and accounting fees, whether or not the transactions contemplated hereby are consummated.  Buyer shall pay the cost of all Transaction Taxes payable upon or in connection with, and all surveys, title insurance policies and title reports obtained in connection with, this Agreement and the transactions contemplated thereby and all filing fees required to be paid in connection with any filings made or notices given pursuant to any Antitrust Law.

13.9.  Broker’s and Finder’s Fees.  Each of the parties represents and warrants that it has not dealt with any broker or finder in connection with any of the transactions contemplated by this Agreement in a manner so as to give rise to any claims against the other party for any brokerage commission, finder’s fees or other similar payout except that Seller has retained Miller Buckfire & Co., LLC and will pay Miller Buckfire & Co., LLC such fees as are approved by the Bankruptcy Court.

13.10.      Severability.  In the event that any part of this Agreement is declared by any court or other judicial or administrative body to be null, void or unenforceable, said provision shall survive to the extent it is not so declared, and all of the other provisions of this Agreement shall remain in full force and effect only if, after excluding the portion deemed to be unenforceable, the remaining terms shall provide for the consummation of the transactions contemplated hereby in substantially the same manner as originally set forth at the later of the date this Agreement was executed or last amended.

13.11.      Notices.  All notices, requests, demands and other communications under this Agreement shall be in writing and shall be deemed to have been duly given:  (a) on the date of service if served personally on the party to whom notice is to be given; (b) on the day of transmission if sent via facsimile transmission to the facsimile number given below, and telephonic confirmation of receipt is obtained promptly after completion of transmission; (c) on the day after delivery to Federal Express or similar overnight courier or the Express Mail service maintained by the United States Postal Service or (d) on the fifth day after mailing, if mailed to the party to whom notice is to be given, by first class mail, registered or certified, postage prepaid and properly addressed, to the party as follows:

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If to Seller:

Calpine Corporation

717 Texas Avenue, Suite 1000

Houston, Texas 77002

Attention:  General Counsel

Facsimile:  (713) 353-9131

Copy to:

Kirkland & Ellis LLP

655 Fifteenth Street, N.W.

Washington, D.C. 20005-5793

Attention:  Mitchell F. Hertz

Facsimile:  (202) 874-5200

and

Kirkland & Ellis LLP

777 South Figueroa Street

Los Angeles, California 90017-5800

Attention:  Bennett L. Spiegel

Facsimile:  (213) 680-8500

If to Buyer:

FirstEnergy Generation Corp.

76 South Main Street

Akron, Ohio  44308

Attention: President

Facsimile: (330) 384-3875

Copy to:

FirstEnergy Corp.

76 South Main Street, Ste 1500

Akron, OH 44308

Attention: Rick C. Giannantonio

Facsimile:  (330) 384-3875

And

Brouse McDowell

1001 Lakeside Avenue

Suite 1600

Cleveland, Ohio  44114

Attn:  Patricia A. Gajda and Marc B. Merklin

Facsímile:  (216) 830-6807

Any party may change its address for the purpose of this Section 13.11 by giving the other party written notice of its new address in the manner set forth above.

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13.12.      Amendments; Waivers.  This Agreement may be amended or modified, and any of the terms, covenants, representations, warranties or conditions hereof may be waived, only by a written instrument executed by the parties hereto, or in the case of a waiver, by the party waiving compliance.  Any waiver by any party of any condition, or of the breach of any provision, term, covenant, representation or warranty contained in this Agreement, in any one or more instances, shall not be deemed to be nor construed as a furthering or continuing waiver of any such condition, or of the breach of any other provision, term, covenant, representation or warranty of this Agreement.

13.13.                            Schedules.  Seller may, at its option, include in the Disclosure Schedules items that are not material, and any such inclusion, or any references to dollar amounts, shall not be deemed to be an acknowledgment or representation that such items are material or would cause a Material Adverse Effect, to establish any standard of materiality or to define further the meaning of such terms for purposes of this Agreement.  Information disclosed in the Disclosure Schedules shall constitute a disclosure for all purposes of the section for which such disclosure was made and each other section for which such disclosure is readily apparent.

13.140.                          Public Announcements.  No party shall make any press release or public announcement concerning the transactions contemplated by this Agreement without the prior written approval of the other parties, unless a press release or public announcement is required by Law or Order of the Bankruptcy Court.  If any such announcement or other disclosure is required by Law or Order of the Bankruptcy Court, the disclosing party shall give the nondisclosing party or parties prior notice of, and an opportunity to comment on, the proposed disclosure.  The parties acknowledge that Seller shall file this Agreement with the Bankruptcy Court in connection with obtaining the Sale Order.

13.15.                            Entire Agreement.  This Agreement, the Master Escrow Agreement, the Purchase Notice and the Confidentiality Agreement contain the entire understanding among the parties hereto with respect to the transactions contemplated hereby and supersede and replace all prior and contemporaneous agreements and understandings, oral or written, with regard to such transactions.  All Schedules hereto and any documents and instruments delivered pursuant to any provision hereof are expressly made a part of this Agreement as fully as though completely set forth herein.

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13.16.                            Parties in Interest.  Nothing in this Agreement is intended to confer any rights or remedies under or by reason of this Agreement on any Persons other than Seller and Buyer and their respective successors and permitted assigns.  Nothing in this Agreement is intended to relieve or discharge the obligations or liability of any third Persons to Seller or Buyer.  No provision of this Agreement shall give any third Persons any right of subrogation or action over or against Seller or Buyer.

13.17.                            Headings.  The article and section headings in this Agreement are for reference purposes only and shall not affect the meaning or interpretation of this Agreement.

13.18.                            Construction.  Unless the context of this Agreement otherwise requires, (i) words of any gender include the other gender, (ii) words using the singular or plural number also include the plural or singular number, respectively, (iii) the terms “hereof,” “herein,” “hereby,” and derivative or similar words refer to this entire Agreement as a whole and not to any other particular article, section or other subdivision, (iv) the words “include,” “includes” and “including” shall be deemed to be followed by the phrase “without limitation,” (v) “shall,” “will,” or “agrees” are mandatory, and “may” is permissive, and (vi) “or” is not exclusive.

13.19.                            Currency.  Except where otherwise expressly provided, all amounts in this Agreement are stated and shall be paid in United States currency.

13.20.                            Time of Essence.  Time is of the essence of this Agreement.

13.21.                            Counterparts.  This Agreement may be executed in counterparts, each of which shall be deemed an original, but all of which shall constitute the same agreement.  This Agreement and any signed agreement entered into in connection herewith or contemplated hereby, and any amendments hereto or thereto, to the extent signed and delivered by facsimile (or equivalent electronic transmission, including by email of a .pdf copy thereof), shall be treated in all manner and respects as an original contract and shall be considered to have the same binding legal effect as if it were the original signed version thereof delivered in person.

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ARTICLE 14 

DEFINITIONS

14.1.                              Certain Terms Defined.  As used in this Agreement, the following terms shall have the following meanings:

“Affiliate” means, with respect to any Person, any other Person directly or indirectly controlling, controlled by or under direct or indirect common control with such first Person where “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management policies of a Person, through the ownership of voting securities, by contract, as trustee, executor or otherwise.

“Assumption Agreement” means the agreement substantially in the form of Exhibit B hereto.

“Bankruptcy Code” means Title 11 of the United States Code.

“Bankruptcy Court” means the United States Bankruptcy Court for the Southern District of New York or such other court having jurisdiction over the Chapter 11 Case originally administered in the United States Bankruptcy Court of the Southern District of New York.

“Bidding Procedures Order” means the order of the Bankruptcy Court entered on December 19, 2007 at Docket No. 7254 and attached as Exhibit E hereto.

“Business Day” means any day other than Saturday, Sunday and any day that is a legal holiday or a day on which banking institutions in New York, New York are authorized by Law or other Governmental action to close.

“Business Records” means all books, files and records to the extent they apply exclusively to the Acquired Assets and the Power Plant, including customer lists, historical customer files, reports, plans, data, accounting and tax records, test results, product specifications, drawings, diagrams, training manuals, engineering data, safety and environmental reports and documents, maintenance schedules, operating and production records, inventory records, business plans, and marketing and all other studies, documents and records but excluding any Retained Books and Records.

“Chapter 11 Case” means, collectively, the cases commenced and to be commenced by Seller under chapter 11 of the Bankruptcy Code in the Bankruptcy Court.

“Clayton Act” means Title 15 of the United States Code §§ 12-27 and Title 29 of the United States Code §§ 52-53, as amended.

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“Code” means the Internal Revenue Code of 1986, as amended.

“Consent” means any consent, approval, authorization, qualification, waiver or notification of a Government.

“Contract” means any written or oral contract, agreement, license, sublicense, lease, sublease, mortgage, instruments, guaranties, commitment, undertaking or other similar arrangement, whether express or implied.

“Emission Allowances“ means all authorizations to emit specified units of pollutants or Hazardous Material from the Power Plant, which units are established by any Government authority with jurisdiction over the Power Plant under (a) an air pollutant control and emission reduction program designed to mitigate global warming or interstate or intrastate transport of or the emission of air pollutants, (b) a program designed to mitigate the impairment of surface waters, watersheds or groundwater or (c) any pollution reduction program with a similar purpose, in each case regardless of whether the Government authority establishing such authorizations designates such authorizations by a name other than “Allowance.”

“Employee” means Kevin Florence, the current manager of the Power Plant.

“Employee Benefit Plan” means any “employee benefit plan” (as such term is defined in ERISA § 3(3)) and any other material employee benefit plan, program or arrangement of any kind maintained, sponsored or contributed to by Seller.

“Environmental Laws”means all currently existing and future federal, state, provincial, municipal, local and foreign statutes, ordinances, rules, Orders, regulations, remediation standards, and other provisions having the force of law for protection of the environment, including the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, 42 U.S.C. Sec. 9601 et seq., as amended, the federal Resource Conservation and Recovery Act, 42 U.S.C. Sec. 6901 et seq., as amended, and related state statutes.

“Environmental Reports”means any environmental sampling or report performed specifically to test compliance with any Environmental Laws, and any and all Phase I or II environmental assessments, in each case which Seller has received from an un-Affiliated third party within the last three (3) years with respect to the Power Plant and the Owned Real Property; provided, Environmental Reports shall not include any safety, health and environmental audit reports, or internal investigation reports, prepared under the direction of Seller’s legal department and privileged under the attorney-client privilege, attorney work-product privilege, or state or federal environmental self-auditing privilege or policy.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

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“ERISA Affiliate” means any entity treated as a single employer with Seller pursuant to Section 414 of the Code.

“Escrow Agent” means Union Bank of California, N.A., the escrow agent under the Master Escrow Agreement.

“Existing Survey” means that certain plat of a survey provided by Seller to Buyer and  covering all or part of the Owned Real Property.

“Existing Title Policy” means that certain proforma title policy provided by Seller to Buyer and covering all or part of the Owned Real Property.

“Federal Trade Commission Act” means the Federal Trade Commission Act (15 U.S.C. § 41 et seq.), as amended, and the rules and regulations promulgated thereunder.

“Final Order” or “Final Orders” means any Order of a Government, the Bankruptcy Court or other court of competent jurisdiction after all opportunities for rehearing, reargument, petition for certiorari and appeal are exhausted or expired and any requests for rehearing have been denied, and that has not been revised, stayed, enjoined, set aside, annulled, reversed, remanded, modified or superseded, with respect to which any required waiting period has expired, and to which all conditions to effectiveness prescribed therein or otherwise by law or Order have been satisfied; provided, however, that no Order shall fail to be a Final Order solely because of the possibility that a motion pursuant to Rule 60 of the Federal Rules of Civil Procedure or Bankruptcy Rule 9024 may be filed with respect to such Order.  In the case of the Sale Order, a Final Order shall also consist of an Order as to which an appeal, notice of appeal or motion for rehearing or new trial has been filed but as to which Buyer, in its sole discretion, elects to proceed with Closing.

“Government” means any agency, division, subdivision, audit group, procuring office or governmental or regulatory authority in any event or any adjudicatory body thereof, of the United States, any state thereof or any foreign government.

“Guaranty” means the Guaranty of the Guarantor substantially in the form of Exhibit A hereto.

“Guarantor” means FirstEnergy Corp., an Ohio corporation.

“Hazardous Materials”means and includes any hazardous or toxic substance or waste or any contaminant or pollutant regulated under Environmental Laws, including, but not limited to, “hazardous substances” as currently defined by the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended, “hazardous wastes” as currently defined by the Resource Conservation and Recovery Act, as amended, natural gas petroleum products or byproducts and crude oil.

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“HIPAA” means the Health Insurance Portability and Accountability Act of 1996, as amended.

“HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (15 U.S.C. §§ 15c-15h, 18a), as amended.

“Improvements” means the buildings, improvements and structures now existing on the Real Property or demised under the Real Estate Leases, but only to the extent such buildings, improvements and structures constitute fixtures under applicable law.

“Knowledge of Seller”, “Seller’s Knowledge” or any other similar term or knowledge qualification means the present actual knowledge of Kevin Florence.

“Lien” means any mortgage, pledge, charge, security interest, encumbrance, lien (statutory or other) or conditional sale agreement.

“Master Escrow Agreement” means the escrow agreement by and among Seller, Buyer and Union Bank of California, N.A., relating to the Deposit.

“Material Adverse Effect” means a state of facts, event, change or effect on the physical condition of the Acquired Assets, or the enforceability of any Assigned Contract, that results in a material adverse effect on the combined operations and value of the Acquired Assets but excluding any state of facts, event, change or effect caused by events, changes or developments relating to: (i) changes of Laws, including those governing national, regional, state or local electric transmission or distribution systems, (ii) strikes, work stoppages or other labor disturbances, (iii) increases in costs of commodities or supplies, including fuel, (iv) effects of weather or meteorological events, (v) the transactions contemplated by this Agreement or the announcement thereof; (vi) changes in constructions costs; (vii) changes or conditions affecting the industries in which the Acquired Assets are a part generally (including any change or condition (x) generally affecting the international, national or regional or local electric generating, transmission or distribution industry (y) generally affecting the international, national, regional or local wholesale or retail markets for electric power or (z) resulting from changes in the international, national, regional or local fuel markets for the type of fuel used at the Power Plant); (viii) changes in economic, regulatory or political conditions generally; (ix) changes resulting from any motion, application, pleading or Order filed under or in connection with, the Chapter 11 Case or any motion, application, pleading or Order filed by any Government applicable to providers of generation, transmission or distribution of electricity generally; or (x) any act(s) of war or of terrorism other than such event or occurrences that cause material physical damage to the Power Plant or transmission services thereto.

“Ordinary Course of Business” means, with respect to the Power Plant, the maintenance thereof consistent with prior practices with respect to the future construction and operation thereof and prudent health, safety and environmental practices, and taking into account the status and quality of the Power Plant.

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“Permitted Liens” means:  (i) all Liens in existence on the date of this Agreement set forth on Schedule 14.1 of the Disclosure Schedules; (ii) Liens for Taxes, assessments and Government or other similar charges that are not yet due and payable or that, although due and payable, are being contested in good faith; (iii) Liens included in the Assumed Liabilities; (iv) Liens that will attach to the proceeds of this sale under this Agreement pursuant to section 363 of the Bankruptcy Code; (v) such covenants, conditions, restrictions, easements, encroachments or encumbrances, or any other state of facts, that do not materially interfere with the present occupancy of the Real Property or the use of such Real Property as it has been used by Seller prior to the Closing Date; (vi) zoning, building codes and other land use laws regulating the use of occupancy of Owned Real Property or the activities conducted thereon which are imposed by any governmental authority having jurisdiction over Owned Real Property; (vii) a lessor’s interest in, and any mortgage, pledge, security interest, encumbrance, lien (statutory or other) or conditional sale agreement on or affecting a lessor’s interest in, property underlying any of the Real Estate Leases; (viii) restrictions and regulations imposed by any Government authority or any local, state, regional, national or international reliability council, or any independent system operator or regional transmission organization with jurisdiction over Seller or the Power Plant; (ix) exceptions, restrictions, easements, charges, rights-of-way and monetary and non-monetary encumbrances which are set forth in any license; (x) exceptions and related matters set forth in the Existing Survey; and (xi) the matters set forth in [Schedule B, items 3,4,5,6 and 8] of the Existing Title Policy.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization or Government.

“Power Plant” means the approximately 70% complete, nominal 707 MW gas-fired combined cycle electric generating facility primarily located in Fremont, Ohioincluding all Owned Real Property, equipment, electrical transformers, pipeline and electrical interconnection facilities (including water discharge facilities and water injection facilities) related thereto.

“Purchase Notice” means Exhibit A of the Master Escrow Agreement, as executed and delivered by Buyer and Calpine.

“Regulatory Approvals” means state public utility commission and/or notifications of other related Government authorities with respect to the consummation of the transactions contemplated hereby.

“Related Person” means, with respect to any Person, all past, present and future directors, officers, members, managers, stockholders, employees, controlling persons, agents, professionals, attorneys, accountants, investment bankers, Affiliates or representatives of any such Person.

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“Retained Books and Records” means (i) all corporate seals, minute books, charter documents, corporate stock record books, original tax and financial records and such other files, books and records to the extent they  relate to any of the Excluded Assets or Excluded Liabilities or the organization, existence, capitalization or debt financing of Seller or of any Affiliate of Seller, (ii) all books, files and records that would otherwise constitute a Business Record but for the fact that disclosure of books, files or records could (w) violate any legal constraints or obligations regarding the confidentiality thereof, (x) waive any attorney client, work product  or like privilege, (y) disclose information about Seller or any of its Affiliates that is unrelated to the Power Plant or (z) disclose information about Seller or any of its Affiliates pertaining to energy or project evaluation, energy or natural gas price curves or projections or other economic predictive models, or (iii) all books and records prepared in connection with or relating in any way to the transactions contemplated by this Agreement, including bids received from other parties and analyses relating in any way to the Acquired Assets and the Assumed Liabilities.

“Rule” or “Rules” means the Federal Rules of Bankruptcy Procedure.

“Sherman Act” means title 15 of the United States Code §§ 1-7, as amended.

“Subsidiary” means, with respect to any Person, any corporation, partnership, limited liability company, association or other business entity of which (a) if a corporation, a majority of the total voting power of shares of stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person or a combination thereof, or (b) if a partnership, limited liability company, association or other business entity, a majority of the partnership or other similar ownership interest thereof is at the time owned or controlled, directly or indirectly, by any Person or one or more Subsidiaries of that Person or a combination thereof.  For purposes hereof, a Person or Persons shall be deemed to have a majority ownership interest in a partnership, limited liability company, association or other business entity if such Person or Persons shall be allocated a majority of partnership, limited liability company, association or other business entity gains or losses or shall be or control the managing director or general partner of such partnership, limited liability company, association or other business entity.

“Tax Return” means any report, return, information return, filing or other information, including any schedules, exhibits or attachments thereto, and any amendments to any of the foregoing required to be filed or maintained in connection with the calculation, determination, assessment or collection of any Taxes (including estimated Taxes).

“Taxes” means all taxes, however denominated, including any interest, penalties or additions to tax that may become payable in respect thereof, imposed by any Government, which taxes shall include all income taxes, Transaction Taxes, payroll and employee withholding, unemployment insurance, social security (or similar), sales and use, excise, franchise, gross receipts, occupation, real and personal property, stamp, transfer, workmen’s compensation, customs duties, registration, documentary, value added, alternative or add-on minimum, estimated, environmental (including taxes under section 59A of the Code) and other obligations of the same or a similar nature, whether arising before, on or after the Closing Date.

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14.2.All Terms Cross-Referenced.  Each of the following terms is defined in the section set forth opposite such term:

Term	Section
Accepting Employee	7.7(a)
Accounts Receivable	1.2(b)
Acquired Assets	1.1
Adjustment Date	10.2
Affiliate	14.1
Agreement	Preamble
Allocation Schedule	10.5
Antitrust Law	9.2
Assigned Contracts	1.1(f)
Assumed Liabilities	1.3
Assumption Agreement	14.1
Bankruptcy Code	14.1
Bankruptcy Court	14.1
Bidding Procedures Order	14.1
Business Day	14.1
Business Records	14.1
Buyer	Preamble
Buyer Group	13.6
Calpine Marks	1.2(l)
Chapter 11 Case	14.1
Claim Over	13.6
Claims	1.2(i)
Clayton Act	14.1
Closing	3.1
Closing Date	3.1
Code	14.1
Confidentiality Agreement	6.5
Consent	14.1
Contract	14.1
Deposit	2.2
Disclosure Schedules	1.1(a)
Emissions Allowances	14.1
Employee	14.1
Employee Benefit Plan	14.1
Entitled Real Property	1.1(c)
Environmental Laws	14.1
Environmental Reports	14.1
Equipment	1.1(d)
ERISA	14.1
ERISA Affiliate	14.1
Escrow Agent	14.1

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Excluded Assets	1.2
Excluded Liabilities	1.4
Existing Survey	14.1
Existing Title Policy	14.1
Federal Trade Commission Act	14.1
Final Order	14.1
Government	14.1
Hazardous Materials	14.1
HSR Act	14.1
Improvements	14.1
Inventory	1.1(g)
Knowledge of Seller	14.1
Law	4.3
Leased Real Property	1.1(a)(b)
Lien	14.1
Losses	6.5
Master Escrow Agreement	14.1
Material Adverse Effect	14.1
Material Contracts	4.7(a)(ii)
Non-Recourse Person	13.6
Order	4.3
Ordinary Course of Business	14.1
Organizational Documents	4.3
Other Contracts	1.1(f)
Owned Real Property	1.1(a)
Permits	1.1(i)
Permitted Liens	14.1
Person	14.1
Power Plant	14.1
Purchase Notice	14.1
Purchase Price	2.1
Real Estate Leases	1.1(a)(b)
Real Property	1.1(c)
Regulatory Approvals	14.1
Related Person	14.1
Retained Books and Records	14.1
Rule	14.1
Rules	14.1
Sale Order	6.3
Seller	Preamble
Seller’s Account	3.3
Seller’s Knowledge	14.1
Sherman Act	14.1
Straddle Period	10.2
Subsidiary	14.1
Supplier Contracts	1.1(e)

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Tax Return	14.1
Taxes	14.1
Termination Date	12.2(a)(iii)
Termination Order	12.2(a)(v)
Third Person	13.6
Transaction Taxes	10.1
Welfare Benefits	7.7(d)

(Signatures are on the following page.)

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized as of the date first above written.

FIRSTENERGY GENERATION CORP.

By:

Name: 

Title: 

CALPINE CORPORATION

By:

Name: 

Title: 

EX-10.3

EXECUTION COPY

CONSENT AND AMENDMENT

Dated as of November 2, 2007

To the Lenders party to the Credit Agreement

  and the Administrative Agent referred to below

Ladies and Gentlemen:

     Reference is made to the Credit Agreement, dated as of August 24, 2006 (as amended, modified or supplemented as of the date hereof, the “Credit Agreement”), among FirstEnergy Corp., an Ohio corporation, FirstEnergy Solutions Corp., an Ohio corporation, American Transmission Systems, Incorporated, an Ohio corporation, Ohio Edison Company, an Ohio corporation, Pennsylvania Power Company, a Pennsylvania corporation, The Cleveland Electric Illuminating Company, an Ohio corporation, The Toledo Edison Company, an Ohio corporation, Jersey Central Power & Light Company, a New Jersey corporation, Metropolitan Edison Company, a Pennsylvania corporation, and Pennsylvania Electric Company, a Pennsylvania corporation, the banks and other financial institutions parties thereto, Citibank, N.A., as administrative agent, the fronting banks party thereto and the swing line lenders party thereto. Capitalized terms used herein and not otherwise defined herein have the meanings given such terms in the Credit Agreement.

Section 1.  Termination Date Extension.

Pursuant to Section 2.19 of the Credit Agreement, the Borrowers hereby request that each Lender consent to a one-year extension of the Termination Date with respect to such Lender’s Commitment and its Outstanding Credits.  By signing in the appropriate space provided in the signature pages hereof, and subject to the satisfaction of the conditions precedent set forth in Section 2 below, each Lender hereby (i) consents to such extension with respect to its Commitment and its Outstanding Credits and (ii) waives those provisions of Section 2.19(b) of the Credit Agreement that specify that each Lender’s consent to the Borrowers’ foregoing extension request be delivered no earlier than 60 days and no later than 70 days following the Extension Notice Date and agrees instead that any Lender that has not executed and delivered this Consent and Amendment to the Administrative Agent within 18 days following the date hereof shall be deemed not to have consented to such extension request.

Section 2. Conditions Precedent to Termination Date Extension.

Section 1 of this Consent and Amendment shall become effective as of November 20, 2007 if on or prior to such date (i) Lenders holding Commitments aggregating more than 66-2/3% of the Commitments shall have executed and delivered this Consent and Amendment in accordance with Section 1 above, (ii) the following statements shall be true: (A) no event has occurred and is continuing, or would result from the extension of the Termination Date, that constitutes an Event of Default or would, with the giving of notice or the lapse of time, or both, constitute an Event of Default, and (B) the representations and warranties contained in Section 4.01 of the Credit Agreement are correct in all material respects on and as of the date of extension of the Termination Date, before and after giving effect to such extension, as though made on and as of such date (provided however that subsections (f) and (g) thereof shall be deemed to read as set forth in the proposed amendments set forth in Section 3(vii) of this Consent and Amendment), and (iii) the Administrative Agent shall have received the following, each dated such date and in form and substance satisfactory to the Administrative Agent: (x) a certificate of a duly authorized officer of each Borrower to the effect that as of the date of extension of the Termination Date the statements set forth in clauses (A) and (B) above are true, (y) certified copies of the resolutions of the Board of Directors of each Borrower authorizing such extension and the performance of the Credit Agreement on and after the date of extension of the Termination Date, and of all documents evidencing other necessary corporate action and Governmental Action with respect to the Credit Agreement and such extension of the Termination Date and (z) an opinion or opinions of counsel to the Borrowers, as to such matters related to the foregoing as the Administrative Agent or the Lenders through the Administrative Agent may reasonably request.

Section 3.  Credit Agreement Amendments.  The parties agree that, subject to the satisfaction of the conditions precedent set forth in Section 4 below:

(i) The term “Borrower Sublimit” set forth in Section 1.01 of the Credit Agreement is amended and restated in its entirety to read as follows:

                   ““Borrower Sublimit” means:  (i) with respect to FE, $2,750,000,000, (ii) with respect to FES, $1,000,000,000, (iii) with respect to ATSI, $0 (unless and until increased pursuant to Section 2.06(c)), (iv) with respect to OE, $500,000,000, (v) with respect to Penn, $50,000,000, (vi) with respect to CEI, $250,000,000 (unless and until increased pursuant to Section 2.06(c)), (vii) with respect to TE, $250,000,000 (unless and until increased pursuant to Section 2.06(c)), (viii) with respect to JCP&L, $425,000,000, (ix) with respect to Met-Ed, $250,000,000, and (x) with respect to Penelec, $250,000,000.”

(ii)  Section 1.01 of the Credit Agreement is amended by adding each of the following definitions in its proper alphabetical place:

““Additional Commitment Lender” has the meaning set forth in Section 2.19(d).”

““Anniversary Date” has the meaning set forth in Section 2.19(a).”

““Existing Termination Date” has the meaning set forth in Section 2.19(a).”

““Extension Notice Date” has the meaning set forth in Section 2.19(b).”

““Specified  Date” has the meaning set forth in Section 2.19(c).”

(iii) The first sentence of Section 2.06(c) of the Credit Agreement is amended by deleting the first sentence therein and substituting the following therefor:

“ATSI may increase its Borrower Sublimit up to $100,000,000 by delivering a notice to the Administrative Agent requesting such increase, subject to the condition that either (i) ATSI has Reference Ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FE unconditionally guarantees the amounts payable by ATSI hereunder by delivering to the Administrative Agent a duly completed Guaranty executed by FE.”

(iv) Section 2.12(b)(iv) of the Credit Agreement is amended and restated in its entirety to read as follows:

   “If at any time ATSI shall have Outstanding Credits and shall fail to have Reference Ratings of at least BBB- by S&P and Baa3 by Moody’s, and FE shall fail to deliver to the Administrative Agent a Guaranty executed by FE, ATSI agrees (A) to prepay to the Administrative Agent the principal amount of all Advances outstanding to ATSI and (B) to pay to the Administrative Agent an amount in immediately available funds (which funds shall be held as collateral pursuant to arrangements satisfactory to the Administrative Agent) equal to all of the amount available for drawing under the Letters of Credit outstanding to ATSI at such time.”

(v)  Section 2.19 of the Credit Agreement is amended and restated in its entirety to read as follows:

SECTION 2.19.  Extension of Termination Date.

                (a)  The Borrowers may, by notice to the Administrative Agent (which shall promptly notify the Lenders) not earlier than 45 days and not later than 35 days prior to any anniversary of the date of this Agreement (the “Anniversary Date”), request that each Lender extend such Lender’s Termination Date for an additional one year after the Termination Date then in effect for such Lender hereunder (the “Existing Termination Date”).

                (b)  Each Lender, acting in its sole and individual discretion, shall, by notice to the Administrative Agent given not earlier than 30 days prior to the applicable Anniversary Date and not later than the date (the “Extension Notice Date”) that is 20 days prior to the Applicable Anniversary Date, advise the Administrative Agent whether or not such Lender agrees to such extension (and each Lender that determines not to so extend its Existing Termination Date (a “Nonconsenting Lender”) shall notify the Administrative Agent of such fact promptly after such determination (but in any event no later than the Extension Notice Date), and any Lender that does not so advise the Administrative Agent on or before the Extension Notice Date shall be deemed to be a Nonconsenting Lender.  The election of any Lender to agree to such extension shall not obligate any other Lender to so agree.

 

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                (c)  The Administrative Agent shall notify the Borrowers of each Lender’s determination under this Section no later than the date 15 days following the Extension Notice Date, or, if such date is not a Business Day, on the next preceding Business Day (the “Specified Date”).

(d)  The Borrowers shall have the right on or before the Specified Date to replace each Nonconsenting Lender with, and add as “Lenders” under this Agreement in place thereof, one or more Eligible Assignees (each, an “Additional Commitment Lender”) with the approval of the Administrative Agent, the Swing Line Lenders and the Fronting Banks (which approvals shall not be unreasonably withheld), each of which Additional Commitment Lenders shall have entered into an agreement in form and substance satisfactory to the Borrowers and the Administrative Agent pursuant to which such Additional Commitment Lender shall, effective as of the Specified Date, undertake a Commitment (and, if any such Additional Commitment Lender is already a Lender, its Commitment shall be in addition to such Lender’s Commitment hereunder on such date).

(e)  If (and only if) the aggregate amount of the Commitments of the Lenders that have agreed so to extend their Existing Termination Dates plus the aggregate additional Commitments of the Additional Commitment Lenders shall be more than 66-2/3% of the aggregate amount of the Commitments in effect immediately prior to the Specified Date, then, effective as of the Specified Date, the Existing Termination Date of each Lender agreeing to an extension and of each Additional Commitment Lender shall be extended to the date that is one year after the Existing Termination Date, and each Additional Commitment Lender shall thereupon become a “Lender” for all purposes of this Agreement.

(f)  Notwithstanding the foregoing, the extension of a Lender’s Existing Termination Date pursuant to this Section shall be effective with respect to such Lender on the Specified Date but only if (i) the following statements shall be true: (A) no event has occurred and is continuing, or would result from the extension of the Existing Termination Date, that constitutes an Event of Default or an Unmatured Default and (B) the representations and warranties contained in Section 4.01 are correct in all material respects on and as of the Specified Date, before and after giving effect to such extension, as though made on and as of such date, and (ii) on or prior to the Specified Date the Administrative Agent shall have received the following, each dated the Specified Date and in form and substance satisfactory to the Administrative Agent: (x) a certificate of a duly authorized officer of each Borrower to the effect that as of the Specified Date the statements set forth in clauses (A) and (B) above are true, (y) certified copies of the resolutions of the Board of Directors of each Borrower authorizing such extension and the performance of this Agreement on and after the Specified Date, and of all documents evidencing other necessary corporate action and Governmental Action with respect to this Agreement and such extension of the Existing Termination Date and (z) an opinion of counsel to the Borrowers, as to such matters related to the foregoing as the Administrative Agent or the Lenders through the Administrative Agent may reasonably request.

(g)  Subject to subsection (d) above, the Commitment of any Nonconsenting Lender shall automatically terminate on its Existing Termination Date (without regard to any extension by any other Lender).”

(vi)  Section 3.02(ii) of the Credit Agreement is amended and restated in its entirety to read as follows:

“(ii)  In the case of an Extension of Credit with respect to ATSI without delivery of a Guaranty executed by FE, the financial statements described in Section 5.01(g)(ii) and (iii) shall be currently available for ATSI, and ATSI shall have delivered copies of such financial statements to the Administrative Agent; and”

(vii)  Subsections (f) and (g) of Section 4.01 of the Credit Agreement are amended and restated in their entirety to read as follows:

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“(f)           Litigation.  Except as disclosed in FE’s, with respect to FE, ATSI and FES, or such Borrower’s, with respect to any other Borrower, Annual Report on Form 10-K for the fiscal year ended December 31, 2006, its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2007, June 30, 2007 and September 30, 2007 and its Current Reports on Form 8-K filed in 2007 prior to November 2, 2007, or additionally with respect to FES in its Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 (copies of which have been furnished to each Lender), there is no pending or threatened action or proceeding (including, without limitation, any proceeding relating to or arising out of Environmental Laws) affecting it or any of its Subsidiaries before any court, governmental agency or arbitrator that has a reasonable possibility of having a material adverse effect on the business, condition (financial or otherwise), results of operations or prospects of it and its consolidated subsidiaries, taken as a whole, or on the ability of such Borrower to perform its obligations under this Agreement or any other Loan Document, and there has been no development in the matters disclosed in such filings that has had such a material adverse effect.

(g)           Financial Statements; Material Adverse Change.  The consolidated balance sheets of FE and its Subsidiaries, with respect to FE and ATSI, and such Borrower and its Subsidiaries, with respect to any other Borrower, as at December 31, 2006, and the related consolidated statements of income, retained earnings and cash flows of FE and its Subsidiaries, with respect to FE and ATSI, and such Borrower and its Subsidiaries, with respect to any other Borrower, for the fiscal year then ended, certified by PricewaterhouseCoopers LLP, independent public accountants, and the unaudited consolidated balance sheet of FE and its Subsidiaries, with respect to FE and ATSI, and such Borrower and its Subsidiaries, with respect to any other Borrower, as at September 30, 2007, and the related consolidated statements of income, retained earnings and cash flows of FE and its Subsidiaries, with respect to FE and ATSI, and such Borrower and its Subsidiaries, with respect to any other Borrower, for the nine months then ended, copies of each of which have been furnished to each Lender and each Fronting Bank, in all cases as amended and restated to the date hereof, present fairly the consolidated financial position of such Borrower and its Subsidiaries as at such dates and the consolidated results of the operations of such Borrower and its Subsidiaries for the periods ended on such dates, all in accordance with GAAP consistently applied. Except as disclosed in FE’s, with respect to FE, ATSI and FES, or such Borrower’s, with respect to any other Borrower, Annual Report on Form 10-K for the fiscal year ended December 31, 2006, its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2007, June 30, 2007 and September 30, 2007 and its Current Reports on Form 8-K filed in 2007 prior to November 2, 2007, or additionally with respect to FES in its Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 (copies of which have been furnished to each Lender), there has been no material adverse change in the business, condition (financial or otherwise), results of operations or prospects of such Borrower and its Consolidated Subsidiaries, taken as a whole, since December 31, 2006.”

Section 4.  Conditions to Effectiveness of Credit Agreement Amendment.  Section 3 of this Consent and Amendment (the “Amendments”) shall be effective as of the date hereof when and if the following conditions are satisfied (such date being the “Amendment Date”):

(a)   The Administrative Agent shall have received the following, each dated the Amendment Date, in form and substance satisfactory to the Administrative Agent and with one copy for each Fronting Bank and each Lender:

  (i)Counterparts of this Consent and Amendment, duly executed by each of the Borrowers and each Lender;

        (ii)Certified copies of the resolutions of the Board of Directors of each Borrower approving the Amendments and of all documents evidencing any other necessary corporate action with respect to the Amendments;

        (iii)A certificate of the Secretary or an Assistant Secretary of each Borrower certifying (A) the names and true signatures of the officers of such Borrower authorized to sign this Consent and Amendment and the other documents to be delivered hereunder; (B) that attached thereto are true and correct copies of the Organizational Documents of such Borrower, in each case as in effect on such date; and (C) that attached thereto are true and correct copies of all governmental and regulatory authorizations and approvals (including such Borrower’s Approval, as applicable) required for the due execution and delivery by such Borrower of this Consent and Amendment and the performance by such Borrower of the Amendments;

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        (iv)        An opinion or opinions of counsel for the Borrowers regarding the Amendments in a form reasonably satisfactory to the Administrative Agent;

        (v)       A favorable opinion of King & Spalding LLP, special New York counsel for the Administrative Agent; and

        (vi)     Such other certifications, opinions, financial or other information, approvals and documents as the Administrative Agent, any Fronting Bank, any Swing Line Lender or any other Lender may reasonably request, all in form and substance satisfactory to the Administrative Agent, such Fronting Bank, such Swing Line Lender or such other Lender (as the case may be).

(b)  The representations and warranties of the Borrowers set forth in Section 5 below shall be true and correct in all material respects on and as of the Amendment Date as though made on and as of such date.

Section 5.  Representations and Warranties. Each Borrower represents and warrants that (i) the representations and warranties contained in Article IV of the Credit Agreement, as amended hereby (with each reference therein to “this Agreement”, “hereunder” and words of like import referring to the Credit Agreement being deemed to be a reference to this Amendment and the Credit Agreement, as amended hereby), are true and correct on and as of the date hereof as though made on and as of such date, and (ii) no event has occurred and is continuing, or would result from the execution and delivery of this Consent and Amendment, that constitutes an Event of Default or an Unmatured Default.

Section 6.  Effect on the Credit Agreement.  The execution, delivery and effectiveness of this Consent and Amendment shall not, except as expressly set forth herein, operate as a waiver of any right, power or remedy of any Lender, Swing Line Lender, Fronting Bank or the Administrative Agent under the Credit Agreement, or constitute a waiver of any provision of the Credit Agreement.  Except as expressly set forth herein, the Credit Agreement is and shall continue to be in full force and effect and is hereby in all respects ratified and confirmed. This Consent and Amendment shall be binding on the parties hereto and their respective successors and permitted assigns under the Credit Agreement.

Section 7.  Costs, Expenses and Taxes.  FE agrees to pay on demand all costs and expenses incurred by either the Administrative Agent and any Fronting Banks in connection with the preparation, execution and delivery of this Amendment and any other documents to be delivered hereunder, including, without limitation, the reasonable fees and out-of-pocket expenses of counsel for the Administrative Agent and the Fronting Banks with respect thereto and with respect to advising the Administrative Agent and the Fronting Banks as to their rights and responsibilities under this Consent and Amendment.  FE further agrees to pay on demand all costs and expenses, if any (including, without limitation, reasonable fees and out-of-pocket expenses of counsel), incurred by the Administrative Agent, the Fronting Banks and the Lenders in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Consent and Amendment and the other documents to be delivered hereunder, including, without limitation, counsel fees and expenses in connection with the enforcement of rights under Section 8.05(a) of the Credit Agreement. In addition, FE agrees to pay any present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies that arise from the execution or delivery of, or otherwise with respect to, this Amendment.

If you consent and agree to the foregoing, please evidence such consent and agreement by (i) executing and returning one counterpart of this Amendment by facsimile or e-mail to Sarah Norris (fax no. 212-556-2222; e-mail snorris@kslaw.com) and (ii) executing and returning six original counterparts to this Consent and Amendment by overnight mail to King & Spalding LLP, 1185 Avenue of the Americas, New York, New York 10036, Attention: Sarah Norris, no later than 5:00 p.m., New York City time, on November 16, 2007.

[Remainder of page intentionally left blank.]

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Very truly yours,
FIRSTENERGY CORP.
FIRSTENERGY SOLUTIONS CORP.
AMERICAN TRANSMISSION SYSTEMS, INCORPORATED
OHIO EDISON COMPANY
PENNSYLVANIA POWER COMPANY
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
THE TOLEDO EDISON COMPANY
METROPOLITAN EDISON COMPANY
PENNSYLVANIA ELECTRIC COMPANY
By
	James F. Pearson
	Treasurer
JERSEY CENTRAL POWER & LIGHT COMPANY
By
	Randy Scilla
	Treasurer

    Consent and Amendment Signature Page       

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The undersigned hereby consent
and agree to the foregoing:
CITIBANK, N.A.
By
	Name:
	Title:

Consent and Amendment Signature Page       

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BARCLAYS BANK PLC
By
	Name:
	Title:

    Consent and Amendment Signature Page       

8

JPMORGAN CHASE BANK, N.A.
By
	Name:
	Title:

    Consent and Amendment Signature Page

9

KEYBANK NATIONAL ASSOCIATION
By
	Name:
	Title:

    Consent and Amendment Signature Page       

10

WACHOVIA BANK, NATIONAL ASSOCIATION
By
	Name:
	Title:

    Consent and Amendment Signature Page

11

THE ROYAL BANK OF SCOTLAND PLC
By
	Name:
	Title:

    Consent and Amendment Signature Page

12

THE BANK OF NOVA SCOTIA
By
	Name:
	Title:

    Consent and Amendment Signature Page

13

BANK OF AMERICA, N.A.
By
	Name:
	Title:

    Consent and Amendment Signature Page       

14

THE BANK OF NEW YORK
By
	Name:
	Title:

    Consent and Amendment Signature Page       

15

CREDIT SUISSE, CAYMAN ISLANDS BRANCH
By
	Name:
	Title:
By
	Name:
	Title:

    Consent and Amendment Signature Page       

16

MORGAN STANLEY BANK
By
	Name:
	Title:

    Consent and Amendment Signature Page

17

UBS LOAN FINANCE LLC
By
	Name:
	Title:
By
	Name:
	Title:

    Consent and Amendment Signature Page       

18

UNION BANK OF CALIFORNIA, N.A.
By
	Name:
	Title:

    Consent and Amendment Signature Page       

19

LEHMAN BROTHERS BANK, FSB
By
	Name:
	Title:

    Consent and Amendment Signature Page       

20

WILLIAM STREET CREDIT CORPORATION
By
	Name:
	Title:

    Consent and Amendment Signature Page       

21

NATIONAL CITY BANK
By
	Name:
	Title:

    Consent and Amendment Signature Page       

22

SUMITOMO MITSUI BANKING CORPORATION
By
	Name:
	Title:

    Consent and Amendment Signature Page       

23

MIZUHO CORPORATE BANK, LTD.
By
	Name:
	Title:

    Consent and Amendment Signature Page       

24

PNC BANK, NATIONAL ASSOCIATION
By
	Name:
	Title:

    Consent and Amendment Signature Page       

25

U.S. BANK, N.A.
By
	Name:
	Title:

    Consent and Amendment Signature Page       

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SUNTRUST BANK
By
	Name:
	Title:

    Consent and Amendment Signature Page       

27

MELLON BANK, N.A.
By
	Name:
	Title:

    Consent and Amendment Signature Page       

28

FIRST COMMERCIAL BANK, as a Bank
By
	Name:
	Title:

    Consent and Amendment Signature Page       

29

FIFTH THIRD BANCORP
By
	Name:
	Title:

    Consent and Amendment Signature Page       

30

KBC BANK N.V., as a Bank
By
	Name:
	Title:

    Consent and Amendment Signature Page       

31

FIRSTMERIT BANK. N.A.
By
	Name:
	Title:

    Consent and Amendment Signature Page       

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EX-10.4

     February 26, 2008

Mr. Gary R. Leidich

4672 Barnsleigh Drive

Fairlawn, OH 44333

Dear Gary,

The purpose of this letter agreement (“Agreement”) is to set forth the general terms and conditions of your continued employment with FirstEnergy Service Company or any of its affiliates (collectively “FirstEnergy” or the “Company”) for the term of this Agreement:

1.   Effective March 2, 2008, your title will be Executive Vice President of FirstEnergy Corp. and President, FE Generation, and your duties and responsibilities will be commensurate with those customarily performed, undertaken and exercised by persons situated in a similar executive capacity, including, without limitation responsibility for the FirstEnergy Fossil Generation and Commodity Operations, and such other duties as may be assigned from time to time.  In consideration of your performance of such duties you will be compensated as follows:

(a)   Base Salary.  You will receive a base salary (the “Base Salary”) at an annual rate of Six Hundred Fifty Thousand Dollars ($650,000) which will be payable in accordance with the existing payroll practices of FirstEnergy.  The Base Salary will be reviewed at least annually at the same time as the base salaries of FirstEnergy’s other executives.

(b)   Annual Bonus.  You will be a participant in FirstEnergy’s 2007 Incentive Plan (“ICP”) and be eligible to receive an annual bonus each year under the Short-Term Incentive Program (“STIP”) component of the ICP (or any successor program).  Your annual short-term target opportunity will be set by the Compensation Committee of the Board of Directors at the same time as other senior executive officers.  For 2008, your target bonus opportunity will be 80% of your Base Salary.  Any annual incentive compensation awarded to you will be payable in accordance with the provisions of the STIP.  The Key Performance Indicators (“KPIs”), which serve as the basis for determining the amount of the annual bonus earned, will be set and approved by the Company’s Board of Directors and provided to you as soon as practicable thereafter.

(c)   Long-Term Incentive Compensation.  You are eligible for a long-term incentive opportunity under the Long-Term Incentive Program (“LTIP”) component of the ICP.  Your annual long-term target opportunity will be set by the Compensation Committee of the Board of Directors at the same time as other senior executive officers.  For 2008, your target bonus opportunity for Performance-Adjusted Restricted Stock Units will be 138% of your Base Salary.  For 2008, your target bonus opportunity for Performance Shares will be 146% of your Base Salary.  Any long-term incentive compensation awarded to you will be payable in accordance with the provisions of the LTIP.

Gary R. Leidich                                                                                                                                       2                                  & #160;                                                                          February 26, 2008

As soon as practicable after the execution of this Agreement, the Company will provide you a grant of restricted FirstEnergy common stock units with an equivalent cash value of approximately One Million Three Hundred Thousand Dollars ($1,300,000).  The restricted stock units will be granted under and subject to the terms of the Company’s ICP and a restricted stock unit agreement to be entered into between you and the Company.  The stock unit grant will fully vest on June 30, 2010 and can be increased or decreased by 25% at that time based on the achievement of specific corporate performance criteria.  The criteria and the ultimate adjustment will mirror the annual 2008 and 2009 performance measures for the Performance-Adjusted Restricted Stock Unit grants.  In the event your employment is terminated by the Company without Cause, as defined in the ICP, prior to June 30, 2010, the stock unit grant will fully vest on the date of your termination.  In the event you voluntarily resign or retire prior to June 30, 2010, the restricted stock unit grant will vest on a prorated basis based on your full months of service from the date of grant through the termination of your employment.  In the event of your death, the stock unit grant will fully vest.

(d)   Previously Granted Stock Award.  In March 2005, you were granted 50,000 shares of restricted FirstEnergy common stock pursuant to a Restricted Stock Agreement.  You and the Company hereby agree that in the event your employment is terminated by the Company without Cause prior to March 1, 2010, this stock grant will fully vest on the date of your termination.  Consistent with the terms of the Restricted Stock Agreement, in the event you voluntarily resign or retire prior to March 1, 2010, the restricted stock grant will be forfeited in its entirety.  The Restricted Stock Agreement will be amended to reflect these terms.

(e)   Prior Severance Benefit.  Pursuant to the terms of your 1997 agreement with Centerior Energy Corporation (“Centerior”) which provided you with a severance benefit due to the change in control of Centerior, you remain entitled to the lump-sum amount of $1,095,889 payable to you when you reach age 62.  This lump-sum amount is subject to gross-up to cover any applicable excise tax.

(f)   Employee Benefits.  The Company maintains a Flexible Benefits Plan that includes programs providing health care insurance, dental insurance, group term life insurance, accidental death and dismemberment insurance, long-term disability, long-term care, dependent care and health care spending accounts.  You will be eligible to participate in the FirstEnergy Flexible Benefits Plan, as well as all executive and employee welfare benefit plans, programs, policies and arrangements sponsored, maintained or contributed to by FirstEnergy on the same level as other senior executive officers of FirstEnergy, subject to the terms and conditions of such plans.  Consistent with prior agreements, you are not eligible to participate in the FirstEnergy Supplemental Executive Retirement Program (the “SERP”).

(g)   Financial Planning.  You will be entitled to the financial planning benefits available to other senior executive officers during your employment with the Company and will be entitled to continue to receive the financial planning benefits for one (1) year following the date of the termination of your employment, provided that the Company continues to offer this benefit to other similarly situated executives of FirstEnergy.

Gary R. Leidich                                                                                                                                       3  
60;                                                                                                         February 26, 2008

(h)   Executive Severance Plan.  You and the Company agree that, notwithstanding any other agreement you may have had with the Company or any of its affiliates, under no circumstances will you be eligible for benefits under the Company’s Executive Severance Benefits Plan or any successor plan at any time.

(i)   Other Agreements.  This Agreement supersedes any other agreements you may have had with the Company regarding the terms of your employment.

2.   The term of this Agreement shall be from the date so agreed below until June 30, 2010; unless either terminated early by either party for any reason upon written notice given 60 days in advance, or mutually extended in writing.

If the above is agreeable to you, please sign where indicated and return a copy to me for our records.  You should retain a copy for yourself.  If you have any questions, please do not hesitate to call.

 Sincerely,

Anthony J. Alexander

President & Chief Executive Officer

So Agreed: _______________________________________________

Date:____________________________________________________

EX-10.5

       February 26, 2008

Mr. Richard R. Grigg

4140 Far-O-Way Lane

Richfield, OH 44286

Dear Dick,

Based on our discussions we have mutually agreed to extend the expiration date of your January 16, 2007, amendment to your July 20, 2004 employment agreement (collectively the “Prior Agreements”) from March 31, 2008 to June 30, 2010.

In consideration of the foregoing, the sufficiency of which is hereby acknowledged by the parties, your Prior Agreements are hereby replaced in their entirety with the following terms of this agreement (“Agreement”) which shall set forth the general terms and conditions of your continued employment with the FirstEnergy Service Company or any of its affiliates (collectively “FirstEnergy” or the “Company”) for the term of this Agreement:

1.   Effective March 2, 2008, your title will be Executive Vice President of FirstEnergy Corp. and President, FE Utilities, and your duties and responsibilities will be commensurate with those customarily performed, undertaken and exercised by persons situated in a similar executive capacity, including, without limitation responsibility for the FirstEnergy Energy Delivery and Customer Service Business Unit and such other duties as may be assigned from time to time.  In consideration of your performance of such duties you will be compensated as follows:

(a)   Base Salary.  You will receive a base salary (the “Base Salary”) at an annual rate of Seven Hundred Fifty Thousand Dollars ($750,000) which will be payable in accordance with the existing payroll practices of FirstEnergy.  The Base Salary will be reviewed at least annually at the same time as the base salaries of FirstEnergy’s other executives.

(b)   Annual Bonus.  You will be a participant in FirstEnergy’s 2007 Incentive Plan (“ICP”) and be eligible to receive an annual bonus each year under the Short-Term Incentive Program (“STIP”) component of the ICP (or any successor program).  Your annual short-term target opportunity will be set by the Compensation Committee of the Board of Directors at the same time as other senior executive officers.  For 2008, your target bonus opportunity will be 70% of your Base Salary.  Any annual incentive compensation awarded to you will be payable in accordance with the provisions of the STIP.  The Key Performance Indicators (“KPIs”), which serve as the basis for determining the amount of the annual bonus earned, will be set and approved by the Company’s Board of Directors and provided to you as soon as practicable thereafter.

(c)   Long-Term Incentive Compensation.  You are eligible for a long-term incentive opportunity under the Long-Term Incentive Program (“LTIP”) component of the ICP.  Your annual long-term target opportunity will be set by the Compensation Committee of the Board of Directors at the same time as other senior executive officers.  For 2008, your target bonus opportunity for Performance-Adjusted Restricted Stock Units will be 101% of your Base Salary.  For 2008, your target bonus opportunity for Performance Shares will be 107% of your Base Salary.  Any long-term incentive compensation awarded to you will be payable in accordance with the provisions of the LTIP.

Mr. Richard R. Grigg                                                                                                                              2                                                                                                                 February 26, 2008

As soon as practicable after the execution of this Agreement, the Company will provide you a grant of restricted FirstEnergy common stock units with an equivalent cash value of approximately One Million One Hundred Thousand Dollars ($1,100,000).  The restricted stock units will be granted under and subject to the terms of the Company’s ICP and a restricted stock unit agreement to be entered into between you and the Company.  The stock unit grant will fully vest on June 30, 2010 and can be increased or decreased by 25% at that time based on the achievement of specific corporate performance criteria.  The criteria and the ultimate adjustment will mirror the annual 2008 and 2009 performance measures for the Performance-Adjusted Restricted Stock Unit grants.  In the event your employment is terminated by the Company without Cause, as defined in the ICP, prior to June 30, 2010, the stock unit grant will fully vest on the date of your termination.  In the event you voluntarily resign or retire prior to June 30, 2010, the restricted stock unit grant will vest on a prorated basis based on your full months of service from the date of grant through the termination of your employment.  In the event of your death, the stock unit grant will fully vest.

(d)   Change in Control Agreement (CIC).  The CIC executed by you on December 31, 2007, remains in effect pursuant to its terms and is unaffected by the terms of this Agreement.

(e)   Employee Benefits.  The Company maintains a Flexible Benefits Plan that includes programs providing health care insurance, dental insurance, group term life insurance, accidental death and dismemberment insurance, long-term disability, long-term care, dependent care and health care spending accounts.  Except as specifically set forth in this Agreement, you will be eligible to participate in the FirstEnergy Flexible Benefits Plan, as well as all executive and employee welfare benefit plans, programs, policies and arrangements sponsored, maintained or contributed to by FirstEnergy on the same level as other senior executive officers of FirstEnergy, subject to the terms and conditions of such plans.

At the conclusion of your employment with the Company, you will be granted the maximum credit (currently 85 points) for purposes of determining the Company contribution toward the cost of retiree health care coverage under the Flexible Benefits Plan or any successor plan, so long as retiree health care is provided under the Flexible Benefits Plan and a Company contribution is provided to other senior executive officers of FirstEnergy.

In the event of your death as an active employee, health care coverage for your surviving spouse will be obtained and provided at substantially the same coverage level and participant contribution level as available to active employees through March 31, 2008.  Thereafter, health care coverage would be provided to your surviving spouse on the same terms and conditions as provided to other surviving spouses under the terms of the Company’s welfare benefit plan.

(f)   Pension Benefits.  You are eligible to participate in any and all of FirstEnergy’s qualified and non-qualified pension, retirement, and deferred compensation plans, programs, policies and arrangements as they relate to FirstEnergy’s senior executive officers with the exception of the Supplemental Executive Retirement Program (the “SERP”).  Your participation in any of the programs for which you are eligible will be on the same terms and conditions as applicable to other participants in those programs and will be governed by the applicable plan documents.

Mr. Richard R. Grigg                                                                                                                              3                                           
60;                                                                     February 26, 2008

Upon the termination of your employment you will be provided additional service credit of four (4) years and two (2) months for purposes of calculating your non-qualified supplemental pension benefit.  In the event of your death while you are an active employee, your service credit for purposes of calculating this non-qualified supplemental pension benefit will be enhanced as necessary to give you credit for a total of at least 10 years of service.

(g)   Financial Planning.  You will be entitled to the financial planning benefits available to other senior executive officers during your employment with the Company and will be entitled to continue to receive the financial planning benefits for one (1) year following the termination of your employment, provided that the Company continues to offer this benefit to other similarly situated executives of FirstEnergy.

(h)   Executive Severance Plan.  You and the Company agree that, notwithstanding any other agreements you may have had with the Company or any of its affiliates, under no circumstances will you be eligible for benefits under the Company’s Executive Severance Benefits Plan or any successor plan at any time.

(i)   Other Agreements.  This Agreement supersedes any other agreements you may have had with the Company regarding the terms of your employment.

2.   The term of this agreement shall be from the date so agreed below until June 30, 2010; unless either terminated early by either party for any reason upon written notice given 60 days in advance, or mutually extended in writing.

If the above is agreeable to you, please sign where indicated and return a copy to me for our records.  You should retain a copy for yourself.  If you have any questions, please do not hesitate to call.

Sincerely,

Anthony J. Alexander

President & Chief Executive Officer

So Agreed: _______________________________________________

Date:____________________________________________________

EX-10.6

FirstEnergy Corp.

Executive and Directors Incentive Compensation Plan

Restricted Stock Unit Agreement

      Award No.:   RSUP8

      Number of Shares Awarded:  XXX shares

Grantee:  Gary R. Leidich (per Employment Agreement dated 2/26/2008)

This Restricted Stock Unit Agreement (the “Agreement”) is entered into as of the 27th day of February 2008 between FirstEnergy Corp. and the “Grantee."  For the purposes of this Agreement, the term “Company” or “FE” means FirstEnergy Corp. and/or its subsidiaries, singularly or collectively.

SECTION ONE - AWARD

As of the date of this Agreement, in accordance with the FirstEnergy Corp. 2007 Incentive Plan  (the “Plan”) and the terms and conditions of this Agreement, the Company grants to the Grantee the right to receive, at the end of the Period of Restriction (as defined below) a number of shares common stock of the Company (“Common Stock”) equal to number of restricted stock units set forth above (the “Restricted Stock Units”), subject to adjustment based on FE’s performance as described below.

SECTION TWO - GENERAL TERMS

This agreement is subject to the Plan and the following terms and conditions:

Period of Restriction

For the purposes of this Agreement, “Period of Restriction” means the period beginning on the Date of Grant set forth above and ending on the earliest of:

a) 5:00 p.m. Akron Time on June 30, 2010;

b) The date of the Grantee’s death;

c) The date that the Grantee’s employment is terminated due to Disability (as defined, except as otherwise provided in "409A" below, under the then established rules of the Company or any of its subsidiaries, as the case may be); or

d) The date that the Grantee’s employment is terminated by the Company, without Cause, prior to June 30, 2010.

In addition, to the extent described under the caption “Forfeiture” below, the Period of Restriction will end with respect to a pro rata portion of the Restricted Stock Units if (a) the Grantee’s employment is voluntarily terminated, (b) the Grantee retires, or (c) the Grantee continues to be employed by FE but ceases to be employed in an executive position during the two-year Performance Period.  Neither the Restricted Stock Units nor the right to receive the Common Stock issuable under the Restricted Stock Units may be sold, transferred, pledged or assigned by the Grantee until the end of the Period of Restriction, except as set forth in Section Three of this Agreement.

Performance Adjusted Restricted Stock Units

If the Delivery Date (as defined below under "Delivery of Common Stock") is June 30, 2010, the actual number of shares issuable under the Restricted Stock Units awarded pursuant to this Agreement may be adjusted upward or downward by twenty-five percent (25%) from the base number of shares issuable under the Restricted Stock Units (as set forth in Section One of this Agreement), including all Dividend Equivalent, based on FE’s performance against three key metrics.  The Committee has identified the three performance metrics as Earnings Per Share, Safety Record, and Operational Performance Index.

FE’s performance against the three performance metrics will be evaluated, with respect to each performance metric, by comparing the average of FE’s actual annual performance over the two years beginning in the year of grant of this Award to the average of the annual target performance levels established over the same period to determine whether the Company has exceeded, met or fallen below the target performance level for that particular performance metric. The annual target performance level relating to each metric for each year will be set by the Committee in February of that year. The following guidelines will be used to adjust the number of shares issuable under the Restricted Stock Units awarded pursuant to this Agreement:

·   If the Company’s average annual performance meets or exceeds the average of the target performance levels established by the Committee with respect to all three of the performance metrics identified above, the base number of shares issuable under the Restricted Stock Units (as set forth in Section One of this Agreement) and all Dividend Equivalents will be increased by twenty-five percent (25%).  

·   If the Company’s average annual performance falls below the average of the target performance levels established by the Committee with respect to all three of the performance metrics identified above, the base number of shares issuable under the Restricted Stock Units (as set forth in Section One of this Agreement) and all Dividend Equivalents will be decreased by twenty-five percent (25%).  

·   If the Company’s average annual performance meets or exceeds the average of the target performance levels established by the Committee with respect to one or more of the performance metrics identified above, but falls below the average of the target performance levels with respect to one or more of the other performance metrics, the base number of shares issuable under the Restricted Stock Units (as set forth in Section One of this Agreement) will not be increased or decreased.  All Dividend Equivalents will be paid.

Withholding Tax

The Company shall sell shares on the open market in an amount sufficient to satisfy federal (including FICA and Medicare), state, and/or local taxes required by law to be withheld in connection with the grant of the Restricted Stock Units or the delivery of shares of Common Stock subject to the Restricted Stock Units granted under this Agreement, provided however that, pursuant to administrative rules adopted by the Company, the Grantee may elect to have the Company sell shares on the open market in an amount in excess of the applicable withholding amounts required by law up to an amount not to exceed the total federal (including FICA and Medicare), state and local  taxes that could be payable by the Grantee in connection with the grant of the Restricted Stock Units or the issuance of shares of Common Stock subject to the Restricted Stock Units granted under this Agreement.

Delivery of Common Stock

The date that Shares of Common Stock shall be delivered to the Grantee (the “Delivery Date”) shall be as follows for each specified event:

·   June 30, 2010 if the delivery is on account of  paragraph a) of Section Two entitled “Period of Restriction”, Grantee’s retirement, voluntary resignation, or if the Grantee continues to be employed by FE but ceases to be employed in an executive position during the two-year Performance Period;

   ·   As soon as practicable after the Grantee’s death or Disability pursuant to paragraphs b), c), or  d) of  Section Two entitled “Period of Restriction”.  If employment is terminated pursuant to paragraphs b), c) or d), the Grantee will receive a payout equal to the full number of shares granted in this Agreement and all Dividend Equivalents earned up to the date of termination.  The payout will not be adjusted for performance.

Upon payment of tax obligations and as soon as practicable after  the Delivery Date, the Company shall issue to the Grantee shares of FE Common Stock under the Restricted Stock Units.  The Company will issue a number of shares of Common Stock equal to the number of Restricted Stock Units awarded under this Agreement, as adjusted, less any shares withheld to cover the tax obligations in accordance with the preceding paragraph; provided that, no fractional shares of Common Stock will be issued under the Restricted Stock Units and any fractional shares to which the Grantee would otherwise be entitled will be rounded up to the next full share. All shares issued will be registered in the name of the Grantee and will be held in safekeeping with FE.

Forfeiture

The Grantee shall forfeit all of the Restricted Stock Units and any right under this Agreement to receive Common Stock upon the occurrence of any of the following events before the expiration of the Period of Restriction:

·   Termination of employment with the Company or its subsidiaries for any reason.  Notwithstanding the foregoing, no forfeiture shall occur if termination of employment with the Company is due to death, Disability (as defined under the then established rules of the Company or any of its subsidiaries, as the case may be), occurs at anytime following a Change of Control, or if the Grantee’s employment is terminated by the Company, without Cause, prior to June 30, 2010.

·   Any attempt to sell, transfer, pledge, or assign the Restricted Stock Units or the right to receive the Common Stock issuable under the Restricted Stock Units in violation of this Agreement.

If the Grantee’s employment is voluntarily terminated, or if the Grantee retires (as defined under the then established rules of the Company or any of its subsidiaries, as the case may be); or if the Grantee continues to be employed by FE but ceases to be employed in an executive position during the two-year Performance Period the Restricted Stock Units in this Agreement will be forfeited and payable as follows, subject to Section 3.8 of the Plan:

·   If the Grantee’s employment terminates prior to a full month after the Date of Grant, all Restricted Stock Units and any Restricted Stock Units earned as Dividend Equivalents will be forfeited.

·   If the Grantee’s employment terminates a full month or more after the Date of Grant, the Grantee will be entitled to a prorated number of Restricted Stock Units.  The number of shares to be prorated will be calculated as of the June 30, 2010 vesting date by multiplying the number of shares initially awarded and all Dividend Equivalents earned through the vesting date, by the number of full months served after the date of grant, divided by twenty-four months.  The prorated shares will then be adjusted upward or downward by the performance factors in accordance with the provisions under the caption “Performance Adjusted Restricted Stock Units”, (as determined by the Compensation Committee).  All fractional shares will be rounded up to the next full shares.   The remaining portion of Restricted Stock Units initially granted and all associated Dividend Equivalents will be forfeited.

Upon the occurrence of any of the above events (for which no exception has been made as set forth above) before the expiration of the Period of Restriction, the Restricted Stock Units shall be forfeited by the Grantee to the Company and the Grantee’s interest in the Restricted Stock Units and the Common Stock issuable under the Restricted Stock Units, including the right to receive Dividend Equivalents (as defined below) shall terminate immediately in accordance with the foregoing, unless such forfeiture is waived in the sole discretion of the Committee.  However, any Restricted Stock Units not forfeited shall continue to be adjusted for performance in accordance with the provisions under the caption "Performance Adjusted Restricted Stock Units" above and shall include the right to receive Dividend Equivalents.

Continuing Transfer Restrictions

Should Grantee’s employment with FE continue after expiration of the Period of Restriction, until such time as Grantee’s employment with FE and its subsidiaries terminates, the Grantee will not be permitted to sell, transfer, pledge, or assign (collectively, “Transfer”) shares of Common Stock issued under this Agreement (the “Transfer Restricted Securities”) to the extent prohibited in this paragraph.  If Grantee is subject to the employee share ownership guidelines established by the Committee, then Grantee may not Transfer any Transfer Restricted Securities to the extent that Grantee’s aggregate ownership of FE stock immediately before and after the Transfer does not meet or exceed the ownership level that applies to Grantee under those share ownership guidelines.  In addition, if Grantee is subject to the employee share ownership guidelines established by the Committee, in no case may Grantee Transfer any Transfer Restricted Securities to the extent that the Transfer, when aggregated with all of Grantee’s other Transfers, would cause Grantee to cease to own directly at least one-half of the Transfer Restricted Securities.  Any attempt to Transfer any Transfer Restricted Securities in violation of the foregoing shall be void, and FE shall not record such transfer on its books or treat any purported transferee of the Transfer Restricted Securities as the owner of such shares for any purpose.  The Committee may, however, in its sole discretion waive the foregoing transfer restrictions in whole or in part.  In addition, the Grantee will be permitted to satisfy tax withholding or income tax obligations associated with the Restricted Stock Units as provided for under the Withholding Tax section of this Agreement and any shares sold to satisfy withholding or income tax obligations will not be considered to be Transfer Restricted Securities.

Grantee agrees that FE may maintain custody of the certificate or certificates evidencing the Transfer Restricted Securities until the expiration of Grantee’s employment with FE and its subsidiaries in order to enforce the restrictions provided in this Agreement.  Upon the termination of Grantee’s employment with FE and its subsidiaries for any reason after (or contemporaneous with) termination of the Period of Restriction, the Grantee’s shares will be free of all encumbrances, provided that the Grantee has made the necessary arrangements with FE to satisfy any withholding obligations.

Dividend Equivalents

With respect to the Restricted Stock Units granted pursuant to this Agreement, the Grantee will be credited on the books and records of the Company with an amount per unit (the “Dividend Equivalent”) equal to the amount per share of any cash dividends declared by the Board on the outstanding Common Stock of the Company.  Such Dividend Equivalents will be credited in the form of an additional number of Restricted Stock Units which Restricted Stock Units, from the time of crediting, will be deemed to be in addition to and part of the base number of Restricted Stock Units awarded in Section One for all purposes hereunder, equal to the aggregate amount of Dividend Equivalents credited on this Award on the respective dividend payment date divided by the average of the high and low price per share of Common Stock on the respective dividend payment date. Until the Period of Restriction lapses or any forfeiture of the Restricted Stock Units occurs pursuant to the terms and conditions described above, the Company will credit, in additional Restricted Stock Units, to the Grantee’s Restricted Stock Unit award, an amount equal to the Dividend Equivalents in the manner set forth above.  The Restricted Stock Units attributable to the Dividend Equivalents will be either delivered or forfeited, as appropriate, under the same terms and conditions under this Agreement that apply to the other Restricted Stock Units.

Shareholder Rights

The Grantee shall have no rights as a shareholder of the Company, including voting rights, with respect to the Restricted Stock Units until the issuance of FE Common Stock upon expiration of the Period of Restriction.

Effect on the Employment Relationship

The Restricted Stock Units granted are voluntary and made on a one-time basis and does not constitute a commitment to make any future awards.  Nothing in this Agreement guarantees employment with the Company or any Subsidiary, nor does it confer any special rights or privileges to the Grantee as to the terms of employment.

Adjustments

In the event of any merger, reorganization, consolidation, recapitalization, separation, liquidation, stock dividend, stock split, combination, distribution, or other change in corporate structure of the Company affecting the Common Stock, the Committee will adjust the number and class of securities granted under this Agreement in a manner determined by the Committee, in its sole discretion, to be appropriate to prevent dilution or enlargement of the Restricted Stock Units granted under this Agreement.

Administration

1. This Agreement is governed by the laws of the State of Ohio without giving effect to the principles of conflicts of laws.

2. The terms and conditions of this Award may be modified by the Committee

        (a) In any case permitted by the terms of the Plan or this Agreement,

        (b) with the written consent of the Grantee, or

        (c) without the consent of the Grantee if the amendment is either not materially adverse to the interests of the Grantee or is necessary or appropriate in the view of the Committee to conform with, or to take into account, applicable law, including either exemption from or compliance with any applicable tax law.

3. The administration of this Agreement and the Plan will be performed in accordance with Article 3 of the Plan.  All determinations and decisions made by the Committee, the Board, or any delegate of the Committee as to the provisions of the Plan shall be final, conclusive, and binding on all persons.

4. The terms of this Agreement are governed at all times by the official text of the Plan and in no way alter or modify the Plan.

5. If a term is capitalized but not defined in this Agreement, it has the meaning given to it in the Plan.

6. To the extent a conflict exists between the terms of this Agreement and the provisions of the Plan, the provisions of the Plan shall govern.

409A

It is intended that this Agreement and the compensation and benefits hereunder either be exempt from, or comply with, Section 409A of the Internal Revenue Code (“Section 409A”), and this Agreement shall be so construed and administered.  In the event that the Company reasonably determines that any compensation or benefits payable under this Agreement may be subject to taxation under Section 409A, the Company, after consultation with the Grantee, shall have the authority to adopt, prospectively or retroactively, such amendments to this Agreement or to take any other actions it determines necessary or appropriate to (a) exempt the compensation and benefits payable under this Agreement from Section 409A or (b) comply with the requirements of Section 409A.  In no event, however, shall this section or any other provisions of this Agreement be construed to require the Company to provide any gross-up for the tax consequences of any provisions of, or payments under, this Agreement and the Company shall have no responsibility for tax consequences to Grantee (or the Grantee’s beneficiary) resulting from the terms or operation of this Agreement.

Notwithstanding any other provision in this Agreement to the contrary,  (1) a Grantee shall not be treated as having a termination of employment unless the Grantee would also be treated as having a separation of service for purposes of Section 409A, (2) a Grantee shall not be treated as having a disability unless the Grantee would also be treated as having a disability for purposes of Section 409A.

SECTION THREE - TRANSFER OF AWARD

Neither the Restricted Stock Units nor the right to receive the Common Stock issuable under the Restricted Stock Units are transferable during the life of the Grantee.  Only the Grantee shall have the right to receive the Common Stock issuable under the Restricted Stock Units, unless the Grantee is deceased, at which time the Common Stock issuable under the Restricted Stock Units may be received by the Grantee’s beneficiary (as designated under Article 12 of the Plan) or by will or by the laws of descent and distribution.

FirstEnergy Corp.

By _____________________________

                   Corporate Secretary

I acknowledge receipt of this Restricted Stock Unit Agreement and I accept and agree with the terms and conditions stated above.

________________________________

________________                                                                                           (Signature of Grantee)

            (Date)

EX-10.7

FirstEnergy Corp.

Executive and Directors Incentive Compensation Plan (Plan)

Restricted Stock Agreement

Amendment Dated as of February 26, 2008 to

Restricted Stock Agreement 32 (RS32) Dated March 1, 2005

FirstEnergy Corp. (“Company”), as authorized by the Compensation Committee of its Board of Directors on February 18, 2008, and in accordance with Section 3.3 of the above captioned Plan, and per the terms of your Employment Agreement dated February 26, 2008, amends Restricted Stock Agreement 32 between the Company and Gary R. Leidich (“Recipient”) as follows:

A.  Under the GENERAL TERMS heading, replace the Restricted Period subheading and text in its entirety with the following:

“Restricted Period

Restricted Shares shall not be sold, transferred, pledged, or assigned, until the earliest of:

a) March 1, 2010;

b) The date of the Recipient’s death;

c) The date that a Change in Control occurs;

d) The date that the Recipient’s employment is terminated due to Disability (as defined under Section 8.10 of the Plan); or

e) The date that your employment is terminated by the Company without Cause prior to March 1, 2010. “

                 B.  Under the GENERAL TERMS heading, replace the Forfeiture subheading and text in its entirety with the following:

“Forfeiture

The Recipient shall forfeit all of the Restricted Stock and any right to dividends on the Restricted Stock upon the occurrence of any the following events before the expiration of the Period of Restriction:

·    Termination of employment with the Company or its subsidiaries for any reason.  Notwithstanding the foregoing, no forfeiture shall occur if termination of employment with the Company is due to death, Disability (as defined under the then established rules of the Company or any of its subsidiaries, as the case may be) or under circumstances where Recipient is involuntarily terminated by the Company without Cause prior to March 1, 2010.

·         Any attempt to sell, transfer, pledge, or assign the Restricted Shares in violation of the above.

If the Recipient’s employment is involuntary terminated the Restricted Stock in this Agreement will become fully vested.  Additionally, the Recipient will be entitled to all restricted dividends on this Award, as of the date of termination.  The shares will be issued as soon as practicable after the termination, subject to satisfying the applicable tax withholding requirements and subject to Section 3.8 of the Plan.

Upon the occurrence of any of the above before the expiration of the Period of Restriction, the Restricted Stock shall be forfeited by the Recipient to the Company and the Recipient’s interest in the Restricted Stock and dividends earned on the Restricted Stock shall terminate immediately in accordance with the foregoing, unless such forfeiture is waived in the sole discretion of the Committee.”

 FirstEnergy Corp.

 By _______________________________

                                  Corporate Secretary

I acknowledge receipt of this Modification Agreement and I accept and agree with the terms and conditions stated above.

  ________________________________

________________                                                                                           (Signature of Recipient)

            (Date)

EX-10.8

FirstEnergy Corp.

Executive and Directors Incentive Compensation Plan

Restricted Stock Unit Agreement

      Award No.:   RSUP9

   Number of Shares Awarded:  XXX shares

Grantee:  Richard R. Grigg (per Employment Agreement dated 2/26/2008)

This Restricted Stock Unit Agreement (the “Agreement”) is entered into as of the 27th day of February 2008 between FirstEnergy Corp. and the “Grantee."  For the purposes of this Agreement, the term “Company” or “FE” means FirstEnergy Corp. and/or its subsidiaries, singularly or collectively.

SECTION ONE - AWARD

As of the date of this Agreement, in accordance with the FirstEnergy Corp. 2007 Incentive Plan  (the “Plan”) and the terms and conditions of this Agreement, the Company grants to the Grantee the right to receive, at the end of the Period of Restriction (as defined below) a number of shares common stock of the Company (“Common Stock”) equal to number of restricted stock units set forth above (the “Restricted Stock Units”), subject to adjustment based on FE’s performance as described below.

SECTION TWO - GENERAL TERMS

This agreement is subject to the Plan and the following terms and conditions:

Period of Restriction

For the purposes of this Agreement, “Period of Restriction” means the period beginning on the Date of Grant set forth above and ending on the earliest of:

a) 5:00 p.m. Akron Time on June 30, 2010;

b) The date of the Grantee’s death;

c) The date that the Grantee’s employment is terminated due to Disability (as defined, except as otherwise provided in "409A" below, under the then established rules of the Company or any of its subsidiaries, as the case may be);

d)	The date of  a Change in Control, or,
e)	The date that the Grantee’s employment is terminated by the Company, without Cause, prior to June 30, 2010.

In addition, to the extent described under the caption “Forfeiture” below, the Period of Restriction will end with respect to a pro rata portion of the Restricted Stock Units if (a) the Grantee’s employment is voluntarily terminated, (b) the Grantee retires, or (c) the Grantee continues to be employed by FE but ceases to be employed in an executive position during the two-year Performance Period.  Neither the Restricted Stock Units nor the right to receive the Common Stock issuable under the Restricted Stock Units may be sold, transferred, pledged or assigned by the Grantee until the end of the Period of Restriction, except as set forth in Section Three of this Agreement.

Performance Adjusted Restricted Stock Units

If the Delivery Date (as defined below under "Delivery of Common Stock") is June 30, 2010, the actual number of shares issuable under the Restricted Stock Units awarded pursuant to this Agreement may be adjusted upward or downward by twenty-five percent (25%) from the base number of shares issuable under the Restricted Stock Units (as set forth in Section One of this Agreement), including all Dividend Equivalent, based on FE’s performance against three key metrics.  The Committee has identified the three performance metrics as Earnings Per Share, Safety Record, and Operational Performance Index.

FE’s performance against the three performance metrics will be evaluated, with respect to each performance metric, by comparing the average of FE’s actual annual performance over the two years beginning in the year of grant of this Award to the average of the annual target performance levels established over the same period to determine whether the Company has exceeded, met or fallen below the target performance level for that particular performance metric. The annual target performance level relating to each metric for each year will be set by the Committee in February of that year. The following guidelines will be used to adjust the number of shares issuable under the Restricted Stock Units awarded pursuant to this Agreement:

·      If the Company’s average annual performance meets or exceeds the average of the target performance levels established by the Committee with respect to all three of the performance metrics identified above, the base number of shares issuable under the Restricted Stock Units (as set forth in Section One of this Agreement) and all Dividend Equivalents will be increased by twenty-five percent (25%).  

·      If the Company’s average annual performance falls below the average of the target performance levels established by the Committee with respect to all three of the performance metrics identified above, the base number of shares issuable under the Restricted Stock Units (as set forth in Section One of this Agreement) and all Dividend Equivalents will be decreased by twenty-five percent (25%).  

·        If the Company’s average annual performance meets or exceeds the average of the target performance levels established by the Committee with respect to one or more of the performance metrics identified above, but falls below the average of the target performance levels with respect to one or more of the other performance metrics, the base number of shares issuable under the Restricted Stock Units (as set forth in Section One of this Agreement) will not be increased or decreased.  All Dividend Equivalents will be paid.

Withholding Tax

The Company shall sell shares on the open market in an amount sufficient to satisfy federal (including FICA and Medicare), state, and/or local taxes required by law to be withheld in connection with the grant of the Restricted Stock Units or the delivery of shares of Common Stock subject to the Restricted Stock Units granted under this Agreement, provided however that, pursuant to administrative rules adopted by the Company, the Grantee may elect to have the Company sell shares on the open market in an amount in excess of the applicable withholding amounts required by law up to an amount not to exceed the total federal (including FICA and Medicare), state and local  taxes that could be payable by the Grantee in connection with the grant of the Restricted Stock Units or the issuance of shares of Common Stock subject to the Restricted Stock Units granted under this Agreement.

Delivery of Common Stock

The date that Shares of Common Stock shall be delivered to the Grantee (the “Delivery Date”) shall be as follows for each specified event:

·       June 30, 2010 if the delivery is on account of  paragraph a) or e) of Section Two entitled “Period of Restriction”, Grantee’s retirement, voluntary resignation, or if the Grantee continues to be employed by FE but ceases to be employed in an executive position during the two-year Performance Period; or

· As soon as practicable after the Grantee’s death or Disability, or termination of employment pursuant to paragraphs b), c), or d) of Section Two entitled “Period of Restriction”.  If employment is terminated pursuant to paragraphs b), c) or d), the Grantee will receive a payout equal to the full number of shares granted in this Agreement and all Dividend Equivalents earned up to the date of termination.  The payout will not be adjusted for performance.

Upon payment of tax obligations and as soon as practicable after  the Delivery Date, the Company shall issue to the Grantee shares of FE Common Stock under the Restricted Stock Units.  The Company will issue a number of shares of Common Stock equal to the number of Restricted Stock Units awarded under this Agreement, as adjusted, less any shares withheld to cover the tax obligations in accordance with the preceding paragraph; provided that, no fractional shares of Common Stock will be issued under the Restricted Stock Units and any fractional shares to which the Grantee would otherwise be entitled will be rounded up to the next full share. All shares issued will be registered in the name of the Grantee and will be held in safekeeping with FE.

Forfeiture

The Grantee shall forfeit all of the Restricted Stock Units and any right under this Agreement to receive Common Stock upon the occurrence of any of the following events before the expiration of the Period of Restriction:

·       Termination of employment with the Company or its subsidiaries for any reason.  Notwithstanding the foregoing, no forfeiture shall occur if termination of employment with the Company is due to death, Disability (as defined under the then established rules of the Company or any of its subsidiaries, as the case may be), occurs at anytime following a Change of Control, or if the Grantee’s employment is terminated by the Company, without Cause, prior to June 30, 2010.

·       Any attempt to sell, transfer, pledge, or assign the Restricted Stock Units or the right to receive the Common Stock issuable under the Restricted Stock Units in violation of this Agreement.

If the Grantee’s employment is voluntarily terminated, or if the Grantee retires (as defined under the then established rules of the Company or any of its subsidiaries, as the case may be); or if the Grantee continues to be employed by FE but ceases to be employed in an executive position during the two-year Performance Period the Restricted Stock Units in this Agreement will be forfeited and payable as follows, subject to Section 3.8 of the Plan:

·       If the Grantee’s employment terminates prior to a full month after the Date of Grant, all Restricted Stock Units and any Restricted Stock Units earned as Dividend Equivalents will be forfeited.

·       If the Grantee’s employment terminates a full month or more after the Date of Grant, the Grantee will be entitled to a prorated number of Restricted Stock Units.  The number of shares to be prorated will be calculated as of the June 30, 2010 vesting date by multiplying the number of shares initially awarded and all Dividend Equivalents earned through the vesting date, by the number of full months served after the date of grant, divided by twenty-four months.  The prorated shares will then be adjusted upward or downward by the performance factors in accordance with the provisions under the caption “Performance Adjusted Restricted Stock Units”, (as determined by the Compensation Committee).  All fractional shares will be rounded up to the next full shares.   The remaining portion of Restricted Stock Units initially granted and all associated Dividend Equivalents will be forfeited.

Upon the occurrence of any of the above events (for which no exception has been made as set forth above) before the expiration of the Period of Restriction, the Restricted Stock Units shall be forfeited by the Grantee to the Company and the Grantee’s interest in the Restricted Stock Units and the Common Stock issuable under the Restricted Stock Units, including the right to receive Dividend Equivalents (as defined below) shall terminate immediately in accordance with the foregoing, unless such forfeiture is waived in the sole discretion of the Committee.  However, any Restricted Stock Units not forfeited shall continue to be adjusted for performance in accordance with the provisions under the caption "Performance Adjusted Restricted Stock Units" above and shall include the right to receive Dividend Equivalents.

Continuing Transfer Restrictions

Should Grantee’s employment with FE continue after expiration of the Period of Restriction, until such time as Grantee’s employment with FE and its subsidiaries terminates, the Grantee will not be permitted to sell, transfer, pledge, or assign (collectively, “Transfer”) shares of Common Stock issued under this Agreement (the “Transfer Restricted Securities”) to the extent prohibited in this paragraph.  If Grantee is subject to the employee share ownership guidelines established by the Committee, then Grantee may not Transfer any Transfer Restricted Securities to the extent that Grantee’s aggregate ownership of FE stock immediately before and after the Transfer does not meet or exceed the ownership level that applies to Grantee under those share ownership guidelines.  In addition, if Grantee is subject to the employee share ownership guidelines established by the Committee, in no case may Grantee Transfer any Transfer Restricted Securities to the extent that the Transfer, when aggregated with all of Grantee’s other Transfers, would cause Grantee to cease to own directly at least one-half of the Transfer Restricted Securities.  Any attempt to Transfer any Transfer Restricted Securities in violation of the foregoing shall be void, and FE shall not record such transfer on its books or treat any purported transferee of the Transfer Restricted Securities as the owner of such shares for any purpose.  The Committee may, however, in its sole discretion waive the foregoing transfer restrictions in whole or in part.  In addition, the Grantee will be permitted to satisfy tax withholding or income tax obligations associated with the Restricted Stock Units as provided for under the Withholding Tax section of this Agreement and any shares sold to satisfy withholding or income tax obligations will not be considered to be Transfer Restricted Securities.

Grantee agrees that FE may maintain custody of the certificate or certificates evidencing the Transfer Restricted Securities until the expiration of Grantee’s employment with FE and its subsidiaries in order to enforce the restrictions provided in this Agreement.  Upon the termination of Grantee’s employment with FE and its subsidiaries for any reason after (or contemporaneous with) termination of the Period of Restriction, the Grantee’s shares will be free of all encumbrances, provided that the Grantee has made the necessary arrangements with FE to satisfy any withholding obligations.

Dividend Equivalents

With respect to the Restricted Stock Units granted pursuant to this Agreement, the Grantee will be credited on the books and records of the Company with an amount per unit (the “Dividend Equivalent”) equal to the amount per share of any cash dividends declared by the Board on the outstanding Common Stock of the Company.  Such Dividend Equivalents will be credited in the form of an additional number of Restricted Stock Units which Restricted Stock Units, from the time of crediting, will be deemed to be in addition to and part of the base number of Restricted Stock Units awarded in Section One for all purposes hereunder, equal to the aggregate amount of Dividend Equivalents credited on this Award on the respective dividend payment date divided by the average of the high and low price per share of Common Stock on the respective dividend payment date. Until the Period of Restriction lapses or any forfeiture of the Restricted Stock Units occurs pursuant to the terms and conditions described above, the Company will credit, in additional Restricted Stock Units, to the Grantee’s Restricted Stock Unit award, an amount equal to the Dividend Equivalents in the manner set forth above.  The Restricted Stock Units attributable to the Dividend Equivalents will be either delivered or forfeited, as appropriate, under the same terms and conditions under this Agreement that apply to the other Restricted Stock Units.

Shareholder Rights

The Grantee shall have no rights as a shareholder of the Company, including voting rights, with respect to the Restricted Stock Units until the issuance of FE Common Stock upon expiration of the Period of Restriction.

Effect on the Employment Relationship

The Restricted Stock Units granted are voluntary and made on a one-time basis and does not constitute a commitment to make any future awards.  Nothing in this Agreement guarantees employment with the Company or any Subsidiary, nor does it confer any special rights or privileges to the Grantee as to the terms of employment.

Adjustments

In the event of any merger, reorganization, consolidation, recapitalization, separation, liquidation, stock dividend, stock split, combination, distribution, or other change in corporate structure of the Company affecting the Common Stock, the Committee will adjust the number and class of securities granted under this Agreement in a manner determined by the Committee, in its sole discretion, to be appropriate to prevent dilution or enlargement of the Restricted Stock Units granted under this Agreement.

Administration

1. This Agreement is governed by the laws of the State of Ohio without giving effect to the principles of conflicts of laws.

2. The terms and conditions of this Award may be modified by the Committee

         (a) In any case permitted by the terms of the Plan or this Agreement,

         (b) with the written consent of the Grantee, or

         (c) without the consent of the Grantee if the amendment is either not materially adverse to the interests of the Grantee or is necessary or appropriate in the view of the Committee to conform with, or to take into account, applicable law, including either exemption from or compliance with any applicable tax law.

3. The administration of this Agreement and the Plan will be performed in accordance with Article 3 of the Plan.  All determinations and decisions made by the Committee, the Board, or any delegate of the Committee as to the provisions of the Plan shall be final, conclusive, and binding on all persons.

4. The terms of this Agreement are governed at all times by the official text of the Plan and in no way alter or modify the Plan.

5. If a term is capitalized but not defined in this Agreement, it has the meaning given to it in the Plan.

6. To the extent a conflict exists between the terms of this Agreement and the provisions of the Plan, the provisions of the Plan shall govern.

409A

It is intended that this Agreement and the compensation and benefits hereunder either be exempt from, or comply with, Section 409A of the Internal Revenue Code (“Section 409A”), and this Agreement shall be so construed and administered.  In the event that the Company reasonably determines that any compensation or benefits payable under this Agreement may be subject to taxation under Section 409A, the Company, after consultation with the Grantee, shall have the authority to adopt, prospectively or retroactively, such amendments to this Agreement or to take any other actions it determines necessary or appropriate to (a) exempt the compensation and benefits payable under this Agreement from Section 409A or (b) comply with the requirements of Section 409A.  In no event, however, shall this section or any other provisions of this Agreement be construed to require the Company to provide any gross-up for the tax consequences of any provisions of, or payments under, this Agreement and the Company shall have no responsibility for tax consequences to Grantee (or the Grantee’s beneficiary) resulting from the terms or operation of this Agreement.

Notwithstanding any other provision in this Agreement to the contrary,  (1) a Grantee shall not be treated as having a termination of employment unless the Grantee would also be treated as having a separation of service for purposes of Section 409A, (2) a Grantee shall not be treated as having a disability unless the Grantee would also be treated as having a disability for purposes of Section 409A.

SECTION THREE - TRANSFER OF AWARD

Neither the Restricted Stock Units nor the right to receive the Common Stock issuable under the Restricted Stock Units are transferable during the life of the Grantee.  Only the Grantee shall have the right to receive the Common Stock issuable under the Restricted Stock Units, unless the Grantee is deceased, at which time the Common Stock issuable under the Restricted Stock Units may be received by the Grantee’s beneficiary (as designated under Article 12 of the Plan) or by will or by the laws of descent and distribution.

FirstEnergy Corp.

By _____________________________

                      Corporate Secretary

I acknowledge receipt of this Restricted Stock Unit Agreement and I accept and agree with the terms and conditions stated above.

      ________________________________

________________                                                                                                (Signature of Grantee)

        (Date)

EX-10.9

FirstEnergy Corp.

Executive and Directors Incentive Compensation Plan

Restricted Stock Unit Agreement

  Award No.:   RSUP10

  Number of Shares Awarded:  XXX shares

Grantee:  FORM OF GRANT GIVEN TO TOP 5

This Restricted Stock Unit Agreement (the “Agreement”) is entered into as of the 3rd day of March 2008 between FirstEnergy Corp. and the “Grantee."  For the purposes of this Agreement, the term “Company” or “FE” means FirstEnergy Corp. and/or its subsidiaries, singularly or collectively.

SECTION ONE - AWARD

As of the date of this Agreement, in accordance with the FirstEnergy Corp. 2007 Incentive Plan  (the “Plan”) and the terms and conditions of this Agreement, the Company grants to the Grantee the right to receive, at the end of the Period of Restriction (as defined below) a number of shares common stock of the Company (“Common Stock”) equal to number of restricted stock units set forth above (the “Restricted Stock Units”), subject to adjustment based on FE’s performance as described below.

SECTION TWO - GENERAL TERMS

This agreement is subject to the Plan and the following terms and conditions:

Period of Restriction

For the purposes of this Agreement, “Period of Restriction” means the period beginning on the Date of Grant set forth above and ending on the earliest of:

a) 5:00 p.m. Akron Time on March 3, 2011;  

b) The date of the Grantee’s death;  

c) The date that the Grantee’s employment is terminated due to Disability (as defined, except as otherwise provided in "409A" below, under the then established rules of the Company or any of its subsidiaries, as the case may be); or  

d) The date that Grantee’s employment is terminated at any time following a Change in Control, provided that such termination occurs under the conditions specified in either Section 5(a) or 5(b) of Grantee’s Special Severance Agreement dated December 31, 2007, but without regard to the thirty-six (36) month period specified in Section 5(a) or 5(b) and provided further that such termination was not at Grantee's discretion pursuant to Section 5(c) of Grantee's Special Severance Agreement, dated December 31, 2007.

In addition, to the extent described under the caption “Forfeiture” below, the Period of Restriction will end with respect to a pro rata portion of the Restricted Stock Units if (a) the Grantee’s employment is terminated as a result of involuntary termination under conditions in which the Grantee qualifies for, elects to accept an employer severance benefit, if offered, and executes an agreement to release the Company in full against any and all claims as required by the arrangement or plan providing the employer severance benefit; (b) the Grantee retires, or (c) the Grantee continues to be employed by FE but ceases to be employed in an executive position during the three-year Performance Period.  Neither the Restricted Stock Units nor the right to receive the Common Stock issuable under the Restricted Stock Units may be sold, transferred, pledged or assigned by the Grantee until the end of the Period of Restriction, except as set forth in Section Three of this Agreement.

Performance Adjusted Restricted Stock Units

If the Delivery Date (as defined below under "Delivery of Common Stock") is March 3, 2011, the actual number of shares issuable under the Restricted Stock Units awarded pursuant to this Agreement may be adjusted upward or downward by twenty-five percent (25%) from the base number of shares issuable under the Restricted Stock Units (as set forth in Section One of this Agreement), including all Dividend Equivalents, based on FE’s performance against three key metrics.  The Committee has identified the three performance metrics as Earnings Per Share, Safety Record, and Operational Performance Index.

FE’s performance against the three performance metrics will be evaluated, with respect to each performance metric, by comparing the average of FE’s actual annual performance over the three years beginning in the year of grant of this Award to the average of the annual target performance levels established over the same period to determine whether the Company has exceeded, met or fallen below the target performance level for that particular performance metric. The annual target performance level relating to each metric for each year will be set by the Committee in February of that year. The following guidelines will be used to adjust the number of shares issuable under the Restricted Stock Units awarded pursuant to this Agreement:

·       If the Company’s average annual performance meets or exceeds the average of the target performance levels established by the Committee with respect to all three of the performance metrics identified above, the base number of shares issuable under the Restricted Stock Units (as set forth in Section One of this Agreement) and all Dividend Equivalents will be increased by twenty-five percent (25%).  

·       If the Company’s average annual performance falls below the average of the target performance levels established by the Committee with respect to all three of the performance metrics identified above, the base number of shares issuable under the Restricted Stock Units (as set forth in Section One of this Agreement) and all Dividend Equivalents will be decreased by twenty-five percent (25%).  

·       If the Company’s average annual performance meets or exceeds the average of the target performance levels established by the Committee with respect to one or more of the performance metrics identified above, but falls below the average of the target performance levels with respect to one or more of the other performance metrics, the base number of shares issuable under the Restricted Stock Units (as set forth in Section One of this Agreement) will not be increased or decreased.  All Dividend Equivalents will be paid.

Withholding Tax

The Company shall sell shares on the open market in an amount sufficient to satisfy federal (including FICA and Medicare), state, and/or local taxes required by law to be withheld in connection with the grant of the Restricted Stock Units or the delivery of shares of Common Stock subject to the Restricted Stock Units granted under this Agreement, provided however that, pursuant to administrative rules adopted by the Company, the Grantee may elect to have the Company sell shares on the open market in an amount in excess of the applicable withholding amounts required by law up to an amount not to exceed the total federal (including FICA and Medicare), state and local  taxes that could be payable by the Grantee in connection with the grant of the Restricted Stock Units or the issuance of shares of Common Stock subject to the Restricted Stock Units granted under this Agreement.

Delivery of Common Stock

The date that Shares of Common Stock shall be delivered to the Grantee (the “Delivery Date”) shall be as follows for each specified event:

·     March 3, 2011 if the delivery is on account of  paragraph a) of  Section Two entitled “Period of Restriction”, Grantee’s retirement or if the Grantee continues to be employed by FE but ceases to be employed in an executive position during the three-year Performance Period;

·     As soon as practicable after the Grantee’s death or Disability pursuant to paragraph b), c),  or d) of  Section Two entitled “Period of Restriction”;

Upon payment of tax obligations and as soon as practicable after  the Delivery Date, the Company shall issue to the Grantee shares of FE Common Stock under the Restricted Stock Units.  The Company will issue a number of shares of Common Stock equal to the number of Restricted Stock Units awarded under this Agreement, as adjusted, less any shares withheld to cover the tax obligations in accordance with the preceding paragraph; provided that, no fractional shares of Common Stock will be issued under the Restricted Stock Units and any fractional shares to which the Grantee would otherwise be entitled will be rounded up to the next full share. All shares issued will be registered in the name of the Grantee and will be held in safekeeping with FE.

Forfeiture

The Grantee shall forfeit all of the Restricted Stock Units and any right under this Agreement to receive Common Stock upon the occurrence of any of the following events before the expiration of the Period of Restriction:

·       Termination of employment with the Company or its subsidiaries for any reason.  Notwithstanding the foregoing, no forfeiture shall occur if termination of employment with the Company is due to death, Disability (as defined under the then established rules of the Company or any of its subsidiaries, as the case may be), or occurs at anytime following a Change of Control under circumstances where the Grantee is involuntarily terminated and would qualify for, elect to accept an employer severance benefit, if offered, and execute an agreement to release the Company in full against any and all claims as required by the arrangement or plan providing the employer severance benefit.

·       Any attempt to sell, transfer, pledge, or assign the Restricted Stock Units or the right to receive the Common Stock issuable under the Restricted Stock Units in violation of this Agreement.

If the Grantee’s employment is involuntary terminated under conditions in which the Grantee qualifies for, elects to accept an employer severance benefit, if offered, and executes an agreement to release the Company in full against any and all claims as required by the arrangement or plan providing the employer severance benefit; or if the Grantee retires (as defined under the then established rules of the Company or any of its subsidiaries, as the case may be); or if the Grantee continues to be employed by FE but ceases to be employed in an executive position during the three-year Performance Period the Restricted Stock Units in this Agreement will be forfeited and payable as follows, subject to Section 3.8 of the Plan:

·       If the Grantee’s employment terminates prior to a full month after the Date of Grant, all Restricted Stock Units and any Restricted Stock Units earned as Dividend Equivalents will be forfeited.

·     If the Grantee’s employment terminates a full month or more after the Date of Grant, the Grantee will be entitled to a prorated number of Restricted Stock Units.  The number of shares to be prorated will be calculated as of the March 3, 2011 vesting date by multiplying the number of shares initially awarded and all Dividend Equivalents earned through the vesting date, by the number of full months served after the date of grant, divided by thirty-six months.  The prorated shares will then be adjusted upward or downward by the performance factors in accordance with the provisions under the caption “Performance Adjusted Restricted Stock Units”, (as determined by the Compensation Committee).  All fractional shares will be rounded up to the next full shares.   The remaining portion of Restricted Stock Units initially granted and all associated Dividend Equivalents will be forfeited.

Upon the occurrence of any of the above events (for which no exception has been made as set forth above) before the expiration of the Period of Restriction, the Restricted Stock Units shall be forfeited by the Grantee to the Company and the Grantee’s interest in the Restricted Stock Units and the Common Stock issuable under the Restricted Stock Units, including the right to receive Dividend Equivalents (as defined below) shall terminate immediately in accordance with the foregoing, unless such forfeiture is waived in the sole discretion of the Committee.  However, any Restricted Stock Units not forfeited shall continue to be adjusted for performance in accordance with the provisions under the caption "Performance Adjusted Restricted Stock Units" above and shall include the right to receive Dividend Equivalents.

Continuing Transfer Restrictions

Should Grantee’s employment with FE continue after expiration of the Period of Restriction, until such time as Grantee’s employment with FE and its subsidiaries terminates, the Grantee will not be permitted to sell, transfer, pledge, or assign (collectively, “Transfer”) shares of Common Stock issued under this Agreement (the “Transfer Restricted Securities”) to the extent prohibited in this paragraph.  If Grantee is subject to the employee share ownership guidelines established by the Committee, then Grantee may not Transfer any Transfer Restricted Securities to the extent that Grantee’s aggregate ownership of FE stock immediately before and after the Transfer does not meet or exceed the ownership level that applies to Grantee under those share ownership guidelines.  In addition, if Grantee is subject to the employee share ownership guidelines established by the Committee, in no case may Grantee Transfer any Transfer Restricted Securities to the extent that the Transfer, when aggregated with all of Grantee’s other Transfers, would cause Grantee to cease to own directly at least one-half of the Transfer Restricted Securities.  Any attempt to Transfer any Transfer Restricted Securities in violation of the foregoing shall be void, and FE shall not record such transfer on its books or treat any purported transferee of the Transfer Restricted Securities as the owner of such shares for any purpose.  The Committee may, however, in its sole discretion waive the foregoing transfer restrictions in whole or in part.  In addition, the Grantee will be permitted to satisfy tax withholding or income tax obligations associated with the Restricted Stock Units as provided for under the Withholding Tax section of this Agreement and any shares sold to satisfy withholding or income tax obligations will not be considered to be Transfer Restricted Securities.

Grantee agrees that FE may maintain custody of the certificate or certificates evidencing the Transfer Restricted Securities until the expiration of Grantee’s employment with FE and its subsidiaries in order to enforce the restrictions provided in this Agreement.  Upon the termination of Grantee’s employment with FE and its subsidiaries for any reason after (or contemporaneous with) termination of the Period of Restriction, the Grantee’s shares will be free of all encumbrances, provided that the Grantee has made the necessary arrangements with FE to satisfy any withholding obligations.

Dividend Equivalents

With respect to the Restricted Stock Units granted pursuant to this Agreement, the Grantee will be credited on the books and records of the Company with an amount per unit (the “Dividend Equivalent”) equal to the amount per share of any cash dividends declared by the Board on the outstanding Common Stock of the Company.  Such Dividend Equivalents will be credited in the form of an additional number of Restricted Stock Units which Restricted Stock Units, from the time of crediting, will be deemed to be in addition to and part of the base number of Restricted Stock Units awarded in Section One for all purposes hereunder,  equal to the aggregate amount of Dividend Equivalents credited on this Award on the respective dividend payment date divided by the average of the high and low price per share of Common Stock on the respective dividend payment date. Until the Period of Restriction lapses or any forfeiture of the Restricted Stock Units occurs pursuant to the terms and conditions described above, the Company will credit, in additional Restricted Stock Units, to the Grantee’s Restricted Stock Unit award, an amount equal to the Dividend Equivalents in the manner set forth above.   The Restricted Stock Units attributable to the Dividend Equivalents will be either delivered or forfeited, as appropriate, under the same terms and conditions under this Agreement that apply to the other Restricted Stock Units.

Shareholder Rights

The Grantee shall have no rights as a shareholder of the Company, including voting rights, with respect to the Restricted Stock Units until the issuance of FE Common Stock upon expiration of the Period of Restriction.

Effect on the Employment Relationship

The Restricted Stock Units granted are voluntary and made on a one-time basis and does not constitute a commitment to make any future awards.  Nothing in this Agreement guarantees employment with the Company or any Subsidiary, nor does it confer any special rights or privileges to the Grantee as to the terms of employment.

Adjustments

In the event of any merger, reorganization, consolidation, recapitalization, separation, liquidation, stock dividend, stock split, combination, distribution, or other change in corporate structure of the Company affecting the Common Stock, the Committee will adjust the number and class of securities granted under this Agreement in a manner determined by the Committee, in its sole discretion, to be appropriate to prevent dilution or enlargement of the Restricted Stock Units granted under this Agreement.

Administration

1. This Agreement is governed by the laws of the State of Ohio without giving effect to the principles of conflicts of laws.

2. The terms and conditions of this Award may be modified by the Committee

         (a) In any case permitted by the terms of the Plan or this Agreement,

         (b) with the written consent of the Grantee, or

         (c) without the consent of the Grantee if the amendment is either not materially adverse to the interests of the Grantee or is necessary or appropriate in the view of the Committee to conform with, or to take into account, applicable law, including either exemption from or compliance with any applicable tax law.

3. The administration of this Agreement and the Plan will be performed in accordance with Article 3 of the Plan.  All determinations and decisions made by the Committee, the Board, or any delegate of the Committee as to the provisions of the Plan shall be final, conclusive, and binding on all persons.

4. The terms of this Agreement are governed at all times by the official text of the Plan and in no way alter or modify the Plan.

5. If a term is capitalized but not defined in this Agreement, it has the meaning given to it in the Plan.

6. To the extent a conflict exists between the terms of this Agreement and the provisions of the Plan, the provisions of the Plan shall govern.

409A

It is intended that this Agreement and the compensation and benefits hereunder either be exempt from, or comply with, Section 409A of the Internal Revenue Code (“Section 409A”), and this Agreement shall be so construed and administered.  In the event that the Company reasonably determines that any compensation or benefits payable under this Agreement may be subject to taxation under Section 409A, the Company, after consultation with the Grantee, shall have the authority to adopt, prospectively or retroactively, such amendments to this Agreement or to take any other actions it determines necessary or appropriate to (a) exempt the compensation and benefits payable under this Agreement from Section 409A or (b) comply with the requirements of Section 409A.  In no event, however, shall this section or any other provisions of this Agreement be construed to require the Company to provide any gross-up for the tax consequences of any provisions of, or payments under, this Agreement and the Company shall have no responsibility for tax consequences to Grantee (or the Grantee’s beneficiary) resulting from the terms or operation of this Agreement.

Notwithstanding any other provision in this Agreement to the contrary, (1) a Grantee shall not be treated as having a termination of employment unless the Grantee would also be treated as having a separation of service for purposes of Section 409A, (2) a Grantee shall not be treated as having a disability unless the Grantee would also be treated as having a disability for purposes of Section 409A.

SECTION THREE - TRANSFER OF AWARD

Neither the Restricted Stock Units nor the right to receive the Common Stock issuable under the Restricted Stock Units are transferable during the life of the Grantee.  Only the Grantee shall have the right to receive the Common Stock issuable under the Restricted Stock Units, unless the Grantee is deceased, at which time the Common Stock issuable under the Restricted Stock Units may be received by the Grantee’s beneficiary (as designated under Article 12 of the Plan) or by will or by the laws of descent and distribution.

FirstEnergy Corp.

By _____________________________

                       Corporate Secretary

I acknowledge receipt of this Restricted Stock Unit Agreement and I accept and agree with the terms and conditions stated above.

      ________________________________

________________                                                      (Signature of Grantee)

          (Date)

EX-10.10

FirstEnergy Corp.

2007 Incentive Compensation Plan

 Performance Share Award

       Performance Share Award No.:

       Grantee:

       Number of Performance Shares Granted: XXXX

       Performance Period:  1/1/2008--12/31/2010

       Performance Share Closing Date:   April [  ], 2008

This Performance Share Award ("Award") to the “Grantee” is effective as of the 1st day of January, 2008, and is not in lieu of salary or any other compensation for services.  For the purposes of this Award, the term "Company" or "FE" means FirstEnergy Corp. or its subsidiaries, singularly or collectively.

SECTION ONE - AWARD

As of the date of this Award, in accordance with the FirstEnergy Corp. 2007 Incentive Compensation Plan (the “Plan”) and the terms and conditions of this Award, the Company grants to the Grantee an award of Performance Shares.  The Performance Shares will be placed into a Performance Share account until paid out or forfeited.

 The Performance Share account of the Grantee will be credited with an amount per unit (the “Dividend Equivalent”) equal to the amount per share of any cash dividends declared by the Board on the outstanding Common Stock of the Company.  Such Dividend Equivalents will be credited in the form of an additional number of Performance Shares (which Performance Shares, from the time of crediting, will be deemed to be in addition to and part of the base number of Performance Shares awarded in Section One for all purposes hereunder). The additional number of Performance Shares will be equal to the aggregate amount of Dividend Equivalents credited on this Award on the respective dividend payment date divided by the average of the high and low price per share of Common Stock on the respective dividend payment date. Until the Performance Period ends pursuant to the terms and conditions described above, the Company will credit, in additional Performance Shares, to the Grantee’s Performance Share award, an amount equal to the Dividend Equivalents in the manner set forth above.  The Performance Shares attributable to the Dividend Equivalents will be either paid out or forfeited, as appropriate, under the same terms and conditions under this Award that apply to the other Performance Shares.

The value of the Grantee’s account at the end of the three-year Performance Period will be based on the average of the high and low prices of FE common stock for the month of December 2010 and may be adjusted upward or downward based upon the total shareholder return (“TSR”) of FE common stock relative to an energy services company index during the same three-year period.  If the TSR rating is at or above the 86th percentile, the payout will be 150% of the account value. If the TSR is at the 50th percentile, the payout will be 100% of the account value. If the TSR is at the 40th percentile, the payout will be 50% of the account value.  Payouts for a ranking above the 40th percentile and below the 86th percentile will be interpolated.  For a TSR ranking below the 40th percentile, no payout will be made.

The payout under this Award will be made between February 15 and March 15, 2011 if the payout is on account of the completion of the Performance Period and satisfaction of  the TSR ranking, as specified above, or, otherwise, on the payment date as specified in Section Two below (all payment dates are referred to as “Payment Date”). The payout will be made in cash; however, the Grantee may elect to defer receipt of any payout under the provisions of the FE Executive Deferred Compensation Plan.  The election shall be made in a manner as required under administrative rules established by the Company and shall be made in a manner that complies with Section 409A of the Internal Revenue Code (“Section 409A”).

SECTION TWO - GENERAL TERMS

Forfeiture

The Grantee shall forfeit all or a portion of the Award and any rights hereunder to receive this Award upon the occurrence of any of the following events before the expiration of the Performance Period:

Event of Grantee	Affect on Award	Further Information	Payment Date
Retirement (including early retirement)	Account balance prorated based on full months of     service during Performance Period.	As defined under 9.5 of the Plan	Between February 15 and March 15, 2011
Disability	Account balance prorated based on full months of service during Performance Period.	As defined under 9.5 of the Plan, except as otherwise provided in 409A below.	As soon as practicable after the Grantee’s Disability.
Death	Account balance prorated based on full months of service during Performance Period.	Payout made to beneficiary (per Article 15 of the Plan or by will or by the laws of descent and distribution)	As soon as practicable after the Grantee’s death.

Termination for Cause	Award immediately forfeited.	Termination for Cause is defined in section 2.7 of the Plan	N/A
Separation from Company in which you qualify for and elect benefits under the  FirstEnergy Severance Plan, if offered	Account balance prorated based on full months of service during Performance Period.	Refer to the Severance Benefits Plan	Between February 15 and March 15, 2011
Other Termination (including resignation)	Award immediately forfeited		N/A
Transfer out of an executive eligible position	Account balance prorated based on full months in an executive eligible position.		Between February 15 and March 15, 2011

Prorated awards will be calculated using the average high and low FE stock price for the month of December 2010 or, in the case of disability or death, a thirty day period prior to the effective date of the events described above and the most recent quarterly TSR factor.

In the event of a Change in Control as defined in the Plan in section 2.8, this award will pay out as soon as practicable under terms determined by the Compensation Committee.

2

Shareholder Rights

The Grantee shall have no rights as a shareholder of the Company, including voting rights, with respect to the Award.

Effect on the Employment Relationship

This Performance Share Award is voluntary and made on a one-time basis and does not constitute a commitment to make any future awards.  Nothing in this Award guarantees employment with the Company or any Subsidiary, nor does it confer any special rights or privileges to the Grantee as to the terms of employment.

Administration

1.   This Award is governed by the laws of the State of Ohio without giving effect to the principles of the conflicts of laws.

2.   The administration of this Award and the Plan will be performed in accordance with Article 3 of the Plan.  All determinations and decisions made by the Committee, the Board, or any delegate of the Committee as to the provisions of the Plan shall be final, conclusive, and binding on all persons.

3.   The terms of this Award are governed at all times by the official text of the Plan and in no way alter or modify the Plan.

4.   If a term is capitalized but not defined in this Award, it has the meaning given to it in the Plan.

5.   To the extent a conflict exists between the terms of this Award and the provisions of the Plan, the provisions of the Plan shall govern.

6.   The terms and conditions of this Award may be modified by the Committee

(a)    In any case permitted by the terms of the Plan or this Award;

(b)    With the written consent of the Grantee; or

(c)    Without the consent of the Grantee if the amendment is either not materially adverse to the interests of the Grantee or is necessary or appropriate in the view of the Committee to conform with, or to take into account, applicable law, including either exemption from or compliance with any applicable tax law.

409A

It is intended that this Award and the compensation and benefits hereunder either be exempt from, or comply with, Section 409A, and this Award shall be so construed and administered.  In the event that the Company reasonably determines that any compensation or benefits payable under this Award may be subject to taxation under Section 409A, the Company, after consultation with the Grantee, shall have the authority to adopt, prospectively or retroactively, such amendments to this Award or to take any other actions it determines necessary or appropriate to (a) exempt the compensation and benefits payable under this Award from Section 409A or (b) comply with the requirements of Section 409A.  In no event, however, shall this section or any other provisions of this Award be construed to require the Company to provide any gross-up for the tax consequences of any provisions of, or payments under, this Award and the Company shall have no responsibility for tax consequences to Grantee (or the Grantee’s beneficiary) resulting from the terms or operation of this Award.

Notwithstanding any other provision in this Award to the contrary, (1) a Grantee shall not be treated as having a termination of employment unless the Grantee would also be treated as having a separation of services for purposes of Section 409A, (2) a Grantee shall not be treated as having a disability unless the Grantee would also be treated as having a disability for purposes of Section 409A.

3

Withholding

The Company shall have the right to deduct, withhold or require the Grantee to surrender a cash amount sufficient to satisfy federal, state and local taxes required by law to be withheld in connection with the benefits under this Award.

SECTION THREE - TRANSFER OF AWARD

This Award is not transferable during the life of the Grantee.  Only the Grantee shall have the right to  receive payout of the Award, unless deceased, at which time the payout may be received by the Grantee's beneficiary (as designated under Article 15 of the Plan) or by will or by the laws of descent and distribution.

I acknowledge receipt of this Performance Share Award and I accept and agree with the terms and conditions stated above.

   ________________________________

(Signature of Grantee)

_____________________

               (Date)

4

EX-12.1

											EXHIBIT 12.1
FIRSTENERGY CORP.
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
		Year Ended December 31,
			2003		2004		2005		2006		2007
		(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	444,166	$	906,753	$	879,053	$	1,257,806	$	1,308,757
Interest and other charges, before reduction for amounts capitalized
	and deferred		841,099		692,068		675,424		727,956		785,539
Provision for income taxes			407,633		680,524		748,794		794,595		883,033
Interest element of rentals charged to income (a)			247,222		248,499		241,460		226,168		206,073
	Earnings as defined	$	1,940,120	$	2,527,844	$	2,544,731	$	3,006,525	$	3,183,402
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred		$	798,730	$	670,655	$	659,886	$	721,068	$	785,539
Subsidiaries’ preferred stock dividend requirements			42,369		21,413		15,538		6,888		-
Adjustments to subsidiaries’ preferred stock dividends
	to state on a pre-income tax basis		21,515		16,071		13,236		4,351		-
Interest element of rentals charged to income (a)			247,222		248,499		241,460		226,168		206,073
	Fixed charges as defined	$	1,109,836	$	956,638	$	930,120	$	958,475	$	991,612
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES			1.75		2.64		2.74		3.14		3.21
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

EX-13.1

ANNUAL REPORT 2007

Contents	Page
Glossary of Terms	i-iii
Selected Financial Data	1-2
Management's Discussion and Analysis	3-60
Management Reports	61
Report of Independent Registered Public Accounting Firm	62
Consolidated Statements of Income	63
Consolidated Balance Sheets	64
Consolidated Statements of Capitalization	65-66
Consolidated Statements of Common Stockholders' Equity	67
Consolidated Statements of Cash Flows	68
Notes to Consolidated Financial Statements	69-111

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
Pennsylvania Companies	Met-Ed, Penelec and Penn
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
TEBSA	Termobarranquilla S.A., Empresa de Servicios Publicos
The following abbreviations and acronyms are used to identify frequently used terms in this report:
AEP	American Electric Power Company, Inc.
ALJ	Administrative Law Judge
AOCL	Accumulated Other Comprehensive Loss
APB	Accounting Principles Board
APB 25	APB Opinion No. 25, "Accounting for Stock Issued to Employees"
APIC	Additional Paid-In Capital
AQC	Air Quality Control
ARB	Accounting Research Bulletin
ARO	Asset Retirement Obligation
BCIDA	Beaver County Industrial Development Authority (Pennsylvania)
BGS	Basic Generation Service
BPJ	Best Professional Judgment
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAT	Commercial Activity Tax
CAVR	Clean Air Visibility Rule
CBP	Competitive Bid Process
CO2	Carbon Dioxide
CTC	Competitive Transition Charge
DCPD	Deferred Compensation Plan for Outside Directors

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GLOSSARY OF TERMS Contd.

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
ECO	Electro-Catalytic Oxidation
EDCP	Executive Deferred Compensation Plan
EEI	Edison Electric Institute
EIS	Energy Independence Strategy
EITF	Emerging Issues Task Force
EITF 06-11	EITF 06-11, "Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards"
EMP	Energy Master Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 39-1	FIN 39-1, "Amendment of FASB Interpretation No. 39"
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
FIN 48	FIN 48, "Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109"
FMB	First Mortgage Bonds
FSP	FASB Staff Position
FSP SFAS 115-1    and SFAS 124-1	FSP SFAS 115-1 and SFAS 124-1, "The Meaning of Other-Than-Temporary Impairment and its     Application to Certain Investments"
FTR	Financial Transmission Rights
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
HVAC	Heating, Ventilation and Air-conditioning
IRS	Internal Revenue Service
ISO	Independent System Operator
kv	Kilovolt
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.
Moodys	Moodys Investors Service, Inc.
MOU	Memorandum of Understanding
MSG	Market Support Generation
MTC	Market Transition Charge
MW	Megawatts
MWH	Megawatt-hour
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
OAQDA	Ohio Air Quality Development Authority
OCA	Office of Consumer Advocate
OCC	Office of the Ohio Consumers' Counsel
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
OVEC	Ohio Valley Electric Corporation

ii

GLOSSARY OF TERMS Contd.

OWDA	Ohio Water Development Authority
PCRB	Pollution Control Revenue Bond
PICA	Penelec Industrial Customer Alliance
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort; an electric utilitys 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
REC	Renewable Energy Certificate
RECB	Regional Expansion Criteria and Benefits
RFP	Request for Proposal
ROP	Reactor Oversight Process
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
RTOR	Regional Through and Out Rates
S&P	Standard & Poors Ratings Service
S&P 500	Standard & Poors Index of Widely Held Common Stocks
SBC	Societal Benefits Charge
SCR	Selective Catalytic Reduction
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
SERP	Supplemental Executive Retirement Plan
SFAS	Statement of Financial Accounting Standards
SFAS 13	SFAS No. 13, "Accounting for Leases"
SFAS 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 87	SFAS No. 87, "Employers' Accounting for Pensions"
SFAS 101	SFAS No. 101, "Accounting for Discontinuation of Application of SFAS 71"
SFAS 106	SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
SFAS 107	SFAS No. 107, "Disclosure about Fair Value of Financial Instruments"
SFAS 109	SFAS No. 109, "Accounting for Income Taxes"
SFAS 115	SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities"
SFAS 123(R)	SFAS No. 123(R), "Share-Based Payment"
SFAS 133	SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities"
SFAS 141(R)	SFAS No. 141(R), "Business Combinations"
SFAS 142	SFAS No. 142, "Goodwill and Other Intangible Assets"
SFAS 143	SFAS No. 143, "Accounting for Asset Retirement Obligations"
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 157	SFAS No. 157, "Fair Value Measurements"
SFAS 158	SFAS No. 158, "Employers Accounting for Defined Benefit Pension and Other Postretirement    Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)"
SFAS 159	SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities Including an    Amendment of FASB Statement No. 115"
SFAS 160	SFAS No. 160, "Non-controlling Interests in Consolidated Financial Statements - an Amemdment of ARB No. 51"
SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
SRM	Special Reliability Master
TBC	Transition Bond Charge
TEBSA	Termobarranquila S.A. Empresa de Servicios Publicos
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
VIE	Variable Interest Entity

iii

The following selected financial data should be read in conjunction with, and is qualified in its entirety by reference to, the sections entitled "Management's Discussion and Analysis of Financial Condition" and Results of Operations and with our consolidated financial statements and the "Notes to Consolidated Financial Statements." Our Consolidated Statements of Income are not necessarily indicative of future conditions or results of operations.

FIRSTENERGY CORP.
SELECTED FINANCIAL DATA
For the Years Ended December 31,	2007		2006		2005		2004		2003
	(In millions, except per share amounts)
Revenues	$	12,802	$	11,501	$	11,358	$	11,600	$	10,802
Income From Continuing Operations	$	1,309	$	1,258	$	879	$	907	$	494
Net Income	$	1,309	$	1,254	$	861	$	878	$	423
Basic Earnings per Share of Common Stock:
Income from continuing operations	$	4.27	$	3.85	$	2.68	$	2.77	$	1.63
Net earnings per basic share	$	4.27	$	3.84	$	2.62	$	2.68	$	1.39
Diluted Earnings per Share of Common Stock:
Income from continuing operations	$	4.22	$	3.82	$	2.67	$	2.76	$	1.62
Net earnings per diluted share	$	4.22	$	3.81	$	2.61	$	2.67	$	1.39
Dividends Declared per Share of Common Stock (1)	$	2.05	$	1.85	$	1.705	$	1.9125	$	1.50
Total Assets	$	32,068	$	31,196	$	31,841	$	31,035	$	32,878
Capitalization as of December 31:
Common Stockholders' Equity	$	8,977	$	9,035	$	9,188	$	8,590	$	8,290
Preferred Stock		-		-		184		335		335
Long-Term Debt and Other Long-Term
Obligations		8,869		8,535		8,155		10,013		9,789
Total Capitalization	$	17,846	$	17,570	$	17,527	$	18,938	$	18,414
Weighted Average Number of Basic
Shares Outstanding		306		324		328		327		304
Weighted Average Number of Diluted
Shares Outstanding		310		327		330		329		305

(1)	Dividends declared in 2007 include three quarterly payments of $0.50 per share in 2007 and one quarterly payment of $0.55 per share payable in
	2008, increasing the indicated annual dividend rate from $2.00 to $2.20 per share. Dividends declared in 2006 include three quarterly payments of
	$0.45 per share in 2006 and one quarterly payment of $0.50 per share paid in 2007. Dividends declared in 2005 include two quarterly payments of
	$0.4125 per share in 2005, one quarterly payment of $0.43 per share in 2005 and one quarterly payment of $0.45 per share in 2006. Dividends
	declared in 2004 include four quarterly dividends of $0.375 per share paid in 2004 and a quarterly dividend of $0.4125 per share paid in 2005.
	Dividends declared in 2003 include four quarterly dividends of $0.375 per share.

PRICE RANGE OF COMMON STOCK

The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol "FE" and is traded on other registered exchanges.

	2007				2006
First Quarter High-Low	$	67.11	$	57.77	$	52.17	$	47.75
Second Quarter High-Low	$	72.90	$	62.56	$	54.57	$	48.23
Third Quarter High-Low	$	68.31	$	58.75	$	57.50	$	53.47
Fourth Quarter High-Low	$	74.98	$	63.39	$	61.70	$	55.99
Yearly High-Low	$	74.98	$	57.77	$	61.70	$	47.75
Prices are from http://finance.yahoo.com.

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SHAREHOLDER RETURN

The following graph shows the total cumulative return from a $100 investment on December 31, 2002 in FirstEnergy's common stock compared with the total cumulative returns of EEI's Index of Investor-Owned Electric Utility Companies and the S&P 500.

HOLDERS OF COMMON STOCK

There were 120,100 and 119,627 holders of 304,835,407 shares of FirstEnergy's common stock as of December 31, 2007 and January 31, 2008, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 11(A) to the consolidated financial statements.

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FIRSTENERGY CORP.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements: This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding our 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 our 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 our 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 our 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 our 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 our 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 our 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. We expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

EXECUTIVE SUMMARY

Net income in 2007 was $1.31 billion, or basic earnings of $4.27 per share of common stock ($4.22 diluted), compared with net income of $1.25 billion, or basic earnings of $3.84 per share ($3.81 diluted) in 2006 and $861 million, or basic earnings of $2.62 per share ($2.61 diluted) in 2005. The increase in our 2007 earnings was driven primarily by increased electric sales revenues, partially offset by increased purchased power costs, increased other operating expenses and higher amortization of regulatory assets.

Change in Basic Earnings Per Share From Prior Year	2007			2006			2005
Basic Earnings Per Share - Prior Year	$	3.84		$	2.62		$	2.68
Non-core asset sales - 2007		0.04			-			-
Saxton decommissioning regulatory asset - 2007		0.05			-			-
Trust securities impairment - 2007/2006		(0.03	)		(0.02	)		-
PPUC NUG accounting adjustment - 2006		0.02			(0.02	)		-
Ohio/New Jersey income tax adjustments - 2005		-			0.19			(0.19	)
Sammis Plant New Source Review settlement - 2005		-			0.04			(0.04	)
Davis-Besse fine/penalty - 2005		-			0.10			(0.10	)
JCP&L arbitration decision - 2005		-			0.03			(0.03	)
New regulatory assets - JCP&L settlement - 2005		-			(0.05	)		0.05
Lawsuits settlements - 2004		-			-			0.03
Nuclear operations severance costs - 2004		-			-			0.01
Davis-Besse extended outage impacts - 2004		-			-			0.12
Discontinued Operations:
Non-core asset sales/impairments		-			(0.02	)		0.21
Other		0.01			(0.02	)		(0.09	)
Cumulative effect of a change in accounting principle		-			0.09			(0.09	)
Revenues		2.51			0.26			(0.44	)
Fuel and purchased power		(1.51	)		(0.43	)		0.72
Amortization of regulatory assets		(0.31	)		0.78			(0.21	)
Deferral of new regulatory assets		-			0.23			0.22
Other expenses		(0.43	)		0.25			(0.27	)
Investment income		(0.03	)		(0.11	)		0.02
Interest expense		(0.11	)		(0.11	)		0.02
Reduced common shares outstanding		0.22			0.03			-
Basic Earnings Per Share	$	4.27		$	3.84		$	2.62

3

Total electric generation sales increased 2.5% during 2007 compared to the prior year, with retail and wholesale sales increasing 2.0%, and 4.5%, respectively. Electric distribution deliveries increased 2.6% in 2007 compared to 2006, reflecting load growth and higher weather-related usage in 2007.

Financial Matters

Dividends

On December 18, 2007, our Board of Directors declared a quarterly dividend of $0.55 per share on outstanding common stock, a 10% increase, payable on March 1, 2008. The new indicated annual dividend is $2.20 per share. This action brings our cumulative dividend increase to 47% since the beginning of 2005 and is consistent with our policy of sustainable annual dividend growth with a payout that is appropriate for our level of earnings.

Share Repurchase Programs

On March 2, 2007, we repurchased approximately 14.4 million shares, or 4.5%, of our outstanding common stock under an accelerated share repurchase program at an initial purchase price of approximately $900 million, or $62.63 per share. We paid a final purchase price adjustment in cash on December 13, 2007, resulting in a final purchase price of $942 million, or $65.54 per share.

On August 10, 2006, we repurchased approximately 10.6 million shares, or 3.2%, of our outstanding common stock through an accelerated share repurchase program. The initial purchase price was $600 million, or $56.44 per share. We paid a final purchase price adjustment of $27 million in cash on April 2, 2007. Under the two programs, we have repurchased approximately 25 million shares, or 8%, of the total common shares that were outstanding in July 2006.

Sale and Leaseback Transaction

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

Credit Rating Agency Action

On March 26, 2007, S&P assigned its corporate credit rating of BBB to FES and on March 27, 2007, Moodys issued a rating of Baa2 to FES. FES is the holding company of FGCO and NGC, the owners of our fossil and nuclear generation assets, respectively.  Both S&P and Moody's cited the strength of our generation portfolio as a key contributor to the investment grade credit ratings.

On October 18, 2007, S&P revised their outlook for us and our subsidiaries to negative from stable, citing the exposure of our generating assets in Ohio and Pennsylvania to market commodity risk.

On November 2, 2007, Moody's revised their outlook for us and our subsidiaries to stable from positive, citing a downward trend in financial metrics, our near-term capital expenditure program and increased regulatory uncertainty.

Extension and Amendment of Credit Facility

On November 20, 2007, we and certain of our subsidiaries, agreed, pursuant to a Consent and Amendment with the lenders under our $2.75 billion credit facility dated as of August 24, 2006, to extend the termination date of the facility for one year to August 24, 2012. We also agreed to amendments that will permit us to request an unlimited number of additional one-year extensions of the facility termination date upon shorter notice than provided by the original facility terms, which permitted only two such extensions. In addition, the amendments increase FES' borrowing sub-limit under the credit facility to up to $1 billion and remove any requirements for the delivery of a parental guaranty of FES' obligations.

New Financings

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

4

On May 21, 2007, JCP&L issued $550 million of senior unsecured debt securities. The offering was in two tranches, consisting of $250 million of 5.65% senior notes due 2017 and $300 million of 6.15% senior notes due 2037. The proceeds from the transaction were used to redeem all of JCP&Ls outstanding FMBs, repay short-term debt and repurchase JCP&Ls common stock from FirstEnergy.

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

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

Regulatory Matters - Ohio

Legislative Process

On September 25, 2007, the Ohio Governors proposed energy plan was officially introduced into the Ohio Senate as Senate Bill 221. The bill proposed to revise state energy policy to address electric generation pricing after 2008, establish advanced energy portfolio standards and energy efficiency standards, and create GHG emission reporting and carbon control planning requirements. The bill also proposed to move to a hybrid system for determining generation 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. On October 4, 2007, we provided testimony to the Committee citing several concerns with the introduced version of the bill, including its lack of context in which to establish prices. We recommended that the PUCO be provided the clear statutory authority to negotiate rate plans, and in the event that negotiations do not result in rate plan agreements, a competitive bidding process be utilized to establish generation prices for customers that do not choose alternative suppliers.  We also proposed that the PUCOs statutory authority be expanded to promote societal programs such as energy efficiency, demand response, renewable power, and infrastructure improvements. Several proposed amendments to the bill were submitted, including those from Ohios investor-owned electric utilities. On October 25, 2007, a substitute version of the bill, which incorporated certain of the proposed amendments, was introduced into the Senate Energy & Public Utilities Committee.  On October 31, 2007, the Ohio Senate passed Substitute Senate Bill 221.  Among other things, the bill outlines a process for establishing electricity generation prices beginning in 2009, and includes a requirement that at least 25% of the states electricity come from advanced energy technologies by 2025, with at least one-half of that amount coming from renewable resources.

In November 2007, the Ohio House of Representatives referred the bill to the House Public Utilities Committee, which has since conducted various topic-based hearings on the bill. Testimony has been received from interested parties, including the Chairman of the PUCO, consumer groups, utility executives and others. On November 14, 2007, we provided testimony on the history and status of deregulation in Ohio. We said that Ohioans should have the opportunity to participate in the competitive electricity marketplace as provided for under Ohio's 1999 deregulation law, Senate Bill 3, which set the stage for long-term price moderation as well as more reliable and responsive service for Ohio's customers. On November 28, 2007, we provided further testimony expressing the industrys concerns with Substitute Senate Bill 221. We said the legislation should be modified to provide the PUCO with expanded regulatory tools and statutory authority to negotiate rate plans, and to include a true market rate option. At this time, we cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on our operations.

Distribution Rate Request

On June 7, 2007, the Ohio Companies filed their base distribution rate increase request and supporting testimony with the PUCO.  The requested increase of approximately $332 million in annualized distribution revenues (updated on August 6, 2007) is needed to recover expenses related to distribution operations and the costs deferred under previously approved rate plans. The new rates would become effective with the first billing cycle in January 2009 for OE and TE, and approximately May 2009 for CEI.  Concurrent with the effective dates of the proposed distribution rate increases, the Ohio Companies will reduce or eliminate their RTC revenues, resulting in an estimated net reduction of $262 million on the regulated portion of customers bills.

5

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, compared to the Ohio Companies' request of $332 million. 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 were commenced 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. The PUCO is expected to render its decision during the second or third quarter of 2008.

Generation Supply Proposal

On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009.  The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour included in rates would reflect an average of the prices resulting from all successful bid sessions. 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 utilitys total load notwithstanding the customers classification. The proposal also provides the PUCO with the option to phase in generation price increases for any residential tariff group if the outcome of a bid would otherwise result in an increase in average total price of 15% or more.  On August 16, 2007, the PUCO held a technical conference for interested parties to gain a better understanding of the proposal.  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.

RCP Fuel Remand

On August 29, 2007, the Supreme Court of Ohio upheld findings by the PUCO, approving several provisions of the Ohio Companies' RCP. The Court, however, remanded back to the PUCO for further consideration the portion of the PUCO's RCP order that authorized the Ohio Companies to collect deferred fuel costs through future distribution rates. The Court found recovery of competitive generation service costs through noncompetitive distribution rates unlawful. The PUCO's order had authorized the Ohio Companies to defer increased fuel costs incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances, and to recover these deferred costs over a 25-year period beginning in 2009. On September 7, 2007, the Ohio Companies filed a Motion for Reconsideration with the Court on the issue of the deferred fuel costs, which the Court later denied on November 21, 2007.  On September 10, 2007, the Ohio Companies filed an Application on remand with the PUCO proposing that the increased fuel costs be recovered through two generation-related fuel cost recovery riders during the period of October 2007 through December 2008.  On January 9, 2008 the PUCO approved the Ohio Companies' proposed fuel cost rider to recover fuel costs incurred from January 1, 2008 through December 31, 2008, which is expected to be approximately $167 million. The fuel cost rider was 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 5 to 25 years. This second application is pending before the PUCO.

Renewable Energy Option

On August 15, 2007, the PUCO approved a stipulation filed by the Ohio Companies, PUCO Staff and the OCC that creates a green pricing option for customers of the Ohio Companies. The Green Resource Program enables customers to support the development of alternative energy resources through their voluntary participation in this alternative to the Ohio Companies' standard service offer for generation supply. The Green Resource Program provides for the Ohio Companies to purchase RECs at prices determined through a competitive bidding process monitored by the PUCO.

Regulatory Matters - Pennsylvania

Legislative Process

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, are 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.

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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 companys transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long-term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The final form of any legislation arising from the special legislative session is uncertain. Consequently, we are unable to predict what impact, if any, such legislation may have on our operations.

Penns Interim Default Service Supply

On May 2, 2007, Penn made a filing with the PPUC proposing how it will procure the power supply needed for default service customers beginning June 1, 2008.  Penns customers transitioned to a fully competitive market on January 1, 2007, and the default service plan that the PPUC previously approved covered a 17-month period through May 31, 2008. The filing proposed that Penn procure a full-requirements product, by customer class, through multiple RFPs with staggered delivery periods extending through May 2011.  It also proposed a 3-year phase-out of promotional generation rates.

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 further proceedings. 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 is expected to be presented to the PPUC for its consideration by March 13, 2008.

Commonwealth Court Appeal

On January 11, 2007, the PPUC issued its order in the Met-Ed and Penelec 2006 comprehensive transition rate cases (see Note 10(C)). Met-Ed and Penelec subsequently appealed the PPUCs decision on the denial of generation rate relief and on a consolidated income tax adjustment related to the cost of capital to the Pennsylvania Commonwealth Court, while other parties appealed the PPUCs decision on transmission rate relief to that court. Initial briefs in the appeals were filed on June 19, 2007. Responsive briefs and reply briefs were filed on September 21, 2007 and October 5, 2007, respectively. Oral arguments are expected to take place in early 2008.

Generation

Our generating fleet produced 81.0 billion KWH during 2007 compared to 82.0 billion KWH in 2006. Our nuclear fleet produced a record 30.3 billion KWH, while the non-nuclear fleet produced 50.7 billion KWH.

During 2007, generation capacity at several of our units increased as a result of work completed in connection with outages for refueling or other maintenance. These capacity additions were achieved in support of our operating strategy to maximize existing generation assets. The resulting increases in the net demonstrated capacity of our generating units are summarized below:

2007 Power Uprates (MW)
Fossil:
Bruce Mansfield Unit 3	30
Seneca Unit 2	8
	38
Nuclear:
Beaver Valley Unit 1	43
Beaver Valley Unit 2	24
	67
Total	105

Our supply portfolio was also enhanced during the year through the reduction of seasonal derates by 149 MW at our peaking units and through long-term contracts to purchase the output of 115 MW from wind generators.

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Complementing our strategy of incremental enhancements to our current generating fleet, FGCO identified an opportunity to acquire a partially completed 707-MW natural gas fired generating plant in Fremont, Ohio. On January 28, 2008, FGCO entered into definitive agreements with Calpine Corporation to acquire the plant for $253.6 million, following a competitive bid process. The facility includes two combined-cycle combustion turbines and a steam turbine which are expected to be capable of producing approximately 544 MW of load-following capacity and 163 MW of peaking capacity. In court documents, Calpine has estimated that the plant is 70% complete and could become operational within 12 to 18 months. Based on those documents, FGCO estimates that the additional expenditures to complete the facility to be approximately $150 million to $200 million. The final cost and timeframe for construction are subject to FGCOs pending engineering study.

Environmental Update

In February 2007, a SNCR system was placed in-service at Unit 5 of FGCOs Eastlake Plant, upon completion of a scheduled maintenance outage. The SNCR installation is part of our overall Air Quality Compliance Strategy and was required under the NSR Consent Decree. The SNCR system is expected to reduce NOx emissions and help achieve reductions required by the EPAs NOx Transport Rule.

On May 30, 2007, we announced that FGCO plans to install an ECO system on Units 4 and 5 of the R.E. Burger Plant.  Design engineering for the new Burger Plant ECO system began in 2007 with anticipated start-up in the first quarter of 2011. 

Perry Nuclear Power Plant

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 June 29, 2007, the Perry Plant began an unplanned outage to replace a 30-ton motor in the reactor recirculation system.  In addition to the motor replacement, routine and preventive maintenance and several system inspections were performed during the outage to assure continued safe and reliable operation of the plant. On July 25, 2007, the plant was returned to service.

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

Beaver Valley Power Station

On October 24, 2007, Beaver Valley Unit 1 returned to service following completion of its scheduled refueling outage that began on September 24, 2007.  During the outage, the ten-year in-service inspection of the reactor vessel was also completed with no significant issues identified. Beaver Valley Unit 1 had operated for 378 consecutive days when it was taken off line for the outage.

In August 2007, FENOC filed applications with the NRC seeking renewal of the operating licenses for Beaver Valley Units 1 and 2 for an additional 20 years, which would extend the operating licenses to January 29, 2036, for Unit 1 and May 27, 2047, for Unit 2. On November 9, 2007, FENOC announced that the NRCs preliminary requirements to extend the licenses had been met. The NRC held a public meeting on November 27, 2007 to discuss the license renewal. Over the next two years, the NRC will conduct audits and an environmental survey. A decision on the applications is expected in the third quarter of 2009.

Davis-Besse Nuclear Power Station

On May 14, 2007, the NRC issued a Demand for Information to FENOC regarding two reports prepared by expert witnesses for an insurance arbitration related to Davis-Besse. On June 13, 2007, FENOC filed a response to the NRCs 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 our other nuclear plants safely and responsibly. In follow-up discussions, FENOC was asked to provide supplemental information to clarify certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRCs Office of Enforcement after it completes the key commitments embodied in the NRCs order. FENOCs compliance with these commitments is subject to future NRC review.

On February 14, 2008, Davis-Besse returned to service following completion of its scheduled refueling outage, which began on December 30, 2007. In addition to replacing 76 of the 177 fuel assemblies, several improvement projects were completed, including rewinding the turbine generator and reinforcing welds on plant equipment.

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FIRSTENERGY'S BUSINESS

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

▪ Energy Delivery Services transmits and distributes electricity through our eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR and default service requirements in Pennsylvania and New Jersey. This business segment derives its revenues principally from the delivery of electricity within our service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service) in its Pennsylvania and New Jersey franchise areas.  Its net income reflects the commodity costs of securing electricity from our competitive energy services segment under partial requirements purchased power agreements with FES and from non-affiliated power suppliers, including, in each case, associated transmission costs.

The service areas of our utilities are summarized below:

Company	Area Served	Customers Served
OE	Central and Northeastern Ohio	1,040,000
Penn	Western Pennsylvania	159,000
CEI	Northeastern Ohio	756,000
TE	Northwestern Ohio	313,000
JCP&L	Northern, Western and East Central New Jersey	1,087,000
Met-Ed	Eastern Pennsylvania	546,000
Penelec	Western Pennsylvania	589,000
ATSI	Service areas of OE, Penn, CEI and TE

▪ Competitive Energy Services supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the PLR and default service requirements of our Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns or leases and operates 19 generating facilities with a net demonstrated capacity of approximately 13,664 MWs and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated company power sales and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission and ancillary costs charged by PJM and MISO to deliver energy to the segment's customers.

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

Other operating segments include HVAC services (divestiture completed in 2006) and telecommunication services. We have substantially completed the divestiture of our non-core businesses (see Note 8 to the consolidated financial statements). The assets and revenues for the other business operations are below the quantifiable threshold for separate disclosure as "reportable operating segments."

STRATEGY AND OUTLOOK

We have developed four primary objectives that support our business fundamentals including improving operating performance, strengthening financial results, enhancing shareholder value and ensuring a safe work environment. To achieve these goals, we have implemented strategies that are expected to enable us to maximize our performance by successfully managing the transition to competitive generation markets; investing in our transmission and distribution infrastructure to enhance system reliability and customer service; reinvesting in our generating assets for cost-effective growth and environmental improvement; effectively managing commodity supplies and risks; and delivering consistent and predictable financial results.

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Transition to Competitive Generation Markets

2004 to 2006

From 2004 to 2006, our efforts included preparing for competitive generation markets by improving the operational performance of our generating fleet and the reliability of our transmission and distribution system. Key to preparing for market competition for generation was transferring ownership of our generating assets in 2005 from the Ohio Companies and Penn to subsidiaries of FES, our competitive generation subsidiary. With the previous divestiture of generation assets by JCP&L, Met-Ed and Penelec, and JCP&Ls transition to competitive generation markets through the New Jersey BGS auction, we gained experience in producing and acquiring competitively priced electricity for customers while delivering a fair return to shareholders.  We anticipate leveraging this experience when we transition to competitive generation markets in Ohio.

To facilitate a smooth transition to competitive generation markets, we developed and received PUCO approval of a Rate Stabilization Plan (RSP) that was implemented in August 2004. This plan, along with the Rate Certainty Plan (RCP) approved in January 2006, provided Ohio customers with reliable generation supply and price stability through 2008.

We focus our continuing transition to market generation prices in Ohio and Pennsylvania over three periods - 2007 to 2008, 2009 to 2010, and beyond.

2007 to 2008

Effective January 1, 2007, we successfully transitioned Penn to retail rates for generation service derived from a competitive, wholesale power supply procurement process in Pennsylvania. During the year we also completed comprehensive rate cases for Met-Ed and Penelec, which better aligned their distribution and transmission rates to their rate base and costs to serve customers. However, Met-Ed and Penelec were unsuccessful in securing approval for generation rate increases. As a result, FES expects to continue to provide both companies with partial requirements for their PLR and default service load of up to approximately 20 billion KWH at below-market prices through the end of 2010 when their current rate freeze ends. In Ohio, the first distribution rate cases in more than a decade were filed by our Ohio Companies in 2007. However, new rates are not expected to be implemented until 2009.

Our transition to competitive generation markets was supported by continuing strong operational results in 2007 led by generation output of 81 billion KWH. During the year, the net-demonstrated capacity at several of our units was increased by a total of 105 MW through cost-effective unit upgrades. We signed long-term contracts to purchase 115 MW of output from wind generators and made plant improvements that eliminated the impact of 149 MW of seasonal reductions in generating output caused by elevated summer temperature conditions on our peaking units. We also continued to improve transmission and distribution system reliability and customer service.

As we look ahead to 2008, we expect to continue our focus on operational excellence with an emphasis on continuous improvement in our core business to position for success in the next market transition phase. This includes continued investment in projects to increase our generation capacity and energy production capability as well as programs to continue to improve the reliability of our transmission and distribution systems. We also intend to remain actively engaged in shaping the regulatory landscape in Ohio and Pennsylvania, which is discussed in greater detail under Legislative Outlook, Capital Expenditures Outlook and Environmental Outlook below.

With no expected rate increases to offset significantly higher Ohio transition cost amortization expense, coupled with higher depreciation expense and general taxes from increased investments in our energy delivery business and AQC projects as discussed more fully under Environmental Outlook below, we expect 2008 earnings growth to moderate compared to recent years. Expected drivers of 2008 earnings, both positive and negative, are discussed more fully below under Financial Outlook.

2009 to 2010, and Beyond

Under current state law, the default service obligation for the Ohio Companies is scheduled to move to the competitive generation market on January 1, 2009. This is expected to provide our competitive energy services business with an opportunity to capture market-based retail generation rates for the incremental load (approximately 51 billion KWH in 2007) currently sold to the Ohio Companies under existing PSAs at below-market prices to cover default service obligations. We also expect to implement higher distribution rates for our three Ohio Companies in 2009 as a result of rate cases filed in 2007. Transition cost amortization related to the existing rate plans ends for OE and TE on December 31, 2008, and approximately May 2009 for CEI.

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There are two primary factors in 2009 that we expect will adversely impact financial results for 2009 and 2010. The first is declining margins from the RSP and RCP. These plans helped us recover transition costs, but over time the benefit received from those plans will cease. The most significant impact will occur in 2009 when RTC revenues significantly decline and cost deferrals for infrastructure improvements end. These reductions are expected to be partially offset by a substantial decrease in transition cost amortization noted above.

The second factor is the scheduled termination - at the beginning of 2009 - of a favorably priced third-party supply contract serving Met-Ed and Penelec default service customers. Currently, we expect FES will supply an estimated additional 4.5 billion KWH from its supply portfolio under the existing contract with Met-Ed and Penelec. However, because retail generation rates for these two subsidiaries are frozen at a level below current market prices through the end of 2010, FES will incur the related opportunity cost in 2009 and 2010 since it will be unable to sell this power at the higher market prices.

Another major transition period in Pennsylvania will begin in 2011 as the current rate freeze on Met-Ed and Penelecs retail generation rates is expected to end. The companies expect to obtain their power supply from the competitive wholesale market and fully recover their costs through retail rates. Until then, we expect FES will provide approximately 20 billion KWH of below-market priced power to serve Met-Ed and Penelecs load in 2009 and 2010, including the load applicable to the expiring contract referred to above. Beginning in 2011, we expect to redeploy this power to capture the potential upside from market-based generation rates.

We will continue to be actively engaged in the regulatory process in Ohio and Pennsylvania as we strategically manage the transition to competitive generation markets. We also plan to continue our efforts to extract additional production capability from existing generating plants as discussed under Capital Expenditures Outlook below and carefully deploy our cash flow, striving for continuous improvement, while maintaining the strategic flexibility we will need as we move through these transitions.

Legislative Outlook

Efforts are underway by both the executive and legislative branches of government in Ohio and Pennsylvania to introduce new energy legislation. There are multiple issues being considered, including, but not limited to, how the transition to competitive generation markets will occur in each state. See Regulatory Matters Ohio and Regulatory Matters Pennsylvania above.

The major legislative effort in Ohio is centered on the Governors proposed energy plan, which was officially introduced into the Ohio Senate as Senate Bill 221. The bill proposed to revise state energy policy to address electric generation pricing after 2008, establish advanced energy portfolio standards and energy efficiency standards, and create greenhouse gas emission reporting and carbon control planning requirements. The bill also proposed 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 generation market for retail electricity.

We were among the interested parties who have provided testimony on the bill during hearings in both the Ohio Senate and the House.

The House Public Utilities Committee conducted topic-based hearings and public hearings between November 2007 and February 2008.  The House Committee also received testimony on the bills alternative options for establishing electric generation pricing in 2009. The electric utility industry's primary concern is that the current version of the bill does not offer a true hybrid approach because it does not provide the PUCO with adequate statutory authority to continue the success of rate plans or to offer customers the benefits of a competitive generation marketplace.

In Pennsylvania, a number of energy-related legislative proposals have been introduced, including plans to fund the Governors proposed $850 million Energy Independence Fund. As proposed, the Fund would be created through a systems-benefit charge added to customers bills that would support clean energy activities. Legislation was unveiled in February 2007, but failed to pass as part of the state budget. The Governor began a special energy session on September 24, 2007, announcing the identical proposal. On December 12, 2007, the Pennsylvania Senate passed SS SB1, "Alternative Energy Investment Act" which, as amended, would provide $650 million over 10 years in funding to implement the Governors proposal. The bill was referred to the House Environmental Resources and Energy committee where it awaits consideration. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation, demand side management, smart meters and renewable energy.

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Financial Outlook

Our primary financial focus is on:

▪ Delivering consistent financial results,

▪ Maintaining and building our financial strength and flexibility, and

▪ Using our cash flow to benefit investors and maintain or improve our investment-grade ratings.

Positive earnings drivers in 2008 are expected to include:

▪ Incremental growth in distribution sales due to more customers and approximately 1-2% higher electricity use from 2007 levels,

▪ Lower operation and maintenance expenses as a result of fewer scheduled outage days in our generating fleet compared to 2007,

▪ Lower financing costs compared to 2007 when short-term borrowing levels remained high for a significant portion of that year as a result of our interim financing of the approximately $900 million accelerated share repurchase program in March and a $300 million voluntary pension contribution in January. These borrowings were repaid with the proceeds from the $1.3 billion Bruce Mansfield Unit 1 sale and leaseback transaction. Without similar needs for short-term financing in 2008, we expect a decrease in borrowing costs.

▪ On a per share basis, a full year benefit from the reduced number of common shares outstanding resulting from the accelerated share repurchase program executed in March 2007, and

▪ Increased generation output. We expect to generate approximately 85 billion KWH in 2008 compared to 81 billion KWH in 2007 as we continue to focus on excellence in operational performance, including running the plants more efficiently and effectively.

Negative earnings drivers in 2008 are expected to include:

▪ Ohio transition cost amortization expense, a non-cash item, will be approximately $69 million higher under the amortization schedules in our current Ohio rate plans,

▪ Depreciation expenses and property taxes will be higher as we continue to invest capital in our business. These investments include our expenditures for distribution and reliability programs and for our AQC projects, and

▪ Fuel and purchase power expenses will continue to increase.

Net cash from operating activities in 2007 was $1.7 billion which includes a $300 million reduction for the voluntary pension contribution made in January. In 2008, we expect net cash from operations will increase to approximately $2.3 billion.

As we enter 2009, we expect to capture the potential upside from market-based generation rates in Ohio. Beginning at that time, we also should see a decline in AQC-related capital expenditure levels, providing an increase in free cash flow.

A driver for longer-term earnings growth is our effort to improve the utilization and output of our generation fleet. We are also expecting timely recovery of costs and capital investments in our regulated business. We plan to invest approximately $3.7 billion in our regulated energy delivery services business during the 2008-2012 period and to pursue timely recovery of those costs in rates. We also expect rising prices for fuel, purchased power and other operating costs to continue during this period.

Capital Expenditures Outlook

Our capital expenditures forecast for 2008-2012 is approximately $7.6 billion. Approximately $1.3 billion of this relates to AQC projects discussed under Environmental Outlook below. Annual expenditures for this program are expected to peak in 2008, increasing from $386 million in 2007 to $649 million in 2008. AQC expenditures are expected to decline in 2009 to approximately $500 million and by early 2012 we expect the program to be completed.

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With respect to the remainder of our business, we anticipate average annual capital expenditures of approximately $1.2 billion from 2009 through 2012. Distribution and transmission reliability projects average approximately $730 million per year over the next five years. Expenditures for our competitive energy services business are expected to be higher than 2008 levels as a result of capital investments to further increase the output of our existing generating plants and to improve the availability and efficiency of those facilities in the future.

Compared to the construction of new base-load generation assets, we believe our strategy of making incremental additions and operational improvements to our generating fleet to improve output and reliability provides advantages including lower capital costs, reduced technology risk, decreased risk of project cost overruns and an accelerated time to market for the added output. In the near-term, we do not anticipate the need for additional base-load generation. However, we will continue to evaluate opportunities that complement our strategy, such as acquiring the partially completed natural gas fired generating plant in Fremont, Ohio, to enhance our fleet.  See Generation above for more details on the Fremont plant.

Major capital investments planned at our nuclear plants during this time period include approximately $170 million for replacement of the steam generator at Davis-Besse. While this project is not expected to be completed until 2014, fabrication of some equipment is beginning. We also anticipate spending approximately $200 million for planned power uprates at Davis-Besse, Perry and Beaver Valley during this period. Combined, these expenditures represent approximately $370 million of increased capital over a typical maintenance level for nuclear generation during the 2008 to 2012 period.

Projected non-AQC capital spending for 2008 and, on average, for each of the years in the 2009 to 2012 period are:

Projected Non-AQC Capital Spending by Business Unit	2008		2009-2012 Average
	(In millions)
Energy Delivery	$	730	$	730
Nuclear		132		259
Fossil		354		168
Corporate & Other		173		66
Subtotal without AQC	$	1,389	$	1,223

Projected capital expenditures for our AQC plan for each of the years 2008 through 2012, and the change in annual spending, are:

Projected AQC
Capital Spending	2008		2009			2010			2011			2012
	(In millions)
AQC	$	649	$	500		$	156		$	11		$	4
Change from Prior Year		263		(149	)		(344	)		(145	)		(7	)

Environmental Outlook

With respect to compliance with environmental laws and regulations, we believe our generation fleet is well positioned due to substantial investment in pollution control equipment we have already made and will continue to make over the next few years pursuant to our AQC plan. The plan includes projects designed to ensure that all of the facilities in our generation fleet are operated in compliance with all applicable emissions standards and limits, including NOx and SO2. It also fulfills the requirements imposed by the 2005 consent decree that resolved the Sammis NSR litigation. See Environmental Matters below. By 2010, we expect approximately 80% of our generating fleet to have full NOx and SO2 equipment controls and to have decreased our exposure to the volatile emission allowance market.

The following table shows the percentage of our 2007 generating capacity made up of non-emitting and low-emitting generating units, including coal units retrofitted with best available control technology as well as projections for 2010.

	2007			2010*
	Capacity		Fleet	Capacity		Fleet
Fleet Emission Control Status	(MW)		%	(MW)		%
Non-Emitting		4,581	34		4,638	34
Coal Controlled (SO2/NOx-full control)		2,626	19		5,237	38
Natural Gas Peaking		1,283	9		1,283	9
		8,490	62		11,158	81

*Excludes Fremont

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Momentum is building in the United States for some form of greenhouse gas regulation. See Environmental Matters below. We believe that our generation fleet is competitively positioned as we move toward a carbon-constrained world with about 35% of our generation output coming from non-emitting nuclear and hydro power.

While we have relatively low carbon intensity (i.e., CO2 emitted per KWH) due primarily to our non-emitting nuclear fleet, our total CO2 emissions will continue to increase as fossil plant utilization increases. We are involved in the following research and other activities, as part of our GHG compliance strategy:

▪ Pilot testing of CO2 capture and sequestration technology,

▪ Electric Power Research Institutes Coal Fleet for Tomorrow,

▪ Nuclear uprates and license renewals to increase and maintain FES non-emitting nuclear units; and

▪ Participation in the DOEs Midwest Regional Carbon Sequestration Partnership, New Jerseys Clean Energy  Program, and the EPAs Sulfur Hexafluoride Reduction Partnership.

In addition, we will remain actively engaged in the federal and state debate over future environmental requirements and legislation, especially those dealing with potential global climate change. Due to the significant uncertainty as to the final form of any such legislation at both the federal and state levels, it is possible that we would be required to make additional capital expenditures, which could have a material adverse impact on our financial condition and results of operation.

Achieving Our Vision

Our success, in these and other key areas, will help us continue to achieve our vision of being a leading regional energy provider, recognized for operational excellence, outstanding customer service and our commitment to safety; the choice for long-term growth, investment value and financial strength; and a company driven by the leadership, skills, diversity and character of our employees.

RISKS AND CHALLENGES

In executing our strategy, we face a number of industry and enterprise risks and challenges, including:

▪ Risks arising from the reliability of our power plants and transmission and distribution equipment;

▪ Changes in commodity prices could adversely affect our profit margins;

▪ 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;

▪ The use of derivative contracts by us to mitigate risks could result in financial losses that may negatively impact our financial results;

▪ 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;

▪ Nuclear generation involves risks that include uncertainties relating to health and safety, additional capital costs, the adequacy of insurance coverage and nuclear plant decommissioning;

▪ Capital market performance and other changes may decrease the value of decommissioning trust fund, pension fund assets and other trust fundswhich then could require significant additional funding;

▪ We could be subject to higher costs and/or penalties related to mandatory NERC/FERC reliability standards;

▪ 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;

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▪ Disruptions in our fuel supplies could occur, which could adversely affect our ability to operate our generation facilities and impact financial results;

▪ 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;

▪ We are subject to financial performance risks related to the economic cycles of the electric utility industry;

▪ The goodwill of one or more of our operating subsidiaries may become impaired, which would result in write-offs of the impaired amounts;

▪ We face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements;

▪ Significant increases in our operation and maintenance expenses, including our health care and pension costs, could adversely affect our future earnings and liquidity;

▪ 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;

▪ Acts of war or terrorism could negatively impact our business;

▪ Capital improvements and construction projects may not be completed within forecasted budget, schedule or scope parameters;

▪ 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;

▪ Complex and changing government regulations could have a negative impact on our results of operations;

▪ 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;

▪ Our profitability is impacted by our affiliated companies continued authorization to sell power at market-based rates;

▪ There are uncertainties relating to the operations of the PJM and MISO regional transmission organizations (RTOs);

▪ 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;

▪ Availability and cost of emission credits could materially impact our costs of operations;

▪ Mandatory renewable portfolio requirements could negatively affect our costs;

▪ We are and may become subject to legal claims arising from the presence of asbestos or other regulated substances at some of our facilities;

▪ 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;

▪ Interest rates and/or a credit rating downgrade could negatively affect our financing costs and our ability to access capital;

▪ We must rely on cash from our subsidiaries; and

▪ We cannot assure common shareholders that future dividend payments will be made, or if made, in what amounts they may be paid.

15

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among our business segments. A reconciliation of segment financial results is provided in Note 16 to the consolidated financial statements. The divested FSG business segment is included in Other and reconciling adjustments due to its immaterial impact on prior period financial results. Net income (loss) by reportable business segment was as follows:

										Increase (Decrease)
	2007			2006			2005			2007 vs 2006			2006 vs 2005
	(In millions, except per share amounts)
Net Income (Loss)
By Business Segment:
Energy delivery services	$	862		$	893		$	987		$	(31	)	$	(94	)
Competitive energy services		495			393			190			102			203
Ohio transitional generation services		103			112			(73	)		(9	)		185
Other and reconciling adjustments*		(151	)		(144	)		(243	)		(7	)		99
Total	$	1,309		$	1,254		$	861		$	55		$	393
Basic Earnings Per Share:
Income from continuing operations	$	4.27		$	3.85		$	2.68		$	0.42		$	1.17
Discontinued operations		-			(0.01	)		0.03			0.01			(0.04	)
Cumulative effect of a change in accounting principle		-			-			(0.09	)		-			0.09
Basic earnings per share	$	4.27		$	3.84		$	2.62		$	0.43		$	1.22
Diluted Earnings Per Share:
Income from continuing operations	$	4.22		$	3.82		$	2.67		$	0.40		$	1.15
Discontinued operations		-			(0.01	)		0.03			0.01			(0.04	)
Cumulative effect of a change in accounting principle		-			-			(0.09	)		-			0.09
Diluted earnings per share	$	4.22		$	3.81		$	2.61		$	0.41		$	1.20

* Represents other operating segments and reconciling adjustments including interest expense on holding company debt, corporate support services revenues and expenses and the impact of the 2005 Ohio tax legislation.

16

Summary of Results of Operations 2007 Compared with 2006

Financial results for our major business segments in 2007 and 2006 were as follows:

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
2007 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	8,069		$	1,316		$	2,559		$	-		$	11,944
Other		657			152			37			12			858
Internal		-			2,901			-			(2,901	)		-
Total Revenues		8,726			4,369			2,596			(2,889	)		12,802
Expenses:
Fuel and purchased power		3,738			1,937			2,240			(2,901	)		5,014
Other operating expenses		1,700			1,160			305			(79	)		3,086
Provision for depreciation		404			204			-			30			638
Amortization of regulatory assets		991			-			28			-			1,019
Deferral of new regulatory assets		(371	)		-			(153	)		-			(524	)
General taxes		623			107			4			20			754
Total Expenses		7,085			3,408			2,424			(2,930	)		9,987
Operating Income		1,641			961			172			41			2,815
Other Income (Expense):
Investment income		240			16			1			(137	)		120
Interest expense		(456	)		(172	)		(1	)		(146	)		(775	)
Capitalized interest		11			20			-			1			32
Subsidiaries' preferred stock dividends		-			-			-			-			-
Total Other Expense		(205	)		(136	)		-			(282	)		(623	)
Income From Continuing Operations Before
Income Taxes		1,436			825			172			(241	)		2,192
Income taxes		574			330			69			(90	)		883
Income from continuing operations		862			495			103			(151	)		1,309
Discontinued operations		-			-			-			-			-
Net Income (Loss)	$	862		$	495		$	103		$	(151	)	$	1,309

17

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
2006 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	7,039		$	1,266		$	2,366		$	-		$	10,671
Other		584			163			24			59			830
Internal		14			2,609			-			(2,623	)		-
Total Revenues		7,637			4,038			2,390			(2,564	)		11,501
Expenses:
Fuel and purchased power		3,015			1,812			2,050			(2,624	)		4,253
Other operating expenses		1,585			1,138			247			(5	)		2,965
Provision for depreciation		379			190			-			27			596
Amortization of regulatory assets		841			-			20			-			861
Deferral of new regulatory assets		(375	)		-			(125	)		-			(500	)
General taxes		599			90			10			21			720
Total Expenses		6,044			3,230			2,202			(2,581	)		8,895
Operating Income		1,593			808			188			17			2,606
Other Income (Expense):
Investment income		328			35			-			(214	)		149
Interest expense		(431	)		(200	)		(1	)		(89	)		(721	)
Capitalized interest		14			12			-			-			26
Subsidiaries' preferred stock dividends		(16	)		-			-			9			(7	)
Total Other Expense		(105	)		(153	)		(1	)		(294	)		(553	)
Income From Continuing Operations Before
Income Taxes		1,488			655			187			(277	)		2,053
Income taxes		595			262			75			(137	)		795
Income from continuing operations		893			393			112			(140	)		1,258
Discontinued operations		-			-			-			(4	)		(4	)
Net Income (Loss)	$	893		$	393		$	112		$	(144	)	$	1,254
Changes Between 2007 and
2006 Financial Results - Increase (Decrease)
Revenues:
External
Electric	$	1,030		$	50		$	193		$	-		$	1,273
Other		73			(11	)		13			(47	)		28
Internal		(14	)		292			-			(278	)		-
Total Revenues		1,089			331			206			(325	)		1,301
Expenses:
Fuel and purchased power		723			125			190			(277	)		761
Other operating expenses		115			22			58			(74	)		121
Provision for depreciation		25			14			-			3			42
Amortization of regulatory assets		150			-			8			-			158
Deferral of new regulatory assets		4			-			(28	)		-			(24	)
General taxes		24			17			(6	)		(1	)		34
Total Expenses		1,041			178			222			(349	)		1,092
Operating Income		48			153			(16	)		24			209
Other Income (Expense):
Investment income		(88	)		(19	)		1			77			(29	)
Interest expense		(25	)		28			-			(57	)		(54	)
Capitalized interest		(3	)		8			-			1			6
Subsidiaries' preferred stock dividends		16			-			-			(9	)		7
Total Other Income (Expense)		(100	)		17			1			12			(70	)
Income From Continuing Operations Before
Income Taxes		(52	)		170			(15	)		36			139
Income taxes		(21	)		68			(6	)		47			88
Income from continuing operations		(31	)		102			(9	)		(11	)		51
Discontinued operations		-			-			-			4			4
Net Income (Loss)	$	(31	)	$	102		$	(9	)	$	(7	)	$	55

18

Energy Delivery Services 2007 Compared to 2006

Net income decreased $31 million (or 3%) to $862 million in 2007 compared to $893 million in 2006, primarily due to higher expenses, partially offset by increased revenues.

Revenues

The increase in total revenues resulted from the following sources:

Revenues by Type of Service	2007		2006		Increase (Decrease)
	(In millions)
Distribution services	$	3,909	$	3,849	$	60
Generation sales:
Retail		3,145		2,774		371
Wholesale		687		247		440
Total generation sales		3,832		3,021		811
Transmission		785		561		224
Other		200		206		(6	)
Total Revenues	$	8,726	$	7,637	$	1,089

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

Distribution KWH Deliveries
Residential	4.3	%
Commercial	3.7	%
Industrial	(0.2	)%
Net Increase in Distribution KWH Deliveries	2.6	%

The increase in electric distribution deliveries to customers was primarily due to higher weather-related usage during 2007 compared to 2006 (heating degree days increased by 11.2% and cooling degree days increased by 16.7%). The higher revenues from increased distribution deliveries were partially offset by distribution rate decreases of $86 million and $21 million for Met-Ed and Penelec, respectively, as a result of a January 11, 2007 PPUC rate decision (see Regulatory Matters Pennsylvania).

The following table summarizes the price and volume factors contributing to the $811 million increase in generation sales revenues in 2007 compared to 2006:

Sources of Change in Generation Sales Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 1.7% decrease in sales volumes	$	(48	)
Change in prices		419
		371
Wholesale:
Effect of 120% increase in sales volumes		297
Change in prices		143
		440
Net Increase in Generation Sales Revenues	$	811

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

Transmission revenues increased $224 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization for transmission cost recovery. Met-Ed and Penelec defer the difference between revenues received under their transmission rider and transmission costs incurred, with no material effect on current period earnings (see Regulatory Matters Pennsylvania).

19

Expenses

The increases in revenues discussed above were offset by an approximate $1.0 billion increase in expenses due to the following:

▪ Purchased power costs were $723million higher in 2007 due to increases in both unit costs and volumes purchased. The increased unit costs reflected the effect of higher JCP&L costs resulting from the BGS auction process. The increased volumes purchased in 2007 resulted primarily from Met-Eds and Penelecs higher sales to the PJM wholesale market.  The following table summarizes the sources of changes in purchased power costs:

Sources of Change in Purchased Power	Increase
	(In millions)
Purchased Power:
Change due to increased unit costs	$	349
Change due to increased volume		248
Decrease in NUG costs deferred		126
Net Increase in Purchased Power Costs	$	723

▪ Other operating expenses increased $115million primarily due to the net effects of:

- An increase of $101million in MISO and PJM transmission expenses, resulting primarily from higher congestion costs.

- An increase in operation and maintenance expenses of $19million primarily due to increased labor, contractor costs and materials devoted to maintenance projects in 2007.

▪ Amortization of regulatory assets increased $150million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC rates for JCP&L (as discussed above), recovery of deferred non-NUG stranded costs through application of CTC revenues for Met-Ed and higher transition cost amortization for the Ohio companies.

▪ The deferral of new regulatory assets during 2007 was $4 million less in 2007 than in 2006 primarily due to $46 million of lower PJM transmission cost deferrals, partially offset by the deferral of previously expensed decommissioning costs of $27million related to the Saxton nuclear research facility (see Regulatory Matters Pennsylvania) and increased carrying charges earned on the Ohio Companies RCP distribution deferrals of $11 million.

▪ Depreciation expense increased $25 million and general taxes increased $24 million due primarily to property additions since 2006.

▪ Other expenses increased $100million in 2007 compared to 2006 primarily due to lower investment income of $88million resulting from the repayment of notes receivable from affiliates since 2006, and increased interest expense of $25million related to new debt issuances by CEI, JCP&L and Penelec. These increased costs were  partially offset by the absence of $16 million of preferred stock dividends paid in 2006.

Competitive Energy Services 2007 Compared to 2006

Net income for this segment increased $102 million to $495million in 2007 compared to $393million in 2006. This increase reflected an improvement in generation margin (revenues less fuel and purchased power), partially offset by higher operating expenses, depreciation and general taxes.

Revenues

Total revenues increased $331million in 2007 compared to 2006 primarily as a result of higher unit prices for affiliated generation sales to the Ohio Companies and increased retail sales revenues, partially offset by lower non-affiliated wholesale sales revenues.

20

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

The increased affiliated company generation revenues reflected both higher unit prices and increased sales volumes. The increase in PSA sales to the Ohio Companies was due to their higher retail generation sales requirements. Unit prices were higher because rates charged under FES full-requirements PSAs reflect the increases in the Ohio Companies composite retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn due to the implementation of its competitive solicitation process in 2007.

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

					Increase
Revenues by Type of Service	2007		2006		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	712	$	590	$	122
Wholesale		603		676		(73	)
Total Non-Affiliated Generation Sales		1,315		1,266		49
Affiliated Generation Sales		2,901		2,609		292
Transmission		103		120		(17	)
Other		50		43		7
Total Revenues	$	4,369	$	4,038	$	331

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

	Increase
Source of Change in Non-Affiliated Generation Sales	(Decrease)
	(In millions)
Retail:
Effect of 10.8% increase in sales volumes	$	63
Change in prices		59
		122
Wholesale:
Effect of 22.7% decrease in sales volumes		(154	)
Change in prices		81
		(73	)
Net Increase in Non-Affiliated Generation Sales	$	49
Source of Change in Affiliated Generation Sales	Increase
	(In millions)
Ohio Companies:
Effect of 3.4% increase in sales volumes	$	68
Change in prices		118
		186
Pennsylvania Companies:
Effect of 14.9% increase in sales volumes		87
Change in prices		19
		106
Increase in Affiliated Generation Sales	$	292

Transmission revenues decreased $17 million due in part to reduced FTR revenue resulting from fewer FTRs allocated by MISO ($15 million) and PJM ($9 million), partially offset by higher retail transmission revenues of $8 million.

21

           Expenses - -

Total expenses increased $178 million in 2007 compared to 2006 due to the following factors:

▪ Purchased power costs increased $159 million due principally to higher volumes for replacement power related to the forced outages at the Bruce Mansfield and Perry Plants and costs associated with the new capacity market in PJM ($25 million).

▪ Fossil generation operating costs were $66 million higher due to the absence of gains from the sale of emissions allowances recognized in 2006 ($27 million) and increased costs related to scheduled and forced maintenance outages during 2007.

▪ Lease expenses increased $55 million primarily due to intercompany billings associated with the assignment of CEIs and TEs leasehold interests in the Bruce Mansfield Plant to FGCO and the Bruce Mansfield Unit 1 sale and leaseback transaction completed in 2007.

▪ Depreciation expenses were $14 million higher due to property additions since 2006.

▪ General taxes were $17 million higher as a result of increased gross receipts taxes and property taxes.

Partially offsetting the higher costs were:

▪ Fuel costs were $34 million lower primarily due to reduced coal costs and emission allowance costs, offset by increases in nuclear fuel and natural gas costs. Coal costs were reduced due to $38 million of reduced coal consumption reflecting lower generation. Reduced emission allowance costs ($19 million) were partially offset by increased natural gas costs ($7 million) due to increased consumption and nuclear fuel costs ($15 million) due to increased consumption and higher prices.

▪ Nuclear generation operating costs were $72 million lower due to fewer outages in 2007 compared to 2006 and reduced employee benefit costs.

▪ MISO transmission expense decreased by $32 million from 2006 due primarily to a one-time resettlement of costs from generation providers to load serving entities.

▪ Total other expense in 2007 was $17million lower than in 2006 primarily due to lower interest expense, partially offset by decreased earnings on nuclear decommissioning trust investments.

Ohio Transitional Generation Services 2007 Compared to 2006

Net income for this segment decreased to $103million in 2007 from $112 million in 2006. Higher operating expenses, primarily for purchased power, were partially offset by higher generation revenues.

Revenues

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

Revenues by Type of Service	2007		2006		Increase (Decrease)
	(In millions)
Generation sales:
Retail	$	2,248	$	2,095	$	153
Wholesale		7		13		(6	)
Total generation sales		2,255		2,108		147
Transmission		333		280		53
Other		8		2		6
Total Revenues	$	2,596	$	2,390	$	206

22

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

Source of Change in Generation Sales Revenues	Increase
	(In millions)
Retail:
Effect of 3.9% increase in sales volumes	$	82
Change in prices		71
Total Increase in Retail Generation Sales Revenues	$	153

The increase in generation sales was primarily due to higher weather-related usage in 2007 compared to 2006 and reduced customer shopping in Ohio. The percentage of generation services provided by alternative suppliers to total sales delivered by the Ohio Companies in their service areas decreased by 5.9 percentage points from 2006. Average prices increased primarily due to higher composite unit prices for returning customers.

Increased transmission revenues resulted from higher sales volumes and a PUCO-approved transmission tariff increase, which became effective July 1, 2007.

Expenses -

Purchased power costs were $190 million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power	Increase
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	-
Change due to volume purchased		4
		4
Purchases from FES:
Change due to increased unit costs		114
Change due to volume purchased		72
		186
Total Increase in Purchased Power Costs	$	190

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

Other operating expenses increased $58 million primarily due to MISO transmission-related expenses. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.

Other 2007 Compared to 2006

Our financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $7 million decrease in our net income in 2007 compared to 2006. The decrease includes the net effect of the sale of our interest in First Communications ($13 million, net of taxes), the absence of subsidiaries' preferred stock dividends in 2007 ($9 million) and the absence of a $4 million loss included in 2006 results from discontinued operations (see Note 8).

23

Summary of Results of Operations 2006 Compared with 2005

Financial results for our major business segments in 2005 were as follows:

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
2005 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	7,582		$	1,410		$	1,554		$	-		$	10,546
Other		583			140			14			75			812
Internal		33			2,425			-			(2,458	)		-
Total Revenues		8,198			3,975			1,568			(2,383	)		11,358
Expenses:
Fuel and purchased power		2,857			2,100			1,513			(2,458	)		4,012
Other operating expenses		1,600			1,177			248			77			3,102
Provision for depreciation		374			187			-			27			588
Amortization of regulatory assets		1,281			-			-			-			1,281
Deferral of new regulatory assets		(314	)		-			(91	)		-			(405	)
General taxes		607			68			19			19			713
Total Expenses		6,405			3,532			1,689			(2,335	)		9,291
Operating Income		1,793			443			(121	)		(48	)		2,067
Other Income (Expense):
Investment income		262			79			-			(124	)		217
Interest expense		(364	)		(205	)		(1	)		(89	)		(659	)
Capitalized interest		5			14			-			-			19
Subsidiaries' preferred stock dividends		(16	)		-			-			-			(16	)
Total Other Expense		(113	)		(112	)		(1	)		(213	)		(439	)
Income From Continuing Operations Before
Income Taxes		1,680			331			(122	)		(261	)		1,628
Income taxes		672			132			(49	)		(6	)		749
Income from continuing operations		1,008			199			(73	)		(255	)		879
Discontinued operations		-			-			-			12			12
Cumulative effect of a change in accounting principle		(21	)		(9	)		-			-			(30	)
Net Income (Loss)	$	987		$	190		$	(73	)	$	(243	)	$	861
Changes Between 2006 and
2005 Financial Results - Increase (Decrease)
Revenues:
External
Electric	$	(543	)	$	(144	)	$	812		$	-		$	125
Other		1			23			10			(16	)		18
Internal		(19	)		184			-			(165	)		-
Total Revenues		(561	)		63			822			(181	)		143
Expenses:
Fuel and purchased power		158			(288	)		537			(166	)		241
Other operating expenses		(15	)		(39	)		(1	)		(82	)		(137	)
Provision for depreciation		5			3			-			-			8
Amortization of regulatory assets		(440	)		-			20			-			(420	)
Deferral of new regulatory assets		(61	)		-			(34	)		-			(95	)
General taxes		(8	)		22			(9	)		2			7
Total Expenses		(361	)		(302	)		513			(246	)		(396	)
Operating Income		(200	)		365			309			65			539
Other Income (Expense):
Investment income		66			(44	)		-			(90	)		(68	)
Interest expense		(67	)		5			-			-			(62	)
Capitalized interest		9			(2	)		-			-			7
Subsidiaries' preferred stock dividends		-			-			-			9			9
Total Other Income (Expense)		8			(41	)		-			(81	)		(114	)
Income From Continuing Operations Before
Income Taxes		(192	)		324			309			(16	)		425
Income taxes		(77	)		130			124			(131	)		46
Income from continuing operations		(115	)		194			185			115			379
Discontinued operations		-			-			-			(16	)		(16	)
Cumulative effect of a change in accounting principle		21			9			-			-			30
Net Income (Loss)	$	(94	)	$	203		$	185		$	99		$	393

24

      Energy Delivery Services 2006 Compared with 2005

Net income decreased $94 million (or 10%) to $893 million in 2006 compared to $987 million in 2005, primarily due to decreased revenues and increased purchased power costs partially offset by lower amortization of regulatory assets and increased deferral of new regulatory assets.

Revenues

The decrease in total revenues resulted from the following sources:

					Increase
Revenues By Type of Service	2006		2005		(Decrease)
	(In millions)
Distribution services	$	3,850	$	4,582	$	(732	)
Generation sales:
Retail		2,774		2,514		260
Wholesale		247		318		(71	)
Total generation sales		3,021		2,832		189
Transmission		560		574		(14	)
Other		206		210		(4	)
Total Revenues	$	7,637	$	8,198	$	(561	)

Decreases in distribution deliveries by customer class are summarized in the following table:

Distribution KWH Deliveries
Residential	(3.9	)%
Commercial	(1.4	)%
Industrial	(1.4	)%
Total Distribution KWH Deliveries	(2.3	)%

The completion of our Ohio Companies' and Penns generation transition cost recovery under their respective transition plans in 2005 were the primary reasons for the decrease in distribution unit prices, which, in conjunction with lower KWH deliveries, resulted in lower distribution delivery revenues. These reductions were partially offset by the elimination of customer shopping incentives in 2006 in Ohio. The costs of these incentives (reported as a reduction to revenues) were deferred for future recovery under our transition plans and did not affect earnings. The decreases in deliveries to customers were primarily due to milder weather during 2006 as compared to 2005. The following table summarizes major factors producing the $732 million decrease in distribution service revenues in 2006 compared to 2005:

Sources of Change in Distribution Revenues	Increase (Decrease)
	(In millions)
Changes in customer usage	$	(221	)
Ohio shopping incentives		222
Reduced Ohio transition rates		(817	)
Other		84
Net Decrease in Distribution Revenues	$	(732	)

The following table summarizes the price and volume factors contributing to the $189 million increase in generation sales in 2006 compared to 2005:

Sources of Change in Generation Sales Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 0.2% increase in customer usage	$	4
Change in prices		256
		260
Wholesale:
Effect of 0.8% decrease in sales		(3	)
Change in prices		(68	)
		(71	)
Net Increase in Generation Sales Revenues	$	189

25

Higher retail prices in 2006 compared to 2005 resulted from increased generation rates for JCP&L from the New Jersey BGS auction.

Expenses

The net decreases in revenues discussed above were partially offset by a $361 million decrease in expenses due to the following:

▪ Purchased power costs were $163 million higher in 2006 due to higher unit prices partially offset by a 1.1% decrease in volumes purchased. The increased unit prices primarily reflected the effect of higher JCP&L purchased power unit prices resulting from the BGS auction. The decrease in volumes purchased in 2006 was principally due to lower generation sales requirements in the JCP&L service area.  The following table summarizes the sources of changes in purchased power costs:

Sources of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchased Power:
Change due to increased unit costs	$	222
Change due to decreased volume		(34	)
Decrease in NUG costs deferred		(25	)
Net Increase in Purchased Power Costs	$	163

▪ Other operating expenses were $15 million lower in 2006 due, in part, to the following factors:

- The absence in 2006 of expenses for refunds to third-party providers of ancillary services as a result of the implementation of the Ohio Companies' RCP in 2006. Under the RCP, third-party suppliers of ancillary services now bill customers directly for those services. In 2005, ancillary service refund expense was $27 million; and

- A $52 million decrease in employee and contractor costs resulting from lower storm-related expenses and the decreased use of outside contractors for tree trimming, reliability work, legal services and jobbing and contracting; offset by

- A $58 million increase in other expenses due, in part, to increased corporate support service costs of $19 million, a $32 million increase in material and supplies costs applicable to operating and maintenance activities in 2006 and the absence in 2006 of a $9 million insurance settlement received in 2005.

▪ Depreciation expense was $5 million higher resulting principally from increased depreciable property additions;

▪ Amortization of regulatory assets decreased $440 million resulting from the completion of Ohio generation transition cost recovery and Penn's transition plan in 2005;

▪ Deferral of new regulatory assets increased $61 million due to the distribution cost deferrals authorized under the Ohio Companies' RCP, and PJM costs incurred that will be recovered from customers through future rates, partially offset by the completion of shopping incentive deferrals under the Ohio Companies' transition plan and the absence of new regulatory assets resulting from the 2005 rate decision for JCP&L;

▪ General taxes decreased by $8 million primarily due to lower property taxes; and

▪ Other expense decreased $8 million in 2006 compared to 2005 due to increased investment income and capitalized interest, partially offset by increased interest expense resulting primarily from the Ohio Companies' 2006 long-term debt issuances.

Competitive Energy Services 2006 Compared with 2005

Net income for this segment increased $203 million to $393 million in 2006 compared to $190 million in 2005. An improvement in generation margin (revenues less fuel and purchased power) and lower operating expenses was partially offset by higher general taxes and reduced investment income.

26

Revenues

Revenues increased by $63 million in 2006 compared to the prior year due to increases in generation sales to affiliates which were partially offset by decreased non-affiliated generation sales. Affiliated generation sales to the Ohio Companies through PSA arrangements increased by $517 million primarily as a result of higher unit prices. Unit prices were higher because rates charged under FES' full-requirements PSAs reflect the increases in the Ohio Companies' composite retail generation rates. The PSA revenue increase also reflected a 4.9% increase in sales resulting from the Ohio Companies higher retail generation sales requirements. The higher PSA sales revenues from the Ohio Companies were partially offset by a $333 million decrease in generation sales to Pennsylvania and New Jersey affiliates. This decrease was due to a 41.4% decrease in sales volumes, partially offset by higher unit prices. The lower sales were due to lower contractual sales requirements from FES to its PJM market affiliates and decreased generation sales requirements in the JCP&L service area in 2006 compared to 2005.

Non-affiliated generation sales revenues decreased in both the retail and wholesale markets in 2006 compared to 2005. The lower retail sales revenues were due to a 17.3% decrease in customer usage, partially offset by higher unit prices. The lower sales reflected a decrease in the shopping customers FES was serving as those customers returned to the Ohio Companies for their generation requirements. Our record generation output in 2006 allowed for a 9.3% increase in wholesale sales as compared to 2005. However, these sales increases were more than offset by lower unit prices in the wholesale market, resulting in a $79 million decrease in wholesale revenues in 2006.

Transmission revenues increased $43 million in 2006 compared to 2005 due primarily to higher transmission volumes.

Changes in revenues in 2006 from the prior year are summarized in the following table:

					Increase
Revenues By Type of Service	2006		2005		(Decrease)
	(In millions)
Non-affiliated generation sales:
Retail	$	590	$	656	$	(66	)
Wholesale		676		755		(79	)
Total non-affiliated generation sales		1,266		1,411		(145	)
Affiliated generation sales		2,609		2,425		184
Transmission		120		77		43
Other		43		62		(19	)
Total Revenues	$	4,038	$	3,975	$	63

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

	Increase
Source of Change in Non-Affiliated Generation Sales	(Decrease)
	(In millions)
Retail:
Effect of 17.3% decrease in customer usage	$	(114	)
Change in prices		48
		(66	)
Wholesale:
Effect of 9.3% increase in sales		70
Change in prices		(149	)
		(79	)
Net Decrease in Non-Affiliated Generation Sales	$	(145	)
	Increase
Source of Change in Affiliated Generation Sales	(Decrease)
	(In millions)
Ohio Companies:
Effect of 4.9% increase in sales	$	74
Change in prices		443
		517
Pennsylvania and New Jersey affiliates:
Effect of 41.4% decrease in sales		(379	)
Change in prices		46
		(333	)
Net Increase in Affiliated Generation Sales	$	184

27

Expenses -

Total expenses decreased by $302 million in 2006 compared to 2005. The decrease was primarily due to lower purchased power costs, partially offset by higher fuel costs.

The following table summarizes the factors contributing to the changes in fuel and purchased power costs.

	Increase
Source of Change in Fuel and Purchased Power	(Decrease)
	(In millions)
Fuel:
Change due to increased composite unit costs	$	75
Change due to volume consumed		24
		99
Purchased Power:
Change due to increased unit costs		54
Change due to volume purchased		(441	)
		(387	)
Net Decrease in Fuel and Purchased Power Costs	$	(288	)

The net decrease in expenses was due to the following factors:

▪ Lower purchased power costs as a result of decreased KWH purchases, partially offset by increased unit costs.  KWH purchases in 2006 were 45% lower than 2005 due to reduced generation sales requirements to affiliates in the PJM market and increased power available from our owned generation facilities;

▪ Lower transmission expenses and credits from the sale of emission allowances. The decrease in transmission expenses was due to lower PJM congestion and ancillary charges, reflecting the lower sales to affiliates in PJM discussed above, and lower MISO transmission expenses; and

▪ The absence in 2006 of the 2005 accruals of (1) $8.5 million for a civil penalty related to the Sammis Plant; (2) $10 million for obligations to fund environmentally beneficial projects in connection with the Sammis NSR settlement; and (3) $31.5 million for a civil penalty related to the extended Davis-Besse outage.

The above decreases were partially offset by:

▪ Higher fuel costs of $99 million resulting from our generation fleets record output in 2006. Fossil fuel costs increased $97 million as a result of increased generation output, higher coal prices and increased transportation costs for western coal. The increased coal costs were partially offset by lower natural gas and emission allowance costs.  Nuclear fuel costs were higher by $2 million in 2006 compared to the prior year principally due to higher unit prices;

▪ An increase in nuclear operating expenses of $55 million due to three refueling outages in 2006 compared with two refueling outages in 2005;

▪ Increased depreciation expenses of $3 million as a result of property additions; and

▪ Higher general taxes of $22 million reflecting increased property taxes.

Other Income

Investment income in 2006 was $44 million lower than in 2005 primarily due to decreased earnings on nuclear decommissioning trust investments.

Ohio Transitional Generation Services 2006 Compared with 2005

Net income for this segment increased $185 million to $112 million in 2006 compared to a loss of $73 million in 2005. Higher retail generation revenues in 2006 were partially offset by higher operating expenses, primarily for purchased power.

28

Revenues

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

					Increase
Revenues By Type of Service	2006		2005		(Decrease)
	(In millions)
Generation sales:
Retail	$	2,095	$	1,050	$	1,045
Wholesale		13		339		(326	)
Total generation sales		2,108		1,389		719
Transmission		280		173		107
Other		2		6		(4	)
Total Revenues	$	2,390	$	1,568	$	822

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

Sources of Change in Generation Sales Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 24.9% increase in customer usage	$	261
Change in prices		784
		1,045
Wholesale:
Effect of 93.7% decrease in sales		(318	)
Change in prices		(8	)
		(326	)
Net Increase in Generation Sales Revenues	$	719

The retail generation revenue increase was primarily due to higher unit prices resulting from implementation in 2006 of the rate stabilization and fuel recovery charges under the Ohio Companies' RCP. Higher retail revenues also reflected the 24.9% increase in retail KWH sales due principally to the return of shopping customers as a result of third-party suppliers leaving the northern Ohio marketplace. The lower wholesale revenues in 2006 were principally due to the termination of an OE non-affiliated wholesale sales agreement ($179 million) and the December 2005 completion of the Ohio Companies MSG sales arrangement under the Ohio transition plan ($134 million).  The Ohio Companies had been required to provide the MSG to certain non-affiliated alternative suppliers.

Increased transmission revenues resulted from approximately $107 million of new revenues under a MISO transmission rider that began in 2006.

Expenses -

Purchased power costs were $537 million higher due primarily to higher unit prices for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	21
Change due to volume		(1	)
		20
Purchases from FES:
Change due to increased unit costs		443
Change due to volume		74
		517
Total Increase in Purchased Power Costs	$	537

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

29

The increased deferral of new regulatory assets in 2006 resulted from the deferral of fuel costs ($110 million) under the RCP, partially offset by lower MISO cost deferrals ($75 million). Amortization of regulatory assets of $20 million in 2006 represented the amortization of MISO costs for which recovery began in 2006.

Other 2006 Compared to 2005

Our financial results from other operating segments and reconciling adjustments, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $99 million increase to our net income in 2006 compared to 2005. The increase was primarily due to the following:

▪ The absence of 2005 income tax expenses of $63 million consisting of the write-off of income tax benefits of $51 million due to the 2005 change in Ohio tax legislation and $12 million due to a 2005 JCP&L tax audit adjustment;

▪ $23 million of 2006 income tax benefits, primarily reflecting the 2005 federal income tax return filed  in the third quarter of 2006 and the Ohio tax benefit related to a voluntary $300 million pension plan contribution (see Note 3);

▪ A $3 million gain related to interest rate swap financing arrangements; and

▪ A $14 million increase in investment income in 2006.

These increases were partially offset by securities redemption charges of $16 million in 2006, a $5 million decrease in gas commodity transaction results and the absence of net gains of $9 million from the sale of non-core assets in 2005.

DISCONTINUED OPERATIONS

Discontinued operations for 2006 include the remaining FSG subsidiaries (Hattenbach, Dunbar, Edwards, and RPC) and a portion of MYR. We sold 60% of MYR in March 2006 and began accounting for our remaining interest in MYR under the equity method of accounting for investments. An additional 1.67% was sold in June 2006 and the remaining 38.33% was sold in November 2006. MYR's results prior to the sale of the initial 60% in March 2006 and the gain on the March sale is included in discontinued operations. The 2006 MYR results subsequent to the March 2006 sale, recorded as equity investment income, and the gain on the November sale are included in income from continuing operations. Discontinued operations for 2005 include FSG subsidiaries (Elliott-Lewis, Spectrum Control Systems and L.H. Cranston and Sons) and the natural gas business of FES.

The following table summarizes the sources of income from discontinued operations:

Discontinued Operations (Net of tax)	2006			2005
	(In millions)
Gain on sale:
FES natural gas business	$	-		$	5
FSG subsidiaries		2			12
Reclassification of operating (loss) income
to discontinued operations:
FSG subsidiaries		(8	)		(4	)
MYR		2			(1	)
Income (loss) from discontinued operations	$	(4	)	$	12

POSTRETIREMENT BENEFITS

Strengthened equity markets during 2007, $1.3 billion of voluntary cash pension contributions made since September 2004 and plan amendments contributed to reductions of $127 million and $27 million in postretirement benefits expenses in 2007 and 2006, respectively, from the prior year. The following table reflects the portion of qualified pension and OPEB costs that were charged to expense in 2007, 2006 and 2005:

Postretirement Benefits Costs (Credits)	2007			2006		2005
	(In millions)
Pension	$	(9	)	$	29	$	32
OPEB		(41	)		48		72
Total	$	(50	)	$	77	$	104

30

Pension and OPEB expenses are included in various cost categories and have contributed to cost decreases discussed above for 2007. In 2008, we will increase the share of coinsurance, as well as increase the health care premiums paid by certain retirees, which will continue to reduce OPEB costs in 2008. See "Critical Accounting Policies - Pension and Other Postretirement Benefits Accounting" for a discussion of the impact of underlying assumptions on postretirement expenses.

SUPPLY PLAN

The Companies have a default service obligation to provide generation to non-shopping customers who have elected to continue to receive generation service under regulated retail tariffs. The volume of these sales can vary depending on the level of shopping that occurs. The Companies procure their power through PSAs with FES, contracts with non-affiliated companies and, in the case of JCP&L and Penn, through state approved competitive procurement processes. Geographically, approximately 66% of the total generation service obligation is for customers located in the MISO market area and 34% for customers located in the PJM market area.

Within the franchise territories of the Companies, alternative retail energy suppliers are expected in 2008 to provide generation service for approximately 3,345 MW (summer peak) of load with an estimated energy requirement of 15,300 million KWH. If these alternative suppliers fail to deliver power to their customers located in one of the Companies service areas, our utility subsidiary must procure replacement power in the role of PLR.

FES and the Companies control (either through ownership, lease or participation in OVEC) 14,127 MW of installed generating capacity. The balance of the Companies 2008 expected generation service obligation has been secured by FES through a combination of long-term purchases (contract term of greater than one year) and short-term purchases (contract term of less than one year). Additional power supply requirements will be met through spot market transactions.

CAPITAL RESOURCES AND LIQUIDITY

Our business is capital intensive and requires considerable capital resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. In 2008 and subsequent years, we expect to meet our contractual obligations and other cash requirements primarily with a combination of cash from operations and funds from the capital markets. We also expect that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

As of December 31, 2007, our net deficit in working capital (current assets less current liabilities) was principally due to the classification of certain variable interest rate PCRBs as currently payable long-term debt.  These currently bear interest in an interest rate mode that permits individual debt holders to put the respective debt back to the issuer for purchase prior to maturity (see Note 11(C)).

Changes in Cash Position

Our primary source of cash required for continuing operations as a holding company is cash from the operations of our subsidiaries. We also have access to $2.75 billion of short-term financing under a revolving credit facility which expires in 2012.  In 2007, we received $1.3 billion of cash dividends and return of capital from our subsidiaries and paid $616 million in cash dividends to our common stockholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by our subsidiaries.

On March 2, 2007, we repurchased approximately 14.4 million shares, or approximately 4.5%, of our outstanding common stock at a total final price of approximately $942 million pursuant to an accelerated share repurchase program. The initial $891 million purchase price was adjusted by a $51 million cash payment on December 13, 2007. The share repurchase was funded with short-term borrowings, the initial portion of which has since been repaid with the proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction discussed below.

On July 13, 2007, FGCO completed the sale and leaseback of 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 (see Notes 6 and 15).

As of December 31, 2007, we had $129 million of cash and cash equivalents compared with $90 million as of December 31, 2006. The major sources of changes in these balances are summarized below.

31

Cash Flows From Operating Activities

Net cash provided from operating activities was $1.7 billion in 2007, $1.9 billion in 2006 and $2.2 billion in 2005, summarized as follows:

Operating Cash Flows	2007			2006			2005
	(In millions)
Net income	$	1,309		$	1,254		$	861
Non-cash charges		670			783			1,289
Pension trust contribution*		(300	)		90			(341	)
Working capital and other		15			(188	)		411
Net cash provided from operating activities	$	1,694		$	1,939		$	2,220
* The pension trust contribution in 2005 is net of $159 million of related current year cash income tax benefits. The $90 million cash inflow in 2006 represents reduced income taxes paid in 2006 relating to the $300 million pension trust contribution made in January 2007.

Net cash provided from operating activities decreased by $245 million in 2007 compared to 2006 primarily due to a $300 million pension trust contribution in 2007 and a $113 million change in non-cash charges, partially offset by a $203 million change in working capital and other and a $55 million increase in net income (see Results of Operations). The changes in working capital and other primarily resulted from changes in accrued taxes of $246 million and materials and supplies of $104 million due to lower coal inventory levels, partially offset by changes in receivables of $241 million due to higher sales and changes in accounts payable of $48 million reflecting a change in the timing of payments from 2006.

Net cash provided from operating activities decreased by $281 million in 2006 compared to 2005 primarily due to a $599 million decrease from working capital and a $506 million decrease in non-cash charges. These decreases were partially offset by the tax benefit in 2006 relating to the January 2007 pension contribution and the absence in 2006 of the pension trust contribution in 2005 and higher net income in 2006 compared to 2005 (see Results of Operations). The decrease from working capital changes primarily resulted from the absence of $242 million of funds received in 2005 for prepaid electric service (under a three-year Energy for Education Program with the Ohio Schools Council), increased tax payments of $325 million, and $273 million of cash collateral returned to suppliers. These decreases were partially offset by an increase in working capital from the collection of receivables of $192 million.

Cash Flows From Financing Activities

In 2007, 2006 and 2005, net cash used for financing activities was $1.3 billion, $804 million and $876 million, respectively, primarily reflecting the redemptions of debt, common stock and preferred stock shown below:

Securities Issued or Redeemed	2007			2006		2005
	(In millions)
New Issues
Pollution control notes	$	427		$	1,157	$	721
Senior secured notes		-			382		-
Unsecured notes		1,100			1,200		-
	$	1,527		$	2,739	$	721
Redemptions
First mortgage bonds	$	288		$	41	$	252
Pollution control notes		432			1,189		555
Senior secured notes		225			206		94
Long-term revolving credit		-			-		215
Unsecured notes		153			1,100		308
Common stock		969			600		-
Preferred stock		-			193		170
	$	2,067		$	3,329	$	1,594
Short-term borrowings (repayments), net	$	(205	)	$	386	$	561

32

We had approximately $903 million of short-term indebtedness as of December 31, 2007 compared to approximately $1.1 billion as of December 31, 2006. Available bank borrowing capability as of December 31, 2007 included the following:

Borrowing Capability	(In millions)
Short-term credit facilities(1)	$	2,870
Accounts receivable financing facilities		550
Utilized		(900	)
LOCs		(73	)
Net available capability	$	2,447
(1) Includes the $2.75 billion revolving credit facility described below, a $100 million revolving credit facility that expires in December 2009 and a $20 million uncommitted line of credit.

As of 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.

As of December 31, 2007, we 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 that expires in December 2008, 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 and will expire in April 2009.

We along with certain of our subsidiaries are party to a $2.75 billion five-year revolving credit facility (included in the borrowing capability table above). We have the capability to 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 following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations:

33

	Revolving			Regulatory and
	Credit Facility			Other Short-Term
Borrower	Sub-Limit			Debt Limitations(1)
	(In millions)
FirstEnergy	$	2,750		$	-	(2)
OE		500			500
Penn		50			42
CEI		250	(3)		500
TE		250	(3)		500
JCP&L		425			422
Met-Ed		250			250	(4)
Penelec		250			250	(4)
FES		1,000			-	(2)
ATSI		-	(5)		50

(1)	As of December 31, 2007.
(2)	No regulatory approvals, statutory or charter limitations applicable.
(3)	Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moodys.
(4)	Excluding amounts which may be borrowed under the regulated money pool.
(5)	The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) such borrower has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moodys or (ii) FirstEnergy has guaranteed the obligations of such borrower under the facility.

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 our working capital requirements and for other general corporate purposes.

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

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of December 31, 2007, our debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy	57	%
OE	44	%
Penn	25	%
CEI	60	%
TE	40	%
JCP&L	30	%
Met-Ed	44	%
Penelec	48	%
FES	55	%

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

Our regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among our unregulated companies. FESC administers these two money pools and tracks surplus funds of our respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2007 was approximately 5.53% for both money pools.

34

Our access to capital markets and costs of financing are influenced by the ratings of our securities.  The following table displays our securities ratings along with those of FES and the Companies as of December 31, 2007. The ratings outlook from S&P on all securities is negative.  The ratings outlook from Moodys on all securities is stable.

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

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

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

On May 21, 2007, JCP&L issued $550 million of senior unsecured debt securities, consisting of $250 million of 5.65% senior notes due 2017 and $300 million of 6.15% senior notes due 2037.  A portion of the proceeds of the offering were used to redeem outstanding FMB -- $125 million principal amount of 7.50% series due 2023 and $150 million principal amount of 6.75% series due 2025. On July 1, 2007, JCP&L also redeemed the remaining $12.2 million of its outstanding FMB. In addition, $125 million of proceeds were used to repurchase shares of its common stock from FirstEnergy.  The remaining proceeds were used for general corporate purposes.

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

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

On October 4, 2007, FGCO and NGC closed on the issuance of approximately $248 million and $180 million, respectively, of PCRBs. The PCRBs were issued through the OAQDA (FGCO $241 million; NGC $26 million), OWDA (FGCO $7 million; NGC $55 million) and BCIDA (NGC $99 million) with the benefit of bond insurance policies issued by Ambac Assurance Corporation and initially bear interest in an auction rate mode, which provided for a weighted average interest rate of approximately 4.3% and 10.2% as of December 31, 2007 and February 26, 2008, respectively.  Proceeds from the issuances were used to redeem, during the fourth quarter of 2007, an equal amount of outstanding PCRBs originally issued by those authorities on behalf of the Ohio Companies. This transaction brings the total amount of PCRBs transferred from the Ohio Companies and Penn to FGCO and NGC to approximately $1.9 billion, with approximately $265 million remaining to be transferred. The transfer of these PCRBs supports the intra-system generation asset transfer that was completed in 2005.

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As of December 31, 2007, FGCO, NGC, Met-Ed, and Penelec had $276 million, $180 million, $29 million, and $45 million, respectively, of tax-exempt long-term debt sold at auction rates that are reset every 7 or 35 days and insured by AAA-rated bond insurers, namely Ambac Assurance Corporation (Ambac) and XL Capital Assurance, Inc. (XL Capital). Due to the exposure that these bond insurers have in connection with recent developments in the subprime credit market, the rating agencies have put these insurers on review for possible downgrade. Fitch has since lowered the credit ratings of Ambac from AAA to AA and XL Capital from AAA to A. Moody's has downgraded the credit rating of XL Capital from Aaa to A3. Because of the apparent widespread loss of confidence in the creditworthiness of these bond insurers and a resulting loss of liquidity in the markets for these types of insured auction rate securities generally, like other issuers and obligors in this market, we have experienced higher auction rate resets and in some cases failed auctions. The instruments under which the bonds are issued, however, allow us to convert to other interest rate modes, including short-term variable-rate or longer term fixed-rate mode, and in February 2008, we elected to convert all of our  outstanding auction-rate bonds to a weekly rate mode, which requires our mandatory purchase of these bonds on the applicable conversion dates. The conversion and purchase of the auction rate bonds is expected to be completed in April 2008. We expect to hold the bonds until they can be remarketed or refinanced  under a different interest rate mode.

Cash Flows From Investing Activities

Net cash flows used in investing activities resulted principally from property additions. Energy delivery services expenditures for property additions primarily include expenditures related to transmission and distribution facilities. Capital expenditures by the competitive energy services segment are principally generation-related. The following table summarizes investing activities for the three years ended December 31, 2007 by business segment:

Summary of Cash Flows	Property
Used for Investing Activities By Segment	Additions			Investments			Other			Total
2007 Sources (Uses)	(In millions)
Energy delivery services	$	(814	)	$	53		$	(6	)	$	(767	)
Competitive energy services		(740	)		1,302			(3	)		559
Other		(79	)		-			(11	)		(90	)
Inter-Segment reconciling items		-			(15	)		-			(15	)
Total	$	(1,633	)	$	1,340		$	(20	)	$	(313	)
2006 Sources (Uses)
Energy delivery services	$	(629	)	$	147		$	(10	)	$	(492	)
Competitive energy services		(644	)		(5	)		(1	)		(650	)
Other		(42	)		73			11			42
Inter-Segment reconciling items		-			(9	)		-			(9	)
Total	$	(1,315	)	$	206		$	-		$	(1,109	)
2005 Sources (Uses)
Energy delivery services	$	(782	)	$	(106	)	$	(14	)	$	(902	)
Competitive energy services		(375	)		(4	)		3			(376	)
Other		(51	)		28			(20	)		(43	)
Inter-Segment reconciling items		-			(12	)		-			(12	)
Total	$	(1,208	)	$	(94	)	$	(31	)	$	(1,333	)

Net cash used for investing activities in 2007 decreased by $796 million compared to 2006.  The decrease was principally due to approximately $1.3 billion in proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction.  Partially offsetting the cash proceeds from the sale and leaseback transaction was a $318 million increase in property additions which reflects AQC system and distribution system reliability program expenditures and a $49 million decrease in cash provided from cash investments, primarily from the use of restricted cash investments to repay debt during 2006.

Net cash used for investing activities in 2006 decreased by $224 million compared to 2005. The decrease was principally due to a $58 million increase in proceeds from asset sales (see Note 8), an $86 million decrease in net nuclear decommissioning trust activities due to the completion of the Ohio Companies' and Penn's transition cost recovery for nuclear decommissioning at the end of 2005 and a $163 million decrease in cash investments described above. These decreases were partially offset by a $107 million increase in property additions, including the replacement of the steam generators and reactor head at Beaver Valley Unit 1 and AQC system expenditures.

Our capital spending for the period 2008-2012 is expected to be nearly $7.6 billion (excluding nuclear fuel), of which $2.0 billion applies to 2008. 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, our nuclear fuel investments are expected to be reduced by approximately $952 million and $111 million, respectively, as the nuclear fuel is consumed.

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CONTRACTUAL OBLIGATIONS

As of December 31, 2007, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:

					2009-		2011-
Contractual Obligations	Total		2008		2010		2012		Thereafter
	(In millions)
Long-term debt	$	10,891	$	334	$	486	$	1,583	$	8,488
Short-term borrowings		903		903		-		-		-
Interest on long-term debt (1)		9,425		628		1,204		1,070		6,523
Operating leases (2)		4,813		316		626		633		3,238
Fuel and purchased power (3)		16,129		3,070		5,237		3,373		4,449
Capital expenditures		1,192		828		275		60		29
Other (4)		310		9		2		2		297
Total	$	43,663	$	6,088	$	7,830	$	6,721	$	23,024

(1)	Interest on variable-rate debt based on rates as of December 31, 2007.
(2)	See Note 6 to the consolidated financial statements.
(3)	Amounts under contract with fixed or minimum quantities based on estimated annual requirements.
(4)	Includes amounts for capital leases (see Note 6) and contingent tax liabilities (see Note 9).

Guarantees and Other Assurances

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

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As of December 31, 2007, our maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.5 billion, as summarized below:

	Maximum
Guarantees and Other Assurances	Exposure
	(In millions)
FirstEnergy Guarantees of Subsidiaries
Energy and Energy-Related Contracts (1)	$	503
LOC (long-term debt) interest coverage (2)		6
Other (3)		503
		1,012
Subsidiaries Guarantees
Energy and Energy-Related Contracts		64
LOC (long-term debt) interest coverage (2)		6
Other (4)		2,641
		2,711
Surety Bonds		73
LOC (long-term debt) interest coverage (2)		5
LOC (non-debt) (5)(6)		692
		770
Total Guarantees and Other Assurances	$	4,493

(1)	Issued for open-ended terms, with a 10-day termination right by FirstEnergy.
(2)	Reflects the interest coverage portion of LOCs issued in support of floating-rate PCRBs with various maturities. The principal amount of floating-rate PCRBs of $1.6 billion is reflected in debt on FirstEnergy's consolidated balance sheets.
(3)	Includes guarantees of $300 million for OVEC obligations and $80 million for nuclear decommissioning funding assurances.
(4)	Includes FES guarantee of FGCOs obligations under the sale and leaseback of Bruce Mansfield Unit 1, but excludes FES guarantee of FGCOs and NGCs respective obligations under insurance agreements for PCRBs in auction-rate interest mode. The $456 million principal amount of auction-rate PCRBs is reflected in debt on FEs consolidated balance sheets.
(5)	Includes $73 million issued for various terms pursuant to LOC capacity available under FirstEnergy's revolving credit facility.
(6)	Includes approximately $194 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE.

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

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or material adverse event the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of December 31, 2007, our maximum exposure under these collateral provisions was $402 million.

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

We have guaranteed the obligations of the operators of the TEBSA project up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified us against any loss under this guarantee. We have also provided an LOC ($19 million as of December 31, 2007), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

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

OFF-BALANCE SHEET ARRANGEMENTS

FES and the Ohio Companies have obligations that are not included on our Consolidated Balance Sheets related to sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. As of December 31, 2007, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $2.3 billion.

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

MARKET RISK INFORMATION

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

Commodity Price Risk

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

Increase (Decrease) in the Fair Value of Derivative Contracts	Non-Hedge			Hedge			Total
	(In millions)
Change in the Fair Value of Commodity Derivative Contracts:
Outstanding net liability as of January 1, 2007	$	(1,140	)	$	(17	)	$	(1,157	)
Additions/change in value of existing contracts		117			(21	)		96
Settled contracts		310			12			322
Outstanding net liability as of December 31, 2007(1)	$	(713	)	$	(26	)	$	(739	)
Non-commodity Net Liabilities as of December 31, 2007:
Interest rate swaps(2)		-			(5	)		(5	)
Net Liabilities - Derivative Contracts as of December 31, 2007	$	(713	)	$	(31	)	$	(744	)
Impact of Changes in Commodity Derivative Contracts(3)
Income Statement effects (pre-tax)	$	4		$	-		$	4
Balance Sheet effects:
OCI (pre-tax)	$	-		$	(9	)	$	(9	)
Regulatory asset (net)	$	(423	)	$	-		$	(423	)

(1) Includes $713 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.

(2) Interest rate swaps are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements below).

(3) Represents the change in value of existing contracts, settled contracts and changes in techniques/ assumptions.

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Derivatives are included on the Consolidated Balance Sheet as of December 31, 2007 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	-		$	24		$	24
Other liabilities		-			(48	)		(48	)
Non-Current-
Other deferred charges		37			8			45
Other noncurrent liabilities		(750	)		(15	)		(765	)
Net liabilities	$	(713	)	$	(31	)	$	(744	)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, we rely on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. We use these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of December 31, 2007 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2008			2009			2010			2011			2012			Thereafter			Total
	(In millions)
Prices actively quoted(1)	$	(1	)	$	-		$	-		$	-		$	-		$	-		$	(1	)
Other external sources(2)		(235	)		(172	)		(151	)		(97	)		-			-			(655	)
Prices based on models		-			-			-			-			(28	)		(55	)		(83	)
Total(3)	$	(236	)	$	(172	)	$	(151	)	$	(97	)	$	(28	)	$	(55	)	$	(739	)

(1)     Exchange traded.

(2)     Broker quote sheets.

(3)     Includes $713 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.

We perform sensitivity analyses to estimate our exposure to the market risk of our commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on our derivative instruments would not have had a material effect on our consolidated financial position (assets, liabilities and equity) or cash flows as of December 31, 2007. Based on derivative contracts held as of December 31, 2007, an adverse 10% change in commodity prices would decrease net income by approximately $3 million for the next twelve months.

Interest Rate Risk

Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the table below.

Comparison of Carrying Value to Fair Value
																There-						Fair
Year of Maturity	2008			2009			2010			2011			2012			after			Total			Value
	(Dollars in millions)
Assets
Investments other than Cash and
Cash Equivalents-Fixed Income	$	86		$	64		$	80		$	86		$	103		$	1,474		$	1,893		$	1,988
Average interest rate		6.6	%		7.9	%		7.9	%		7.9	%		7.9	%		5.6	%		6.0	%
Liabilities
Long-term Debt and Other
Long-term Obligations:
Fixed rate(1)	$	334		$	287		$	199		$	1,540		$	43		$	6,265		$	8,668		$	8,908
Average interest rate		5.2	%		6.7	%		5.4	%		6.4	%		5.9	%		6.3	%		6.3	%
Variable rate(1)																$	2,223		$	2,223		$	2,223
Average interest rate																	3.7	%		3.7	%
Short-term Borrowings	$	903																	$	903		$	903
Average interest rate		5.4	%																	5.4	%

(1)     Balances and rates do not reflect the fixed-to-floating interest rate swap agreements discussed below.

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We are subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. As discussed in Note 6 to the consolidated financial statements, our investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk. Fluctuations in the fair value of NGC's and our Ohio Companies' decommissioning trust balances will eventually affect earnings (immediately for unrealized losses and affecting OCI initially for unrealized gains) based on the guidance in SFAS 115, FSP SFAS 115-1 and SFAS 124-1. The Pennsylvania Companies and JCP&L, however, will either recover or refund to customers the difference between the investments held in trust and their decommissioning obligations. Therefore, there is not expected to be an earnings effect from fluctuations in their decommissioning trust balances. As of December 31, 2007, our decommissioning trust balances totaled $2.1 billion, with $1.5 billion held by NGC and our Ohio Companies and the remaining balance held by JCP&L, Met-Ed and Penelec. The trust balances of NGC and our Ohio Companies were comprised of 66% equity securities and 34% debt instruments as of December 31, 2007.

Interest Rate Swap Agreements - Fair Value Hedges

We utilize fixed-for-floating interest rate swap agreements as part of our ongoing effort to manage the interest rate risk associated with our debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. During 2007, we paid $2 million to terminate swaps with a notional amount $500million as our subsidiary redeemed the associated hedged debt.  The net loss was recognized as interest expense during 2007.  As of December 31, 2007, the debt underlying the $250million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 4.87%, which the swaps have converted to a current weighted average variable rate of 5.48%.

	December 31, 2007						December 31, 2006
	Notional		Maturity	Fair			Notional		Maturity	Fair
Interest Rate Swaps	Amount		Date	Value			Amount		Date	Value
	(In millions)
Fair value hedges	$	100	2008	$	-		$	100	2008	$	(2	)
			2010					50	2010		(1	)
			2013					300	2013		(6	)
		150	2015		(3	)		150	2015		(10	)
			2025					50	2025		(2	)
			2031					100	2031		(6	)
	$	250		$	(3	)	$	750		$	(27	)

Forward Starting Swap Agreements - Cash Flow Hedges

We utilize forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with anticipated future issuances of fixed-rate, long-term debt securities for one or more of our consolidated subsidiaries in 2007 and 2008. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During 2007, we terminated forward swaps with an aggregate notional value of $2.5 billion at a cost of $30 million. The ineffective portion of that loss ($1.6 million) was recognized in current period earnings. The remaining effective portion of the loss will be recognized over the terms of the associated future debt. As of December 31, 2007, we had outstanding forward swaps with an aggregate notional amount of $400 million and an aggregate fair value of $(3) million.

	December 31, 2007						December 31, 2006
	Notional		Maturity	Fair			Notional		Maturity	Fair
Forward Starting Swaps	Amount		Date	Value			Amount		Date	Value
	(In millions)
Cash flow hedges	$	25	2015	$	(1	)	$	25	2015	$	-
			2017					200	2017		(4	)
		325	2018		(1	)		25	2018		(1	)
		50	2020		(1	)		50	2020		1
	$	400		$	(3	)	$	300		$	(4	)

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $1.4  billion as of December 31, 2007. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $136 million reduction in fair value as of December 31, 2007 (see Note 5(B)).

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Certain investments within our nuclear decommissioning, pension and other postretirement benefit trusts hold credit market securities, including subprime mortgage-related assets. The fair value of these subprime-related investments has declined as a result of recent market developments, including a series of rating agency downgrades of subprime mortgage-related assets. We expect that market conditions will continue to evolve, and that the fair value of these investments may frequently change. We have assessed our investments and believe that declines in the fair value of our nuclear decommissioning and pension trusts, due to their relatively small exposure to subprime assets, will not be material.

CREDIT RISK

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

We maintain credit policies with respect to our counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of our credit program, we aggressively manage the quality of our portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB+ (S&P). As of December 31, 2007, the largest credit concentration with one party, JP Morgan (currently rated investment grade), represented 10.7% of our total credit risk. Within our unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserves, were with investment grade counterparties as of December 31, 2007.

REGULATORY MATTERS

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

▪ restructuring the electric generation business and allowing the Companies' customers to select competitive electric generation suppliers other than the Companies;

▪ establishing or defining the PLR obligations to customers in the Companies' service areas;

▪ providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

▪ itemizing (unbundling) the price of electricity into its component elements including generation, transmission, distribution and stranded costs recovery charges;

▪ continuing regulation of the Companies' transmission and distribution systems; and

▪ requiring corporate separation of regulated and unregulated business activities.

The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $140 million as of December 31, 2007 (JCP&L - $84 million, Met-Ed - $54 million and Penelec - $2 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets by company:

	December 31,		December 31,		Increase
Regulatory Assets*	2007		2006		(Decrease)
	(In millions)
OE	$	737	$	741	$	(4	)
CEI		871		855		16
TE		204		248		(44	)
JCP&L		1,596		2,152		(556	)
Met-Ed		495		409		86
ATSI		42		36		6
Total	$	3,945	$	4,441	$	(496	)

* Penn had net regulatory liabilities of approximately $67 million and $68 million as of December 31, 2007 and 2006, respectively. Penelec had net regulatory liabilities of approximately $74 million and $96 million as of December 31, 2007 and 2006, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

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Regulatory assets by source are as follows:

	December 31,			December 31,			Increase
Regulatory Assets By Source	2007			2006			(Decrease)
	(In millions)
Regulatory transition costs	$	2,363		$	3,266		$	(903	)
Customer shopping incentives		516			603			(87	)
Customer receivables for future income taxes		295			217			78
Loss on reacquired debt		57			43			14
Employee postretirement benefits		39			47			(8	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(115	)		(145	)		30
Asset removal costs		(183	)		(168	)		(15	)
MISO/PJM transmission costs		340			213			127
Fuel costs - RCP		220			113			107
Distribution costs - RCP		321			155			166
Other		92			97			(5	)
Total	$	3,945		$	4,441		$	(496	)

Ohio

The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP. On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2008 through 2010:

Amortization								Total
Period		OE		CEI		TE		Ohio
	(In millions)
2008		$	207	$	126	$	113	$	446
2009			-		212		-		212
2010			-		273		-		273
Total Amortization		$	207	$	611	$	113	$	931

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 Courts Opinion on this issue and affirmed the PUCOs 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 utilitys total load notwithstanding the customers 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, we cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on our operations or those of the Ohio Companies.

Pennsylvania

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.

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If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for 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 our results of operations and those of Met-Ed and Penelec.

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.

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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 companys 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 Governors 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, we are unable to predict what impact, if any, such legislation may have on our operations.

New Jersey

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of December 31, 2007, the accumulated deferred cost balance totaled approximately $322 million.

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 us. 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.

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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 Governors Office and the Governors 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 Jerseys 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, we cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on our 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, we cannot predict the outcome of this process nor determine the impact, if any, such regulations may have on our operations or those of JCP&L.

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. FERCs 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.

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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 us, submitted briefs opposing the ALJs decision and recommendations.  On April 19, 2007, the FERC issued an order rejecting the ALJs 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 PJMs 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 our 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 Regional Expansion Criteria & Benefits (RECB) methodology) be retained.

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 SuperRegion 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.

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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, including ATSI, 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 significant 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 ATSIs transmission revenues from MISO will continue to be equivalent to its transmission revenue requirement and therefore it will not suffer any revenue shortfall.

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.

MISOs 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 FERCs 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 MISOs filing were made with FERC on October 15, 2007.  FERC conducted a technical conference so that the MISO independent market monitor could address market power questions about the MISO proposal on December 6, 2007, and additional comments were filed by us and other parties on December 19, 2007. FERC action is anticipated in the first quarter of 2008.

Duquesnes 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 PJMs forward capacity market.  We believe that Duquesnes filing did not identify or address numerous legal, financial or operational issues that we believe are implicated or affected directly by Duquesnes proposal. Consequently, on December 4, 2007 and January 3, 2008, we submitted responsive filings that, while conceding Duquesnes rights to exit PJM, contested various aspects of Duquesnes proposal.  We particularly focused on Duquesnes proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. We also objected to Duquesnes 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, we protested Duquesnes 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 Duquesnes plans.

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On January 17, 2008, the FERC conditionally approved Duquesnes 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 Owners Agreement. The FERC likewise directed the MISO to submit a compliance filing in forty-five days (or by March 3, 2008) detailing the MISOs 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 Duquesnes transition into the MISO.  On February 19, 2008, we 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. We generally support 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. We do not expect this filing to impose additional supply costs since our 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.  We have not yet had an opportunity to evaluate the impact of the proposed rule on our operations.

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, we completed all of the enhancements that were recommended for completion in 2004.  Subsequently, we have worked systematically to complete all of the enhancements that were identified for completion after 2004, and we expect to complete this work prior to the summer of 2008.  The FERC and the other affected government agencies and reliability entities may review our work and, on the basis of any such review, may recommend additional enhancements in the future, which could require additional, material expenditures.

As a result of outages experienced in JCP&Ls service area in 2002 and 2003, the NJBPU performed a review of JCP&Ls 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&Ls 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 consultants 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&Ls 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 our facilities are located within the ReliabiltyFirst region. We actively participate in the NERC and ReliabiltyFirst stakeholder processes, and otherwise monitor and manage our companies in response to the ongoing development, implementation and enforcement of the reliability standards.

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We believe that we are 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 our part to comply with the reliability standards for our bulk power system could have a material adverse effect on our financial condition, results of operations and cash flows.

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

ENVIRONMENTAL MATTERS

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

Clean Air Act Compliance

We are 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. We believe we are 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. We have disputed those alleged violations based on our 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.

We comply 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 our 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. We believe our facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

On May 22, 2007, we along with 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, we 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.

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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). Our Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO2 and NOX emissions, whereas our 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, our 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.

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 we fail 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, we 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).

The Sammis NSR Litigation consent decree also requires us 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.

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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.

We 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 us is lower than many regional competitors due to our diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to our plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to our 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. We are 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.

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Under NRC regulations, we must ensure that adequate funds will be available to decommission our nuclear facilities.  As of December 31, 2007, we 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, we 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 we (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seek for these facilities.

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site 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.

OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages.  JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007.  Proceedings are continuing in the Superior Court.  We are defending this class action but are unable to predict the outcome of this matter.  No liability has been accrued as of December 31, 2007.

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On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in our service area. The U.S. Canada Power System Outage Task Forces final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in our Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both us and ECAR to assess and understand perceived inadequacies within our system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energys Web site (www.doe.gov). We believe that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. We remain convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 recommendations to prevent or minimize the scope of future blackouts. Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by us, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. We implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of our electric system. Our implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward us. We are also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

On February 5, 2008, the PUCO entered an order dismissing four separate complaint cases before it relating to the August 14, 2003 power outages. The dismissal was filed by the complainants in accordance with a resolution reached between the FirstEnergy companies and the complainants in those four cases. Two of those cases which were originally filed in Ohio State courts involved individual complainants and were subsequently dismissed for lack of subject matter jurisdiction.  Further appeals were unsuccessful. The other two complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured, seeking reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and AEP, as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003.  (Also relating to the August 14, 2003 power outages, a fifth case, involving another insurance company was voluntarily dismissed by the claimant in April 2007; and a sixth case, involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed by the court.)  The order dismissing the PUCO cases, noted above, concludes all pending litigation related to the August 14, 2003 outages and the resolution will not have a material adverse effect on the financial condition, results of operations or cash flows of either us or any of our subsidiaries.

Nuclear Plant Matters

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 us 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 NRCs 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 our 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 NRCs Office of Enforcement after it completes the key commitments embodied in the NRCs order. FENOCs compliance with these commitments is subject to future NRC review.

Other Legal Matters

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

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

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. 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.

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

CRITICAL ACCOUNTING POLICIES

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

Revenue Recognition

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

Emission Allowances

We hold emission allowances for SO2 and NOX in order to comply with programs implemented by the EPA designed to regulate emissions of SO2 and NOX produced by power plants. Emission allowances are either granted to us by the EPA at zero cost or are purchased at fair value as needed to meet emission requirements.  Emission allowances are not purchased with the intent of resale. Emission allowances eligible to be used in the current year are recorded in materials and supplies inventory at the lesser of weighted average cost or market value. Emission allowances eligible for use in future years are recorded as other investments. We recognize emission allowance costs as fuel expense during the periods that emissions are produced by our generating facilities.  Excess emission allowances that are not needed to meet emission requirements may be sold and are reported as a reduction to other operating expenses.

Regulatory Accounting

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

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Pension and Other Postretirement Benefits Accounting

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

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

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

In December 2006, we adopted SFAS 158 which requires a net liability or asset to be recognized for the overfunded or underfunded status of our defined benefit pension and other postretirement benefit plans on the balance sheet and recognize changes in funded status in the year in which the changes occur through other comprehensive income. We will continue to apply the provisions of SFAS 87 and SFAS 106 in measuring plan assets and benefit obligations as of the balance sheet date and in determining the amount of net periodic benefit cost. The overfunded status of our qualified pension and OPEB plans at December 31, 2007 is $136 million. Our non-qualified pension plans have an underfunded status of $165 million at December 31, 2007.

In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. The assumed discount rate was 6.5%, 6.00% and 5.75% as of December 31, 2007, 2006 and 2005, respectively.

Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. In 2007, 2006 and 2005, our qualified pension plan assets actually earned $438 million or 8.2%, $567 million or 12.5% and $325 million or 8.2%, respectively. Our qualified pension costs in 2007, 2006 and 2005 were computed using an assumed 9.0% rate of return on plan assets which generated $449 million, $396 million and $345 million expected returns on plan assets, respectively. The 2007 expected return was based upon projections of future returns and our pension trust investment allocation of approximately 61% equities, 30% bonds, 7% real estate, 1% private equities and 1% cash. The gains or losses generated as a result of the difference between expected and actual returns on plan assets are deferred and amortized and will increase or decrease future net periodic pension expense, respectively.

Our qualified pension and OPEB net periodic benefit expense was a credit of $94 million in 2007 compared to an expense of $94 million and $131 million in 2006 and 2005, respectively. Our non-qualified net periodic pension expense was $21 million in 2007 and 2006 and $16 million in 2005. On January 2, 2007, we made a $300 million voluntary contribution to our pension plan.  In addition, during 2006, we amended our OPEB plan, effective in 2008, to cap our monthly contribution for many of the retirees and their spouses receiving subsidized health care coverage. As a result of the $300 million voluntary contribution and the amendment to the OPEB plan effective in 2008, we expect our 2008 qualified pension and OPEB costs to be a credit of $137 million and our non-qualified pension costs to be an expense of $21 million.

Health care cost trends continue to increase and will affect future OPEB costs. The 2007 and 2006 composite health care trend rate assumptions are approximately 9-11%, gradually decreasing to 5% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. The effect on our pension and OPEB costs from changes in key assumptions are as follows:

Increase in Costs from Adverse Changes in Key Assumptions
Assumption	Adverse Change	Pension		OPEB		Total
				(In millions)
Discount rate	Decrease by 0.25%	$	15	$	3	$	18
Long-term return on assets	Decrease by 0.25%	$	13	$	1	$	14
Health care trend rate	Increase by 1%		N/A	$	9	$	9

57

Ohio Transition Cost Amortization

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

Long-Lived Assets

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

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

Asset Retirement Obligations

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

Income Taxes

We record income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.

Goodwill

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

During 2006, our annual review was completed in the third quarter with no impairment indicated.  As discussed in Note 10 to the consolidated financial statements, the PPUC issued its order on January 11, 2007 related to the comprehensive rate filing made by Met-Ed and Penelec on April 10, 2006.  Prior to issuing the order, the PPUC conducted an informal, nonbinding polling of Commissioners at its public meeting on December 21, 2006 that indicated that the rate increase ultimately granted could be substantially lower than the amounts requested.  As a result of the polling, we determined that an interim review of goodwill for our energy delivery services segment would be required.  No impairment was indicated as a result of that review.

58

SFAS 142 requires the goodwill of a reporting unit to be tested for impairment if there is a more-likely-than-not expectation that the reporting unit or a significant asset group within the reporting unit will be sold.  In December 2005, MYR qualified as an asset held for sale in accordance with SFAS 144.  As a result, in the fourth quarter of 2005, the goodwill of MYR was retested for impairment, resulting in a non-cash charge of $9 million (there was no corresponding income tax benefit).

The forecasts used in our evaluations of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 157 - "Fair Value Measurements"

In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value, which focuses on an exit price rather than entry price; (2) the methods used to measure fair value, such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement and its related FSPs are effective for fiscal years beginning after November 15, 2007, and interim periods within those years.  Under FSP FAS 157-2, we have elected to defer the election of SFAS 157 for financial assets and financial liabilities measured at fair value on a non-recurring basis for one year.  We have evaluated the impact of this Statement and its FSPs, FSP FAS 157-2 and FSP FAS 157-1, which excludes SFAS 13, Accounting for Leases, and its related pronouncements from the scope of SFAS 157, and do not expect there to be a material effect on our financial statements.  The majority of our fair value measurements will be disclosed as level 1 or level 2 in the fair value hierarchy.

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

In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and financial liabilities at fair value. This Statement attempts to provide additional information that will help investors and other users of financial statements to more easily understand the effect of a companys choice to use fair value on its earnings.  The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet.  This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157 and SFAS 107. This Statement is effective for fiscal years beginning after November 15, 2007, and interim periods within those years. We have analyzed our financial assets and financial liabilities within the scope of this Statement and no fair value elections were made as of January 1, 2008.

SFAS 141(R) - "Business Combinations"

In December 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination.  SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance.  SFAS 141(R) will affect business combinations we enter that close after January 1, 2009.  In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this standard. We are currently evaluating the impact of adopting this Standard on our financial statements.

SFAS 160 - "Noncontrolling Interests in Consolidated Financial Statements an Amendment of ARB No. 51"

In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.  This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited.  The Statement is not expected to have a material impact on our financial statements.

59

FSP FIN 39-1 - "Amendment of FASB Interpretation No. 39"

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

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

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

60

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of FirstEnergy Corp. (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Companys 2007 consolidated financial statements.

The Companys internal auditors, who are responsible to the Audit Committee of the Companys Board of Directors, review the results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.

The Companys Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committees findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Companys independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management's programs to monitor compliance with the Companys policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 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 the Companys internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Companys internal control over financial reporting was effective as of December 31, 2007. The effectiveness of the Companys 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 which appears on page 61.

61

Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholders' equity and cash flows present fairly, in all material respects, the financial position of FirstEnergy Corp. and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting.  Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits.  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in the notes to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007 (Note 9), defined benefit pension and other postretirement plans as of December 31, 2006 (Note 3) and conditional asset retirement obligations as of December 31, 2005 (Note 2(G) and Note 12).

A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A companys internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

62

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2007			2006			2005
	(In millions, except per share amounts)
REVENUES:
Electric utilities	$	11,305		$	10,007		$	9,703
Unregulated businesses		1,497			1,494			1,655
Total revenues*		12,802			11,501			11,358
EXPENSES:
Fuel and purchased power		5,014			4,253			4,011
Other operating expenses		3,086			2,965			3,103
Provision for depreciation		638			596			588
Amortization of regulatory assets		1,019			861			1,281
Deferral of new regulatory assets		(524	)		(500	)		(405	)
General taxes		754			720			713
Total expenses		9,987			8,895			9,291
OPERATING INCOME		2,815			2,606			2,067
OTHER INCOME (EXPENSE):
Investment income		120			149			217
Interest expense		(775	)		(721	)		(660	)
Capitalized interest		32			26			19
Subsidiaries preferred stock dividends		-			(7	)		(15	)
Total other expense		(623	)		(553	)		(439	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		2,192			2,053			1,628
INCOME TAXES		883			795			749
INCOME FROM CONTINUING OPERATIONS		1,309			1,258			879
Discontinued operations (net of income tax benefits of $2 million and $4 million, respectively) (Note 8)		-			(4	)		12
INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		1,309			1,254			891
Cumulative effect of a change in accounting principle (net of income tax benefit of $17 million) (Note 2(G))		-			-			(30	)
NET INCOME	$	1,309		$	1,254		$	861
BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income from continuing operations	$	4.27		$	3.85		$	2.68
Discontinued operations (Note 8)		-			(0.01	)		0.03
Cumulative effect of a change in accounting principle (Note 2(G))		-			-			(0.09	)
Net earnings per basic share	$	4.27		$	3.84		$	2.62
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		306			324			328
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income from continuing operations	$	4.22		$	3.82		$	2.67
Discontinued operations (Note 8)		-			(0.01	)		0.03
Cumulative effect of a change in accounting principle (Note 2(G))		-			-			(0.09	)
Net earnings per diluted share	$	4.22		$	3.81		$	2.61
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		310			327			330
* Includes $424 million, $400 million and $395 million of excise tax collections in 2007, 2006 and 2005, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

63

FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
As of December 31,	2007		2006
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	129	$	90
Receivables-
Customers (less accumulated provisions of $36 million and
$43 million, respectively, for uncollectible accounts)		1,256		1,135
Other (less accumulated provisions of $22 million and
$24 million, respectively, for uncollectible accounts)		165		132
Materials and supplies, at average cost		521		577
Prepayments and other		159		149
		2,230		2,083
PROPERTY, PLANT AND EQUIPMENT:
In service		24,619		24,105
Less - Accumulated provision for depreciation		10,348		10,055
		14,271		14,050
Construction work in progress		1,112		617
		15,383		14,667
INVESTMENTS:
Nuclear plant decommissioning trusts		2,127		1,977
Investments in lease obligation bonds (Note 6)		717		811
Other		754		746
		3,598		3,534
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,607		5,898
Regulatory assets		3,945		4,441
Pension assets (Note 3)		700		-
Other		605		573
		10,857		10,912
	$	32,068	$	31,196
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	2,014	$	1,867
Short-term borrowings (Note 13)		903		1,108
Accounts payable		777		726
Accrued taxes		408		598
Other		1,046		956
		5,148		5,255
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholders equity		8,977		9,035
Long-term debt and other long-term obligations		8,869		8,535
		17,846		17,570
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,671		2,740
Asset retirement obligations		1,267		1,190
Deferred gain on sale and leaseback transaction		1,060		-
Power purchase contract loss liability		750		1,182
Retirement benefits		894		944
Lease market valuation liability		663		767
Other		1,769		1,548
		9,074		8,371
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 6 and 14)
	$	32,068	$	31,196
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

64

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2007			2006
(Dollars in millions)
COMMON STOCKHOLDERS' EQUITY:
Common stock, $0.10 par value - authorized 375,000,000 shares -
304,835,407 and 319,205,517 shares outstanding, respectively	$	31		$	32
Other paid-in capital		5,509			6,466
Accumulated other comprehensive loss (Note 2(F))		(50	)		(259	)
Retained earnings (Note 11(A))		3,487			2,806
Unallocated employee stock ownership plan common stock-
521,818 shares in 2006 (Note 4(B))		-			(10	)
Total common stockholders' equity		8,977			9,035

LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 11(C)):
(Interest rates reflect weighted average rates)
	FIRST MORTGAGE BONDS						SECURED NOTES						UNSECURED NOTES						TOTAL
	%		2007		2006		%		2007		2006		%		2007		2006		2007		2006
Ohio Edison Company-
Due 2007-2012		-	$	-	$	-		7.01	$	4	$	8		4.65	$	331	$	331
Due 2013-2017		-		-		-		-		-		-		6.04		400		400
Due 2028-2032		-		-		-		5.38		13		120		-		-		-
Due 2033-2037		-		-		-		-		-		-		6.88		350		350
Total-Ohio Edison				-		-				17		128				1,081		1,081		1,098		1,209
Cleveland Electric Illuminating Company-
Due 2007-2012		6.86		125		125		6.13		232		351		-		-		-
Due 2013-2017		-		-		-		7.88		300		300		5.67		550		379
Due 2018-2022		-		-		-		-		-		133		-		-		-
Due 2028-2032		-		-		-		5.38		6		6		-		-		103
Due 2033-2037		-		-		-		-		-		54		5.95		300		300
Total-Cleveland Electric				125		125				538		844				850		782		1,513		1,751
Toledo Edison Company-
Due 2007-2012		-		-		-		-		-		30		-		-		-
Due 2023-2027		-		-		-		-		-		10		-		-		-
Due 2028-2032		-		-		-		5.38		4		4		-		-		-
Due 2033-2037		-		-		-		-		-		45		6.15		300		300
Total-Toledo Edison				-		-				4		89				300		300		304		389
Pennsylvania Power Company-
Due 2007-2012		9.74		5		6		-		-		-		-		-		-
Due 2013-2017		9.74		5		5		5.40		1		1		-		-		-
Due 2018-2022		9.74		2		2		-		-		-		-		-		-
Due 2023-2027		7.63		6		6		-		-		-		-		-		-
Due 2028-2032		-		-		-		5.38		2		2		-		-		-
Total-Penn Power				18		19				3		3				-		-		21		22
Jersey Central Power & Light Company-
Due 2007-2012		-		-		-		5.50		154		187		-		-		-
Due 2013-2017		-		-		12		5.89		187		487		5.64		550		-
Due 2018-2022		-		-		-		5.60		56		206		4.80		150		-
Due 2023-2027		-		-		275		-		-		-		-		-		-
Due 2033-2037		-		-		-		-		-		200		6.25		500		-
Total-Jersey Central				-		287				397		1,080				1,200		-		1,597		1,367
Metropolitan Edison Company-
Due 2007-2012		-		-		-		-		-		-		4.45		100		150
Due 2013-2017		-		-		-		-		-		-		4.90		400		400
Due 2018-2022		-		-		-		-		-		-		4.66		28		28
Due 2023-2027		5.95		14		14		-		-		-		-		-		-
Total-Metropolitan Edison				14		14				-		-				528		578		542		592
Pennsylvania Electric Company-
Due 2007-2012		5.35		24		24		-		-		-		6.55		135		135
Due 2013-2017		-		-		-		-		-		-		5.74		450		150
Due 2018-2022		-		-		-		-		-		-		6.32		145		145
Due 2023-2027		-		-		-		-		-		-		4.51		25		25
Total-Pennsylvania Electric				24		24				-		-				755		455		779		479

65

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
As of December 31,
(Dollars in millions)
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Cont'd)
(Interest rates reflect weighted average rates)
	FIRST MORTGAGE BONDS						SECURED NOTES						UNSECURED NOTES						TOTAL
	%		2007		2006		%		2007		2006		%		2007		2006		2007			2006
FirstEnergy Corp.-
Due 2007-2012		-		-		-		-		-		-		6.45		1,500		1,500
Due 2028-2032		-		-		-		-		-		-		7.38		1,500		1,500
Total-FirstEnergy				-		-				-		-				3,000		3,000		3,000			3,000
Bay Shore Power		-		-		-		6.25		125		130		-		-		-		125			130
FirstEnergy Generation		-		-		-		-		-		-		4.06		871		624		871			624
FirstEnergy Nuclear Generation		-		-		-		-		-		-		4.24		1,041		861		1,041			861
Total				181		469				1,084		2,274				9,626		7,681		10,891			10,424
Capital lease obligations																				4			4
Net unamortized discount on debt																				(12	)		(26	)
Long-term debt due within one year																				(2,014	)		(1,867	)
Total long-term debt and other long-term obligations																				8,869			8,535
TOTAL CAPITALIZATION																			$	17,846		$	17,570
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

66

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
													Accumulated						Unallocated
				Common Stock						Other			Other						ESOP
	Comprehensive			Number			Par			Paid-In			Comprehensive			Retained			Common
	Income			of Shares			Value			Capital			Income (Loss)			Earnings			Stock
	(Dollars in millions)
Balance, January 1, 2005					329,836,276		$	33		$	7,056		$	(313	)	$	1,857		$	(43	)
Net income	$	861															861
Minimum liability for unfunded retirement benefits, net of $208 million of income taxes		295												295
Unrealized gain on derivative hedges, net of $9 million of income taxes		14												14
Unrealized loss on investments, net of $15 million of income tax benefits		(16	)											(16	)
Comprehensive income	$	1,154
Stock options exercised											(41	)
Allocation of ESOP shares											22									16
Restricted stock units											6
Cash dividends declared on common stock																	(559	)
Balance, December 31, 2005					329,836,276			33			7,043			(20	)		2,159			(27	)
Net income	$	1,254															1,254
Unrealized gain on derivative hedges, net of $10 million of income taxes		19												19
Unrealized gain on investments, net of $40 million of income taxes		69												69
Comprehensive income	$	1,342
Net liability for unfunded retirement benefits due to the implementation of SFAS 158, net of $292 million of income tax benefits (Note 3)														(327	)
Redemption premiums on preferred stock																	(9	)
Stock options exercised											(28	)
Allocation of ESOP shares											33									17
Restricted stock units											11
Stock based compensation											6
Repurchase of common stock					(10,630,759	)		(1	)		(599	)
Cash dividends declared on common stock																	(598	)
Balance, December 31, 2006					319,205,517			32			6,466			(259	)		2,806			(10	)
Net income	$	1,309															1,309
Unrealized loss on derivative hedges, net of $8 million of income tax benefits		(17	)											(17	)
Unrealized gain on investments, net of $31 million of income taxes		47												47
Pension and other postretirement benefits, net of $169 million of income taxes (Note 3)		179												179
Comprehensive income	$	1,518
Stock options exercised											(40	)
Allocation of ESOP shares											26									10
Restricted stock units											23
Stock based compensation											2
FIN 48 cumulative effect adjustment																	(3	)
Repurchase of common stock					(14,370,110	)		(1	)		(968	)
Cash dividends declared on common stock																	(625	)
Balance, December 31, 2007					304,835,407		$	31		$	5,509		$	(50	)	$	3,487		$	-
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

67

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2007			2006			2005
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,309		$	1,254		$	861
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		638			596			588
Amortization of regulatory assets		1,019			861			1,281
Deferral of new regulatory assets		(524	)		(500	)		(405	)
Nuclear fuel and lease amortization		101			90			90
Deferred purchased power and other costs		(346	)		(445	)		(384	)
Deferred income taxes and investment tax credits, net		(9	)		159			154
Investment impairment (Note 2(E))		26			27			6
Cumulative effect of a change in accounting principle		-			-			30
Deferred rents and lease market valuation liability		(99	)		(113	)		(104	)
Accrued compensation and retirement benefits		(37	)		193			90
Tax refunds related to pre-merger period		-			-			18
Commodity derivative transactions, net		6			24			6
Gain on asset sales		(30	)		(49	)		(35	)
Loss (income) from discontinued operations (Note 8)		-			4			(12	)
Cash collateral, net		(68	)		(77	)		196
Pension trust contributions		(300	)		-			(500	)
Decrease (increase) in operating assets-
Receivables		(136	)		105			(87	)
Materials and supplies		79			(25	)		(32	)
Prepayments and other current assets		10			3			3
Increase (decrease) in operating liabilities-
Accounts payable		51			99			32
Accrued taxes		71			(175	)		150
Accrued interest		(8	)		7			(6	)
Electric service prepayment programs		(75	)		(64	)		208
Other		16			(35	)		72
Net cash provided from operating activities		1,694			1,939			2,220
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		1,527			2,739			721
Short-term borrowings, net		-			386			561
Redemptions and Repayments-
Common stock		(969	)		(600	)		-
Preferred stock		-			(193	)		(170	)
Long-term debt		(1,098	)		(2,536	)		(1,424	)
Short-term borrowings, net		(205	)		-			-
Net controlled disbursement activity		(1	)		(27	)		(18	)
Stock-based compensation tax benefit		20			13			-
Common stock dividend payments		(616	)		(586	)		(546	)
Net cash used for financing activities		(1,342	)		(804	)		(876	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(1,633	)		(1,315	)		(1,208	)
Proceeds from asset sales		42			162			104
Proceeds from sale and leaseback transaction		1,329			-			-
Sales of investment securities held in trusts		1,294			1,651			1,587
Purchases of investment securities held in trusts		(1,397	)		(1,666	)		(1,688	)
Cash investments and restricted funds (Note 5)		72			121			(42	)
Other		(20	)		(62	)		(86	)
Net cash used for investing activities		(313	)		(1,109	)		(1,333	)
Net increase in cash and cash equivalents		39			26			11
Cash and cash equivalents at beginning of year		90			64			53
Cash and cash equivalents at end of year	$	129		$	90		$	64
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	744		$	656		$	665
Income taxes	$	710		$	688		$	406
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

68

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.      ORGANIZATION AND BASIS OF PRESENTATION

FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and its subsidiaries FGCO and NGC, and FESC.

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

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 7) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) are accounted for under the equity method. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entitys earnings is reported in the Consolidated Statements of Income.

Certain prior year amounts have been reclassified to conform to the current year presentation. Effective January 1, 2007, FirstEnergy changed its external segment reporting structure to reflect the operations of its core business segments and to align its external segment reporting with internal management reporting. As discussed in Note 16, segment reporting in 2006 and 2005 was reclassified to conform to the 2007 business segment organization and operations.

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

2.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(A)  ACCOUNTING FOR THE EFFECTS OF REGULATION

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.

69

Regulatory Assets

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 expense as incurred. Regulatory assets that do not earn a current return totaled approximately $140 million as of December 31, 2007 (JCP&L - $84 million, Met-Ed - $54 million and Penelec - $2 million). Regulatory assets not earning a current return will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec.

Regulatory assets on the Consolidated Balance Sheets are comprised of the following:

	2007			2006
	(In millions)
Regulatory transition costs	$	2,363		$	3,266
Customer shopping incentives		516			603
Customer receivables for future income taxes		295			217
Loss on reacquired debt		57			43
Employee postretirement benefit costs		39			47
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(115	)		(145	)
Asset removal costs		(183	)		(168	)
MISO/PJM transmission costs		340			213
Fuel costs RCP		220			113
Distribution costs RCP		321			155
Other		92			97
Total	$	3,945		$	4,441

In accordance with the RCP, recovery of the aggregate of the regulatory transition costs and the Extended RTC (deferred customer shopping incentives and interest costs) amounts are expected to be complete for OE and TE by December 31, 2008. CEI's recovery of regulatory transition costs is projected to be complete by April 2009 at which time recovery of its Extended RTC will begin, with recovery estimated to be complete as of December 31, 2010. At the end of their respective recovery periods, any remaining unamortized regulatory transition costs and Extended RTC balances will be reduced by applying any remaining cost of removal regulatory liability balances -- any remaining regulatory transition costs and Extended RTC balances will be written off. The RCP allows the Ohio Companies to defer and capitalize certain distribution costs during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the years 2006, 2007 and 2008. These deferrals will be recovered in distribution rates effective on or after January 1, 2009. In addition, the Ohio Companies deferred certain fuel costs through December 31, 2007 that were incurred above the amount collected through a fuel recovery mechanism in accordance with the RCP (see Note 10(B)).

Transition Cost Amortization

OE, CEI and TE amortize transition costs (see Regulatory Matters Ohio) using the effective interest method. Extended RTC amortization is equal to the related revenue recovery that is recognized. The following table provides the estimated net amortization of regulatory transition costs and Extended RTC amounts (including associated carrying charges) under the RCP for the period 2008 through 2010:

Amortization								Total
Period		OE		CEI		TE		Ohio
	(In millions)
2008		$	207	$	126	$	113	$	446
2009			-		212		-		212
2010			-		273		-		273
Total Amortization		$	207	$	611	$	113	$	931

Total regulatory transition costs as of December 31, 2007 were $2.4 billion, of which approximately $1.6 billion and $237 million apply to JCP&L and Met-Ed, respectively. JCP&Ls and Met-Eds regulatory transition costs include the deferral of above-market costs for power supplied from NUGs of $875 million for JCP&L (recovered through BGS and MTC revenues) and $185 million for Met-Ed (recovered through CTC revenues). The liability for JCP&Ls projected above-market NUG costs and corresponding regulatory asset are adjusted to fair value at the end of each quarter. Recovery of the remaining regulatory transition costs is expected to continue pursuant to various regulatory proceedings in New Jersey and Pennsylvania (See Note 10).

70

(B) REVENUES AND RECEIVABLES

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

Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2007 with respect to any particular segment of FirstEnergy's customers. Total customer receivables were $1.3 billion (billed $734 million and unbilled $524 million) and $1.1 billion (billed $650 million and unbilled $485 million) as of December 31, 2007 and 2006, respectively.

(C)  EARNINGS PER SHARE OF COMMON STOCK

Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The pool of stock-based compensation tax benefits is calculated in accordance with SFAS 123(R). On August 10, 2006, FirstEnergy repurchased 10.6 million shares, approximately 3.2%, of its outstanding common stock through an accelerated share repurchase program. The initial purchase price was $600 million, or $56.44 per share. A final purchase price adjustment of $27 million was settled in cash on April 2, 2007. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an additional accelerated share repurchase program at an initial price of $62.63 per share, or a total initial purchase price of approximately $900 million. A final purchase price adjustment of $51 million was settled in cash on December 13, 2007. The basic and diluted earnings per share calculations shown below reflect the impact associated with these accelerated share repurchase programs.

Reconciliation of Basic and Diluted
Earnings per Share of Common Stock	2007		2006			2005
	(In millions, except per share amounts)
Income from continuing operations	$	1,309	$	1,258		$	879
Less: Redemption premium on subsidiary preferred stock		-		(9	)		-
Income from continuing operations available to common shareholders		1,309		1,249			879
Discontinued operations		-		(4	)		12
Income before cumulative effect of a change in accounting principle		1,309		1,245			891
Cumulative effect of a change in accounting principle		-		-			(30	)
Net income available for common shareholders	$	1,309	$	1,245		$	861
Average shares of common stock outstanding Basic		306		324			328
Assumed exercise of dilutive stock options and awards		4		3			2
Average shares of common stock outstanding Dilutive		310		327			330
Earnings per share:
Basic earnings per share:
Earnings from continuing operations	$	4.27	$	3.85		$	2.68
Discontinued operations		-		(0.01	)		0.03
Cumulative effect of change in accounting principle		-		-			(0.09	)
Net earnings per basic share	$	4.27	$	3.84		$	2.62
Diluted earnings per share:
Earnings from continuing operations	$	4.22	$	3.82		$	2.67
Discontinued operations		-		(0.01	)		0.03
Cumulative effect of change in accounting principle		-		-			(0.09	)
Net earnings per diluted share	$	4.22	$	3.81		$	2.61

71

(D) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment reflects original cost (except for nuclear generating assets which were adjusted to fair value in accordance with SFAS 144), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. Property, plant and equipment balances as of December 31, 2007 and 2006 were as follows:

	December 31, 2007									December 31, 2006
Property, Plant and Equipment	Unregulated			Regulated			Total			Unregulated			Regulated			Total
	(In millions)
In service	$	8,795		$	15,824		$	24,619		$	8,915		$	15,190		$	24,105
Less accumulated depreciation		(4,037	)		(6,311	)		(10,348	)		(4,014	)		(6,041	)		(10,055	)
Net plant in service	$	4,758		$	9,513		$	14,271		$	4,901		$	9,149		$	14,050

FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite rates for FirstEnergy's subsidiaries electric plant in 2007, 2006 and 2005 are shown in the following table:

	Annual Composite
	Depreciation Rate
	2007			2006			2005
OE		2.9	%		2.8	%		2.1	%
CEI		3.6			3.2			2.9
TE		3.9			3.8			3.1
Penn		2.3			2.6			2.4
JCP&L		2.1			2.1			2.2
Met-Ed		2.3			2.3			2.4
Penelec		2.3			2.3			2.6
FGCO		4.0			4.1			N/A
NGC		2.8			2.7			N/A

Jointly-Owned Generating Stations

JCP&L holds a 50% ownership interest in Yards Creek Pumped Storage Facility with a net book value of approximately $19.5 million as of December 31, 2007.

Asset Retirement Obligations

FirstEnergy recognizes a liability for retirement obligations associated with tangible assets in accordance with SFAS 143 and FIN 47. These standards require recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and depreciated over time, as described further in Note 12.

Nuclear Fuel

Property, plant and equipment includes nuclear fuel recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. Nuclear fuel is amortized based on the units of production method.

(E)   ASSET IMPAIRMENTS

Long-Lived Assets

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

72

Goodwill

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

FirstEnergy's 2006 annual review was completed in the third quarter of 2006 with no impairment indicated. As discussed in Note 10 to the consolidated financial statements, the PPUC issued its order on January 11, 2007 related to the comprehensive rate filing made by Met-Ed and Penelec on April 10, 2006. Prior to issuing the order, the PPUC conducted an informal, nonbinding polling of Commissioners at its public meeting on December 21, 2006 that indicated that the rate increase ultimately granted could be substantially lower than the amounts requested. As a result of the polling, FirstEnergy determined that an interim review of goodwill for its energy delivery services segment would be required. No impairment was indicated as a result of that review.

The forecasts used in FirstEnergy's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on FirstEnergy's future evaluations of goodwill. FirstEnergy's goodwill primarily relates to its energy delivery services segment. The impairment analysis includes a significant source of cash representing the Companies' recovery of transition costs as described in Note 10. FirstEnergy estimates that completion of transition cost recovery will not result in an impairment of goodwill relating to its energy delivery services segment.

A summary of the changes in FirstEnergy's goodwill for the three years ended December 31, 2007 is shown below by segment (see Note 16 - Segment Information):

						Ohio
	Energy			Competitive		Transitional
	Delivery			Energy		Generation
	Services			Services		Services		Other			Consolidated
						(In millions)
Balance as of January 1, 2005	$	5,951		$	24	$	-	$	75		$	6,050
Impairment charges									(9	)		(9	)
Non-core asset sales									(12	)		(12	)
Adjustments related to GPU acquisition		(10	)									(10	)
Adjustments related to Centerior acquisition		(9	)									(9	)
Balance as of December 31, 2005		5,932			24		-		54			6,010
Non-core asset sale									(53	)		(53	)
Adjustments related to Centerior acquisition		(1	)									(1	)
Adjustments related to GPU acquisition		(58	)									(58	)
Balance as of December 31, 2006		5,873			24		-		1			5,898
Adjustments related to GPU acquisition		(290	)									(290	)
Other									(1	)		(1	)
Balance as of December 31, 2007	$	5,583		$	24	$	-	$	-		$	5,607

Investments

At the end of each reporting period, FirstEnergy evaluates its investments for impairment. In accordance with SFAS 115 and FSP SFAS 115-1 and SFAS 124-1, investments classified as available-for-sale securities are evaluated to determine whether a decline in fair value below the cost basis is other-than-temporary. FirstEnergy first considers its intent and ability to hold the investment until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. If the decline in fair value is determined to be other-than-temporary, the cost basis of the investment is written down to fair value. Upon adoption of FSP SFAS 115-1 and SFAS 124-1, FirstEnergy began recognizing in earnings the unrealized losses on available-for-sale securities held in its nuclear decommissioning trusts since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of other-than-temporary impairment. The fair value and unrealized gains and losses of FirstEnergy's investments are disclosed in Note 5.

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(F)   COMPREHENSIVE INCOME

Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholders' equity except those resulting from transactions with stockholders and from the adoption of SFAS 158. As of December 31, 2007, AOCL consisted of a net liability for unfunded retirement benefits including the implementation of SFAS 158, net of income tax benefits (see Note 3) of $166 million, unrealized gains on investments in available-for-sale securities of $191 million and unrealized losses on derivative instrument hedges of $75 million. A summary of the changes in FirstEnergy's AOCL balance for the three years ended December 31, 2007 is shown below:

	2007			2006			2005
	(In millions)
AOCL balance as of January 1	$	(259	)	$	(20	)	$	(313	)
Minimum liability for unfunded retirement benefits		-			-			503
Pension and other postretirement benefits:
Prior service credit		(135	)		-			-
Actuarial gain		483			-			-
Unrealized gain (loss) on available for sale securities		78			109			(31	)
Unrealized gain (loss) on derivative hedges		(25	)		29			23
Other comprehensive income		401			138			495
Income taxes related to OCI		192			50			202
Other comprehensive income, net of tax		209			88			293
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $292 million of income tax benefits		-			(327	)		-
AOCL balance as of December 31	$	(50	)	$	(259	)	$	(20	)

Other comprehensive income (loss) reclassified to net income in the three years ended December 31, 2007 is as follows:

	2007			2006			2005
	(In millions)
Pension and other postretirement benefits, net of income tax
benefits of $20 million	$	(25	)	$	-		$	-
Gain (loss) on available for sale securities, net of income taxes         (benefits) of $(6) million, $11 million and $27 million, respectively		(10	)		16			40
Loss on derivative hedges, net of income tax benefits of $10 million,
$12 million and $8 million, respectively		(16	)		(20	)		(12	)
	$	(51	)	$	(4	)	$	28

(G)   CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE

Results in 2005 included an after-tax charge of $30 million recorded upon the adoption of FIN 47 in December 2005. FirstEnergy identified applicable legal obligations as defined under FIN 47 at its active and retired generating units, substation control rooms, service center buildings, line shops and office buildings, identifying asbestos as the primary conditional ARO. FirstEnergy recorded a conditional ARO liability of $57 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $16 million (recorded as part of the carrying amount of the related long-lived asset), and accumulated depreciation of $12 million. FirstEnergy charged regulatory liabilities for $5 million upon adoption of FIN 47 for the transition amounts related to establishing the ARO for asbestos removal from substation control rooms and service center buildings for OE, Penn, CEI, TE and JCP&L. The remaining cumulative effect adjustment for unrecognized depreciation and accretion of $48 million was charged to income ($30 million, net of tax), or $0.09 per share of common stock (basic and diluted) for the year ended December 31, 2005 (see Note 12).

3.      PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy's funding policy is based on actuarial computations using the projected unit credit method. On January 2, 2007, FirstEnergy made a $300 million voluntary cash contribution to its qualified pension plan. Projections indicate that additional cash contributions will not be required before 2017.

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

Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans and earnings on plan assets. Such factors may be further affected by business combinations which impact employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of December 31, 2007.

In December 2006, FirstEnergy adopted SFAS 158. This Statement requires employers to recognize an asset or liability for the overfunded or underfunded status of their pension and other postretirement benefit plans. For a pension plan, the asset or liability is the difference between the fair value of the plans assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plans assets and the accumulated postretirement benefit obligation. The Statement required employers to recognize all unrecognized prior service costs and credits and unrecognized actuarial gains and losses in AOCL, net of tax. Such amounts will be adjusted as they are subsequently recognized as components of net periodic benefit cost or income pursuant to the current recognition and amortization provisions. The incremental impact of adopting SFAS 158 was a decrease of $1.0 billion in pension assets, a decrease of $383 million in pension liabilities and a decrease in AOCL of $327 million, net of tax.

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Obligations and Funded Status	Pension Benefits						Other Benefits
As of December 31	2007			2006			2007			2006
	(In millions)
Change in benefit obligation
Benefit obligation as of January 1	$	5,031		$	4,911		$	1,201		$	1,884
Service cost		88			87			21			34
Interest cost		294			276			69			105
Plan participants contributions		-			-			23			20
Plan amendments		-			-			-			(620	)
Medicare retiree drug subsidy		-			-			-			6
Actuarial (gain) loss		(381	)		38			(30	)		(119	)
Benefits paid		(282	)		(281	)		(102	)		(109	)
Benefit obligation as of December 31	$	4,750		$	5,031		$	1,182		$	1,201
Change in fair value of plan assets
Fair value of plan assets as of January 1	$	4,818		$	4,525		$	607		$	573
Actual return on plan assets		438			567			43			69
Company contribution		311			7			47			54
Plan participants contribution		-			-			23			20
Benefits paid		(282	)		(281	)		(102	)		(109	)
Fair value of plan assets as of December 31	$	5,285		$	4,818		$	618		$	607
Qualified plan	$	700		$	(43	)
Non-qualified plans		(165	)		(170	)
Funded status	$	535		$	(213	)	$	(564	)	$	(594	)
Accumulated benefit obligation	$	4,397		$	4,585
Amounts Recognized in the Statement of
Financial Position
Noncurrent assets	$	700		$	-		$	-		$	-
Current liabilities		(7	)		(7	)		-			-
Noncurrent liabilities		(158	)		(206	)		(564	)		(594	)
Net asset (liability) as of December 31	$	535		$	(213	)	$	(564	)	$	(594	)
Amounts Recognized in
Accumulated Other Comprehensive Income
Prior service cost (credit)	$	83		$	97		$	(1,041	)	$	(1,190	)
Actuarial loss		623			1,039			635			702
Net amount recognized	$	706		$	1,136		$	(406	)	$	(488	)
Assumptions Used to Determine
Benefit Obligations As of December 31
Discount rate		6.50	%		6.00	%		6.50	%		6.00	%
Rate of compensation increase		5.20	%		3.50	%
Allocation of Plan Assets
As of December 31
Asset Category
Equity securities		61	%		64	%		69	%		72	%
Debt securities		30			29			27			26
Real estate		7			5			2			1
Private equities		1			1			-			-
Cash		1			1			2			1
Total		100	%		100	%		100	%		100	%

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Estimated Items to be Amortized in 2008
Net Periodic Pension Cost from	Pension		Other
Accumulated Other Comprehensive Income	Benefits		Benefits
	(In millions)
Prior service cost (credit)	$	13	$	(149	)
Actuarial loss	$	8	$	47

	Pension Benefits									Other Benefits
Components of Net Periodic Benefit Costs (Credit)	2007			2006			2005			2007			2006			2005
	(In millions)
Service cost	$	88		$	87		$	80		$	21		$	34		$	40
Interest cost		294			276			262			69			105			111
Expected return on plan assets		(449	)		(396	)		(345	)		(50	)		(46	)		(45	)
Amortization of prior service cost		13			13			10			(149	)		(76	)		(45	)
Recognized net actuarial loss		45			62			39			45			56			40
Net periodic cost (credit)	$	(9	)	$	42		$	46		$	(64	)	$	73		$	101
Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost	Pension Benefits									Other Benefits
for Years Ended December 31	2007			2006			2005			2007			2006			2005
Discount rate		6.00	%		5.75	%		6.00	%		6.00	%		5.75	%		6.00	%
Expected long-term return on plan assets		9.00	%		9.00	%		9.00	%		9.00	%		9.00	%		9.00	%
Rate of compensation increase		3.50	%		3.50	%		3.50	%

In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. The assumed rates of return on pension plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy's pension trusts. The long-term rate of return is developed considering the portfolios asset allocation strategy.

FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

FirstEnergy has assessed the impact of recent market developments, including a series of rating agency downgrades of subprime mortgage-related assets, on the value of the assets held in its pension and other postretirement benefit trusts. Based on this assessment, FirstEnergy believes that the fair value of its investments as of December 31, 2007 will not be materially affected by the subprime credit crisis due to their relatively small exposure to subprime assets.

Assumed Health Care Cost Trend Rates
As of December 31	2007			2006
Health care cost trend rate assumed for next
year (pre/post-Medicare)		9-11	%		9-11	%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)		5	%		5	%
Year that the rate reaches the ultimate trend
rate (pre/post-Medicare)		2015-2017			2011-2013

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

	1-Percentage-		1-Percentage-
	Point Increase		Point Decrease
	(In millions)
Effect on total of service and interest cost	$	5	$	(4	)
Effect on accumulated postretirement benefit obligation	$	48	$	(42	)

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Taking into account estimated employee future service, FirstEnergy expects to make the following pension benefit payments from plan assets and other benefit payments, net of the Medicare subsidy:

	Pension		Other
	Benefits		Benefits
	(In millions)
2008	$	300	$	83
2009		300		86
2010		307		90
2011		313		94
2012		322		95
Years 2013- 2017		1,808		495

4.      STOCK-BASED COMPENSATION PLANS

FirstEnergy has four stock-based compensation programs: LTIP; EDCP; ESOP; and DCPD. FirstEnergy has also assumed responsibility for several stock-based plans through acquisitions. In 2001, FirstEnergy assumed responsibility for two stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under GPUs Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010.

Effective January 1, 2006, FirstEnergy adopted SFAS 123(R), which requires the expensing of stock-based compensation. Under SFAS 123(R), all share-based compensation cost is measured at the grant date based on the fair value of the award, and is recognized as an expense over the employees requisite service period. FirstEnergy adopted the modified prospective method, under which compensation expense recognized in the year ended December 31, 2006 included the expense for all share-based payments granted prior to but not yet vested as of January 1, 2006. Results for prior periods were not restated.

Prior to the adoption of SFAS 123(R) on January 1, 2006, FirstEnergy's LTIP, EDCP, ESOP, and DCPD stock-based compensation programs were accounted for under the recognition and measurement principles of APB 25 and related interpretations.  Under APB 25, no compensation expense was reflected in net income for stock options as all options granted under those plans have exercise prices equal to the market value of the underlying common stock on the respective grant dates, resulting in substantially no intrinsic value. The pro forma effects on net income for stock options were instead disclosed in a footnote to the financial statements. Under APB 25 and SFAS 123(R), compensation expense was recorded in the income statement for restricted stock, restricted stock units, performance shares and the EDCP and DCPD programs. No stock options have been granted since the third quarter of 2004. Consequently, the impact of adopting SFAS 123(R) was not material to FirstEnergy's net income and earnings per share in the three years ended December 31, 2007.

        (A)    LTIP

FirstEnergy's LTIP includes four stock-based compensation programs restricted stock, restricted stock units, stock options, and performance shares. During 2005, FirstEnergy began issuing restricted stock units and reduced its use of stock options.

Under FirstEnergy's LTIP, total awards cannot exceed 29.1 million shares of common stock or their equivalent. Only stock options, restricted stock and restricted stock units have currently been designated to pay out in common stock, with vesting periods ranging from two months to ten years. Performance share awards are currently designated to be paid in cash rather than common stock and therefore do not count against the limit on stock-based awards. As of December 31, 2007, 9.3 million shares were available for future awards.

Restricted Stock and Restricted Stock Units

Eligible employees receive awards of FirstEnergy common stock or stock units subject to restrictions. Those restrictions lapse over a defined period of time or based on performance. Dividends are received on the restricted stock and are reinvested in additional shares. Restricted common stock grants under the LTIP were as follows:

	2007		2006		2005
Restricted common shares granted		77,388		229,271		356,200
Weighted average market price	$	67.98	$	53.18	$	41.52
Weighted average vesting period (years)		4.61		4.47		5.4
Dividends restricted	Yes		Yes		Yes

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Vesting activity for restricted common stock during the year was as follows:

			Weighted
	Number		Average
	of		Grant-Date
Restricted Stock	Shares		Fair Value
Nonvested as of January 1, 2007		629,482		$	45.79
Nonvested as of December 31, 2007		639,657			48.69
Vested in 2007		67,063			65.02

FirstEnergy grants two types of restricted stock unit awards -- discretionary-based and performance-based. With the discretionary-based, FirstEnergy grants the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of restricted stock units set forth in each agreement. With performance-based, FirstEnergy grants the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of restricted stock units set forth in the agreement subject to adjustment based on FirstEnergy's stock performance.

	2007		2006		2005
Restricted common share units granted		412,426		440,676		477,920
Weighted average vesting period (years)		3.22		3.32		3.32

Vesting activity for restricted stock units during the year was as follows:

			Weighted
	Number		Average
	of		Grant-Date
Restricted Stock Units	Shares		Fair Value
Nonvested as of January 1, 2007		887,794		$	45.97
Nonvested as of December 31, 2007		1,208,780			51.09
Granted during 2007		412,426			62.25
Vested in 2007		10,603			62.87

Compensation expense recognized in 2007, 2006 and 2005 for restricted stock and restricted stock units was approximately $30 million, $17 million and $10 million, respectively.

Stock Options

Stock options were granted to eligible employees allowing them to purchase a specified number of common shares at a fixed grant price over a defined period of time. Stock option activities under FirstEnergy stock option programs for the past three years were as follows:

			Weighted
	Number		Average
	of		Exercise
Stock Option Activities	Options		Price
Balance, January 1, 2005		13,232,755	$	32.40
(3,175,023 options exercisable)				29.07
Options granted		-		-
Options exercised		4,140,893		29.79
Options forfeited		225,606		34.37
Balance, December 31, 2005		8,866,256		33.57
(4,090,829 options exercisable)				31.97
Options granted		-		-
Options exercised		2,221,417		32.65
Options forfeited		26,550		33.36
Balance, December 31, 2006		6,618,289		33.88
(4,160,859 options exercisable)				32.85
Options granted		-		-
Options exercised		1,902,780		32.51
Options forfeited		9,575		38.39
Balance, December 31, 2007		4,705,934		34.42
(3,915,694 options exercisable)				33.55

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Options outstanding by plan and range of exercise price as of December 31, 2007 were as follows:

			Options Outstanding						Options Exercisable
					Weighted						Weighted
	Range of				Average		Remaining				Average
Program	Exercise Prices		Shares		Exercise Price		Contractual Life		Shares		Exercise Price
FE Plan	$	19.31 - $29.87		1,682,609	$	29.15		4.50		1,682,609	$	29.15
	$	30.17 - $39.46		3,004,290	$	37.44		5.57		2,214,050	$	36.96
GPU Plan	$	23.75 - $35.92		19,035	$	24.47		2.35		19,035	$	24.27
Total				4,705,934	$	34.42		5.17		3,915,694	$	33.55

Prior to the adoption of SFAS 123(R) compensation expense for FirstEnergy stock options was based on intrinsic value, which equals any positive difference between FirstEnergy's common stock price on the option's grant date and the option's exercise price. The exercise prices of all stock options granted in prior years equaled the market price of FirstEnergy's common stock on the options' grant dates. If fair value accounting were applied to FirstEnergy's stock options, net income and earnings per share in 2005 would have been reduced as summarized below.

	2005
	(In millions, except per share amounts)
Net Income, as reported	$	861
Add back compensation expense
reported in net income, net of tax
(based on APB 25)*		32
Deduct compensation expense based
upon estimated fair value, net of tax*		(39	)
Pro forma net income	$	854
Earnings Per Share of Common Stock -
Basic
As Reported	$	2.62
Pro Forma	$	2.60
Diluted
As Reported	$	2.61
Pro Forma	$	2.59

* Includes restricted stock, restricted stock units, stock options, performance shares, ESOP, EDCP and DCPD.

As noted above, FirstEnergy reduced its use of stock options beginning in 2005 and increased its use of performance-based, restricted stock units. FirstEnergy did not accelerate out-of-the-money options in anticipation of adopting SFAS 123(R) on January 1, 2006. As a result, all currently unvested stock options will vest by 2008. Compensation expense recognized for stock options during 2007 was approximately $1 million.

Performance Shares

Performance shares are share equivalents and do not have voting rights. The shares track the performance of FirstEnergy's common stock over a three-year vesting period. During that time, dividend equivalents are converted into additional shares. The final account value may be adjusted based on the ranking of FirstEnergy stock performance to a composite of peer companies. Compensation expense recognized for performance shares during 2007, 2006 and 2005 totaled approximately $20 million, $25 million and $7 million, respectively.

(B)   ESOP

An ESOP Trust funded most of the matching contribution for FirstEnergy's 401(k) savings plan through December 31, 2007. All full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. Between 1990 and 1991, the ESOP borrowed $200 million from OE and acquired 10,654,114 shares of OE's common stock (subsequently converted to FirstEnergy common stock) through market purchases. Dividends on ESOP shares were used to service the debt. Shares were released from the ESOP on a pro rata basis as debt service payments were made.

In determining the amount of borrowing under the ESOP, assumptions were made including the size and growth rate of FirstEnergy's workforce, earnings, dividends, and trading price of common stock. In 2005, the ESOP loan was refinanced ($66 million principal amount) and its term was extended by three years. In 2007, 2006 and 2005, 521,818 shares, 922,978 shares and 588,004 shares, respectively, were allocated to employees with the corresponding expense recognized based on the shares allocated method. All shares had been allocated as of December 31, 2007.  Total ESOP-related compensation expense was calculated as follows:

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	2007			2006			2005
	(In millions)
Base compensation	$	36		$	50		$	39
Dividends on common stock held by the ESOP and used to service debt		(11	)		(11	)		(10	)
Net expense	$	25		$	39		$	29

(C)   EDCP

Under the EDCP, covered employees can direct a portion of their compensation, including annual incentive awards and/or long-term incentive awards, into an unfunded FirstEnergy stock account to receive vested stock units or into an unfunded retirement cash account. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy stock account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement (see Note 3). Interest is calculated on the cash allocated to the cash account and the total balance will pay out in cash upon retirement. Of the 1.3 million EDCP stock units authorized, 606,659 stock units were available for future awards as of December 31, 2007. Compensation expense recognized on EDCP stock units was approximately $7 million in 2007 and approximately $5 million in 2006 and 2005, respectively.

        (D)   DCPD

Under the DCPD, directors can elect to allocate all or a portion of their cash retainers, meeting fees and chair fees to deferred stock or deferred cash accounts. If the funds are deferred into the stock account, a 20% match is added to the funds allocated. The 20% match and any appreciation on it are forfeited if the director leaves the Board within three years from the date of deferral for any reason other than retirement, disability, death, upon a change in control, or when a director is ineligible to stand for re-election. Compensation expense is recognized for the 20% match over the three-year vesting period. Directors may also elect to defer their equity retainers into the deferred stock account; however, they do not receive a 20% match on that deferral. DCPD expenses recognized in each of 2007, 2006 and 2005 were approximately $3 million. The net liability recognized for DCPD of $5 million as of December 31, 2007 and 2006 is included in the caption retirement benefits on the Consolidated Balance Sheets.

5.      FAIR VALUE OF FINANCIAL INSTRUMENTS

        (A)   LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS

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

	2007						2006
	Carrying			Fair			Carrying			Fair
	Value			Value			Value			Value
	(In millions)
Long-term debt		$	10,891		$	11,131		$	10,321		$	10,725
Subordinated debentures to affiliated trusts			-			-			103			105
		$	10,891		$	11,131		$	10,424		$	10,830

The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to the Companies' ratings.

        (B)   INVESTMENTS

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities. The Companies and NGC periodically evaluate their investments for other-than-temporary impairment. They first consider their intent and ability to hold the investment until recovery and then consider, among other factors, the duration and the extent to which the securitys fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment.

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FirstEnergy has assessed the impact of recent market developments, including a series of rating agency downgrades of subprime mortgage-related assets, on the value of the assets held in its nuclear decommissioning trusts. Based on this assessment, FirstEnergy believes that the fair value of its investments as of December 31, 2007 will not be materially affected by the subprime credit crisis due to their relatively small exposure to subprime assets.

Available-For-Sale Securities

The Companies and NGC hold debt and equity securities within their nuclear decommissioning trusts, nuclear fuel disposal trusts and NUG trusts. These trust investments are classified as available-for-sale with the fair value representing quoted market prices. FirstEnergy has no securities held for trading purposes.

The following table provides the carrying value, which approximates fair value, of investments in available-for-sale securities as of December 31, 2007 and 2006. The fair value was determined using the specific identification method.

		2007		2006
		(In millions)
Debt securities:
Government obligations (1)(2)	$	851	$	788
Corporate debt securities		191		153
Mortgage-backed securities		17		12
		1,059		953
Equity securities		1,355		1,284
	$	2,414	$	2,237
(1)         Excludes $3 million and $5 million of cash in 2007 and 2006, respectively.
(2)   Excludes $2 million of receivables and payables in 2006.

The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities as of December 31:

	2007								2006
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt securities	$	1,036	$	27	$	4	$	1,059	$	948	$	10	$	5	$	953
Equity securities		995		360		-		1,355		952		332		-		1,284
	$	2,031	$	387	$	4	$	2,414	$	1,900	$	342	$	5	$	2,237

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income for the three years ended December 31, 2007 were as follows:

	2007		2006		2005
	(In millions)
Proceeds from sales	$	1,294	$	1,651	$	1,587
Realized gains		103		121		133
Realized losses		53		105		60
Interest and dividend income		80		70		62

Upon adoption of FSP SFAS 115-1 and SFAS 124-1, FirstEnergy began expensing unrealized losses on available-for-sale securities held in its nuclear decommissioning trusts since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of other-than-temporary impairment.

Unrealized gains applicable to OE's, TE's and the majority of NGC's decommissioning trusts are recognized in OCI in accordance with SFAS 115, as fluctuations in fair value will eventually impact earnings. The decommissioning trusts of JCP&L, Met-Ed and Penelec are subject to regulatory accounting in accordance with SFAS 71. Net unrealized gains and losses are recorded as regulatory assets or liabilities since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers.

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

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Held-To-Maturity Securities

The following table provides the approximate fair value and related carrying amounts of investments in held-to-maturity securities, which excludes investments of $314 million and $323 million for 2007 and 2006, respectively, excluded by SFAS 107, Disclosures about Fair Values of Financial Instruments, as of December 31:

	2007				2006
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Lease obligations bonds	$	717	$	814	$	811	$	908
Debt securities		73		73		66		69
Notes receivable		45		43		70		67
Restricted funds		3		3		11		11
Equity securities		29		29		9		9
	$	867	$	962	$	967	$	1,064

The fair value of investments in lease obligation bonds is based on the present value of the cash inflows based on the yield to maturity. The maturity dates range from 2008 to 2017. The carrying value of the restricted funds is assumed to approximate market value. The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. The maturity dates range from 2008 to 2040.

The following table provides the amortized cost basis, unrealized gains and losses, and fair values of investments in held-to-maturity securities excluding the restricted funds and notes receivable as of December 31:

	2007								2006
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt securities	$	790	$	97	$	-	$	887	$	877	$	100	$	-	$	977
Equity securities		29		-		-		29		9		-		-		9
	$	819	$	97	$	-	$	916	$	886	$	100	$	-	$	986

        (C)   DERIVATIVES

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

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

FirstEnergy hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases, capital assets denominated in foreign currencies and anticipated interest payments associated with future debt issues. Other than interest-related hedges, FirstEnergy's maximum hedge term is typically two years.  The effective portions of all cash flow hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings.

The net deferred losses of $75 million included in AOCL as of December 31, 2007, for derivative hedging activity, as compared to $58 million as of December 31, 2006, resulted from a net $33 million increase related to current hedging activity and a $16 million decrease due to net hedge losses reclassified to earnings during 2007. Based on current estimates, approximately $24 million (after tax) of the net deferred losses on derivative instruments in AOCL as of December 31, 2007 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.

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FirstEnergy has entered into swaps that have been designated as fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. During 2007, FirstEnergy unwound swaps with a total notional value of $500 million, for which it incurred $2 million in cash losses that will be recognized as interest expense over the remaining maturity of each hedged security. As of December 31, 2007, FirstEnergy had interest rate swaps with an aggregate notional value of $250 million and a fair value of $(3) million.

During 2007, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated issuances of fixed-rate, long-term debt securities for one or more of its subsidiaries as outstanding debt matures during 2008. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During 2007, FirstEnergy terminated swaps with a notional value of $2.5 billion for which it paid $30 million, $1.6 million of which was deemed ineffective and recognized in current period earnings. FirstEnergy will recognize the remaining $28 million loss over the life of the associated future debt. As of December 31, 2007, FirstEnergy had forward swaps with an aggregate notional amount of $400 million and a fair value of $(3) million.

6. LEASES

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

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion (net after-tax proceeds of approximately $1.2 billion) for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034.  A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates.  The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO's obligations under each of the leases. This transaction, which is classified as an operating lease under GAAP for FES and FirstEnergy, generated tax capital gains of approximately $742 million, all of which were offset by existing tax capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowances in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 2(E)).

In 1987, OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. In that same year, CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respective leases, OE, CEI and TE continue to be responsible, to the extent of their leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. They have the right, at the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes.

Effective October 16, 2007 CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. FGCO assumed all of CEIs and TEs 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.

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Rentals for capital and operating leases for the three years ended December 31, 2007 are summarized as follows:

	2007		2006		2005
	(In millions)
Operating leases
Interest element	$	180	$	160	$	171
Other		196		190		162
Capital leases
Interest element		-		1		1
Other		1		2		2
Total rentals	$	377	$	353	$	336

Established by OE in 1996, PNBV purchased a portion of the lease obligation bonds issued on behalf of lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. Similarly, CEI and TE established Shippingport in 1997 to purchase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV and Shippingport arrangements effectively reduce lease costs related to those transactions (see Note 7).

The future minimum lease payments as of December 31, 2007 are:

			Operating Leases
	Capital		Lease		Capital
	Leases		Payments		Trusts		Net
	(In millions)
2008	$	1	$	419	$	103	$	316
2009		1		424		107		317
2010		1		425		116		309
2011		1		417		116		301
2012		1		457		125		332
Years thereafter		1		3,622		384		3,238
Total minimum lease payments		6	$	5,764	$	951	$	4,813
Executory costs		-
Net minimum lease payments		6
Interest portion		1
Present value of net minimum
lease payments		5
Less current portion		1
Noncurrent portion	$	4

FirstEnergy has recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger between OE and Centerior. The total above-market lease obligation of $722 million associated with Beaver Valley Unit 2 is being amortized on a straight-line basis through the end of the lease term in 2017 (approximately $37 million per year). The total above-market lease obligation of $755 million associated with the Bruce Mansfield Plant is being amortized on a straight-line basis through the end of 2016 (approximately $46 million per year). As of December 31, 2007, the above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant totaled $746 million, of which $83 million is classified in the caption other current liabilities.

7. VARIABLE INTEREST ENTITIES

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

Trusts

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

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

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Loss Contingencies

FES and the Ohio Companies are exposed to losses under their applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments are made. The following table shows each companys net exposure to loss based upon the casualty value provisions mentioned above:

	Maximum Exposure		Discounted Lease Payments, net		Net Exposure
	(in millions)
FES	$	1,338	$	1,198	$	140
OE		837		610		227
CEI		753		85		668
TE		753		449		304

Effective October 16, 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant under their 1987 sale and leaseback transactions to FGCO.  FGCO assumed all of CEIs and TEs 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 discussed above, 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 assignments terminate automatically upon the termination of the underlying leases.

Power Purchase Agreements

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

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

Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it incurs for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. As of December 31, 2007, the net above-market loss liability projected for these eight NUG agreements was approximately $74 million. Purchased power costs from these entities during 2007, 2006 and 2005 were $177 million, $171 million, and $180 million, respectively.

8.     DISCONTINUED OPERATIONS

In March 2005, FirstEnergy sold 51% of its interest in FirstCom, resulting in an after-tax gain of $4 million.  FirstEnergy accounted for its remaining 31.85% interest in FirstCom on the equity basis until July 2007 when FirstEnergy's ownership interest decreased to approximately 15% and FirstEnergy began accounting for its investment under the cost method.

In 2006, FirstEnergy sold its remaining FSG subsidiaries (Roth Bros., Hattenbach, Dunbar, Edwards and RPC) for an aggregate net after-tax gain of $2.2 million. Hattenbach, Dunbar, Edwards, and RPC were accounted for as discontinued operations as of December 31, 2006; Roth Bros. did not meet the criteria for that classification as of December 31, 2006.

In 2005, three FSG subsidiaries, Elliott-Lewis, Spectrum Control Systems and L.H. Cranston & Sons, and MYR's Power Piping Company subsidiary were sold resulting in an after-tax gain of $13 million. All of these sales, except the Spectrum Control Systems, met the criteria for discontinued operations at December 31, 2005. On March 31, 2005, FES sold its natural gas business for an after-tax gain of $5 million and was included in discontinued operations at December 31, 2005.

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In December 2005, MYR had qualified as an asset held for sale but did not meet the criteria to be classified as discontinued operations. As required by SFAS 142, the goodwill of MYR was tested for impairment, resulting in a non-cash charge of $9 million in the fourth quarter of 2005 (see Note 2(E)). The carrying amounts of MYR's assets and liabilities as of December 31, 2005 held for sale were not material and had not been classified as assets held for sale on FirstEnergy's Consolidated Balance Sheet.

In March 2006, FirstEnergy sold 60% of its interest in MYR for an after-tax gain of $0.2 million. In June 2006, as part of the March agreement, FirstEnergy sold an additional 1.67% interest. As a result of the March sale, FirstEnergy deconsolidated MYR in the first quarter of 2006 and accounted for its remaining 38.33% interest under the equity method of accounting for investments. In the fourth quarter of 2006, FirstEnergy sold its remaining MYR interest for an after-tax gain of $8.6 million. The income for the period that MYR was accounted for as an equity method investment has not been included in discontinued operations; however, results for all reporting periods prior to the initial sale in March 2006, including the gain on the sale, were reported as discontinued operations.

Revenues associated with discontinued operations were $225 million and $845 million in 2006 and 2005, respectively. The following table summarizes the net income operating results of discontinued operations for 2006 and 2005:

	2006			2005
	(In millions)
Income (loss) before income taxes	$	(4	)	$	(1	)
Income tax expense		(2	)		(5	)
Gain (loss) on sale, net of tax		2			18
Income (loss) from discontinued operations	$	(4	)	$	12

9.     TAXES

Income Taxes

FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and loss carryforwards and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. Details of income taxes for the three years ended December 31, 2007 are shown below:

For the Years Ended December 31,	2007			2006			2005
	(In millions)
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	706		$	519		$	452
State		187			116			142
		893			635			594
Deferred, net-
Federal		22			147			72
State		(18	)		28			110
		4			175			182
Investment tax credit amortization		(14	)		(15	)		(27	)
Total provision for income taxes	$	883		$	795		$	749
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	2,192		$	2,053		$	1,628
Federal income tax expense at statutory rate	$	767		$	719		$	569
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits		(14	)		(15	)		(27	)
State income taxes, net of federal income tax benefit		110			94			165
Penalties		-			-			14
Amortization of tax regulatory assets		8			2			38
Preferred stock dividends		-			5			5
Other, net		12			(10	)		(15	)
Total provision for income taxes	$	883		$	795		$	749

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Accumulated deferred income taxes as of December 31, 2007 and 2006 are as follows:

As of December 31,	2007			2006
	(In millions)
Property basis differences	$	2,502		$	2,595
Regulatory transition charge		706			457
Customer receivables for future income taxes		149			141
Deferred customer shopping incentive		263			219
Deferred sale and leaseback gain		(536	)		(86	)
Nonutility generation costs		(90	)		(122	)
Unamortized investment tax credits		(44	)		(50	)
Other comprehensive income		(68	)		(260	)
Retirement benefits		(9	)		10
Lease market valuation liability		(283	)		(331	)
Oyster Creek securitization (Note 11(C))		149			162
Loss carryforwards		(44	)		(426	)
Loss carryforward valuation reserve		31			415
Asset retirement obligations		35			45
Nuclear decommissioning		(169	)		(116	)
All other		79			87
Net deferred income tax liability	$	2,671		$	2,740

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

As of January 1, 2007, the total amount of FirstEnergy's unrecognized tax benefits was $268 million. FirstEnergy recorded a $2.7 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy's effective tax rate upon recognition. The majority of items that would not have affected the effective tax rate resulted from purchase accounting adjustments that would reduce goodwill upon recognition through December 31, 2008.

A reconciliation of the change in the unrecognized tax benefits for the year ended December 31, 2007 is as follows:

	(In millions)
Balance as of January 1, 2007	$	268
Increase for tax positions related to the current year		1
Increase for tax positions related to prior years		3
Balance as of December 31, 2007	$	272

As of December 31, 2007, FirstEnergy expects that $7 million of the unrecognized benefits will be resolved within the next twelve months and is included in the caption accrued taxes, with the remaining $265 million included in the caption other non-current liabilities on the Consolidated Balance Sheets.

FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. During the years ended December 31, 2007, 2006 and 2005, FirstEnergy recognized net interest expense of approximately $19 million, $9 million and $6 million, respectively. The cumulative net interest accrued as of December 31, 2007 and 2006 was $53 million and $34 million, respectively.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2006. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audit for years 2004 and 2005 began in June 2006 and is not expected to close before December 2008. The IRS began auditing the year 2006 in April 2006 and the year 2007 in February 2007 under its Compliance Assurance Process experimental program. Neither audits are expected to close before December 2008. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy's financial condition or results of operations.

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On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity (see Note 6). This transaction generated tax capital gains of approximately $742 million, all of which were offset by existing tax capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowance in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 2(E)).

FirstEnergy has pre-tax net operating loss carryforwards for state and local income tax purposes of approximately $1.156 billion of which $199 million is expected to be utilized. The associated deferred tax assets are $13 million. These losses expire as follows:

Expiration Period	Amount
	(In millions)
2008-2012	$	331
2013-2017		16
2018-2022		462
2023-2027		347
	$	1,156

General Taxes

Details of general taxes for the three years ended December 31, 2007 are shown below:

For the Years Ended December 31,	2007		2006		2005
	(In millions)
GENERAL TAXES:
Real and personal property	$	237	$	222	$	222
Kilowatt-hour excise		250		241		244
State gross receipts		175		159		151
Social security and unemployment		87		83		79
Other		5		15		17
Total general taxes	$	754	$	720	$	713

Commercial Activity Tax

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

The increase to income taxes associated with the adjustment to net deferred taxes in 2005 is summarized below (in millions):

OE	$	32
CEI		4
TE		18
Other FirstEnergy subsidiaries		(2	)
Total FirstEnergy	$	52

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Income tax expenses were reduced (increased) during 2005 by the initial phase-out of the Ohio income-based franchise tax and phase-in of the CAT tax as summarized below (in millions):

OE	$	3
CEI		5
TE		1
Other FirstEnergy subsidiaries		(3	)
Total FirstEnergy	$	6

10.   REGULATORY MATTERS

(A)   RELIABILITY INITIATIVES

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. Canada Power System Outage Task Force) regarding enhancements to regional reliability. 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.

As a result of outages experienced in JCP&Ls service area in 2002 and 2003, the NJBPU performed a review of JCP&Ls 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&Ls 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 consultants 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&Ls 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.

(B)   OHIO

On September 9, 2005, the Ohio Companies filed their RCP with the PUCO. The filing included a stipulation and supplemental stipulation with several parties agreeing to the provisions set forth in the plan. On January 4, 2006, the PUCO issued an order which approved the 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.

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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 PUCOs 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.

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 utilitys total load notwithstanding the customers 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.

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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.

(C)   PENNSYLVANIA

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 day's 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-Ed's 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-Ed's non-NUG stranded costs. The order decreased Met-Ed's and Penelec's distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed's 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.

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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.

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-Ed's and Penelec's NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in February 2007 and briefing was completed on March 28, 2007. The ALJs initial decision denied Met-Ed's and Penelec's request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. 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 companys 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 Governors 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.

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(D)   NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of December 31, 2007, the accumulated deferred cost balance totaled approximately $322 million.

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 Governors Office and the Governors 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 Jerseys 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.

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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.

(E)    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. FERCs 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 ALJs decision and recommendations.  On April 19, 2007, the FERC issued an order rejecting the ALJs 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 PJMs 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.

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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.

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.

MISOs 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 FERCs 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 MISOs 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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Duquesnes 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 PJMs forward capacity market.  FirstEnergy believes that Duquesnes filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesnes proposal. Consequently, on December 4, 2007 and January 3, 2008, FirstEnergy submitted responsive filings that, while conceding Duquesnes rights to exit PJM, contested various aspects of Duquesnes proposal.  FirstEnergy particularly focused on Duquesnes proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesnes 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 Duquesnes 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 Duquesnes plans.

On January 17, 2008, the FERC conditionally approved Duquesnes 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 Owners Agreement. The FERC likewise directed the MISO to submit a compliance filing in forty-five days (or by March 3, 2008) detailing the MISOs 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 Duquesnes transition into the MISO.  On February 19, 2008, we 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.

11.   CAPITALIZATION

        (A)   COMMON STOCK

Retained Earnings and Dividends

As of December 31, 2007, FirstEnergy's unrestricted retained earnings were $3.5 billion. In addition to paying dividends from retained earnings, each of FirstEnergy's electric utility subsidiaries has authorization from the FERC to pay cash dividends to FirstEnergy from paid-in capital accounts, as long as its equity to total capitalization ratio (without consideration of retained earnings) remains above 35%. The articles of incorporation, indentures and various other agreements relating to the long-term debt and preferred stock of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock. With the exception of Met-Ed, which is currently in an accumulated deficit position, none of these provisions materially restricted FirstEnergy's subsidiaries ability to pay cash dividends to FirstEnergy as of December 31, 2007.

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On December 18, 2007, the Board of Directors increased the indicated annual common stock dividend to $2.20 per share, payable quarterly at a rate of $0.55 per share beginning in the first quarter of 2008. Dividends declared in 2007 were $2.05, which included three quarterly dividends of $0.50 per share paid in the second, third and fourth quarters of 2007 and a quarterly dividend of $0.55 per share payable in the first quarter of 2008. Dividends declared in 2006 were $1.85, which included three quarterly dividends of $0.45 per share paid in the second, third and fourth quarters of 2006 and a quarterly dividend of $0.50 per share paid in the first quarter of 2007. The amount and timing of all dividend declarations are subject to the discretion of the Board and its consideration of business conditions, results of operations, financial condition and other factors.

(B)   PREFERRED AND PREFERENCE STOCK

FirstEnergy's and the Companies preferred stock and preference stock authorizations are as follows:

	Preferred Stock				Preference Stock
	Shares		Par		Shares		Par
	Authorized		Value		Authorized		Value
FirstEnergy		5,000,000	$	100
OE		6,000,000	$	100		8,000,000	no par
OE		8,000,000	$	25
Penn		1,200,000	$	100
CEI		4,000,000	no par			3,000,000	no par
TE		3,000,000	$	100		5,000,000	$	25
TE		12,000,000	$	25
JCP&L		15,600,000	no par
Met-Ed		10,000,000	no par
Penelec		11,435,000	no par

No preferred shares or preference shares are currently outstanding. The following table details the change in preferred shares outstanding for the three years ended December 31, 2007.

	Not Subject to						Subject to
	Mandatory Redemption						Mandatory Redemption
				Par or						Par or
	Number			Stated			Number			Stated
	of Shares			Value			of Shares			Value
	(Dollars in millions)
Balance, January 1, 2005		6,209,699		$	335			167,500		$	17
Redemptions-
7.750% Series		(250,000	)		(25	)
$7.40 Series A		(500,000	)		(50	)
Adjustable Series L		(474,000	)		(46	)
Adjustable Series A		(1,200,000	)		(30	)
7.625% Series								(127,500	)		(13	)
$7.35 Series C								(40,000	)		(4	)
Balance, December 31, 2005		3,785,699			184			-			-
Redemptions-
3.90% Series		(152,510	)		(15	)
4.40% Series		(176,280	)		(18	)
4.44% Series		(136,560	)		(14	)
4.56% Series		(144,300	)		(14	)
4.24% Series		(40,000	)		(4	)
4.25% Series		(41,049	)		(4	)
4.64% Series		(60,000	)		(6	)
$4.25 Series		(160,000	)		(16	)
$4.56 Series		(50,000	)		(5	)
$4.25 Series		(100,000	)		(10	)
$2.365 Series		(1,400,000	)		(35	)
Adjustable Series B		(1,200,000	)		(30	)
4.00% Series		(125,000	)		(13	)
Balance, December 31, 2006		-			-			-			-
Balance, December 31, 2007		-		$	-			-		$	-

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

Securitized Transition Bonds

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

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of December 31, 2007, $397 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each companys equity and assets, which consists primarily of bondable transition property.

Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate annual servicing fees of up to $628,000 that are payable from TBC collections.

Other Long-term Debt

Each of the Companies, except for JCP&L, has a first mortgage indenture under which it issues FMB secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. 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.

FirstEnergy and its subsidiaries have various debt covenants under their respective financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt and the maintenance of certain financial ratios. There also exist cross-default provisions among financing arrangements of FirstEnergy, FES and the Companies.

Based on the amount of FMB authenticated by the respective mortgage bond trustees through December 31, 2007, the Companies' annual sinking fund requirement for all FMB issued under the various mortgage indentures amounted to $50 million. Penn expects to deposit funds with its mortgage bond trustee in 2008 that will then be withdrawn upon the surrender for cancellation of a like principal amount of FMB, specifically authenticated for such purposes against unfunded property additions or against previously retired FMB. This method can result in minor increases in the amount of the annual sinking fund requirement. Met-Ed and Penelec could fulfill their sinking fund obligations by providing bondable property additions, previously retired FMB or cash to the respective mortgage bond trustees.

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

	(In millions)
2008	$	2,013
2009		287
2010		214
2011		1,540
2012		43

Included in the table above are amounts for certain variable interest rate pollution control revenue bonds that currently bear interest in an interest rate mode that permits individual debt holders to put the respective debt back to the issuer for purchase prior to maturity. These amounts are $1.7 billion and $15 million in 2008 and 2010, respectively, representing the next time the debt holders may exercise this right. The applicable pollution control revenue bond indentures provide that bonds so tendered for purchase will be remarketed by a designated remarketing agent.

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Obligations to repay certain pollution control revenue bonds are secured by several series of FMB. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank LOCs of $1.6 billion as of December 31, 2007, or noncancelable municipal bond insurance of $593 million as of December 31, 2007, to pay principal of, or interest on, the applicable pollution control revenue bonds. To the extent that drawings are made under the LOCs or the insurance, FGCO, NGC and the Companies are entitled to a credit against their obligation to repay those bonds. FGCO, NGC and the Companies pay annual fees of 0.15% to 1.70% of the amounts of the LOCs to the issuing banks and 0.15% to 0.16% of the amounts of the insurance policies to the insurers and are obligated to reimburse the banks or insurers, as the case may be, for any drawings thereunder. Certain of the issuing banks and insurers hold FMB as security for such reimbursement obligations.

CEI and TE have unsecured LOCs of approximately $194 million in connection with the sale and leaseback of Beaver Valley Unit 2 for which they are jointly and severally liable. OE has LOCs of $291 million and $134 million in connection with the sale and leaseback of Beaver Valley Unit 2 and Perry Unit 1, respectively. OE entered into a Credit Agreement pursuant to which a standby LOC was issued in support of approximately $236 million of the Beaver Valley Unit 2 LOCs and the issuer of the standby LOC obtained the right to pledge or assign participations in OE's reimbursement obligations under the credit agreement to a trust. The trust then issued and sold trust certificates to institutional investors that were designed to be the credit equivalent of an investment directly in OE.

12.   ASSET RETIREMENT OBLIGATIONS

FirstEnergy has recognized applicable legal obligations under SFAS 143 for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, FirstEnergy has recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47, which was implemented on December 31, 2005.

The ARO liability of $1.3 billion as of December 31, 2007 primarily relates to the nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. FirstEnergy uses an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

In 2006, FirstEnergy revised the ARO associated with Perry as a result of revisions to the 2005 decommissioning study. The present value of revisions in the estimated cash flows associated with projected decommissioning costs increased the ARO and corresponding plant asset for Perry by $4 million. The ARO for FirstEnergy's sludge disposal pond located near the Bruce Mansfield Plant was revised in 2006 due to an updated cost study. The present value of revisions in the estimated cash flows associated with projected remediation costs associated with the site decreased the ARO and corresponding plant asset by $6 million. In May 2006, CEI sold its interest in the Ashtabula C plant. As part of the transaction, CEI settled the $6 million ARO that had been established with the adoption of FIN 47.

FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2007, the fair value of the decommissioning trust assets was approximately $2.1 billion.

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

FirstEnergy identified applicable legal obligations as defined under the new standard at its active and retired generating units, substation control rooms, service center buildings, line shops and office buildings, identifying asbestos remediation as the primary conditional ARO. As a result of adopting FIN 47 in December 2005, FirstEnergy recorded a conditional ARO liability of $57 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $16 million (recorded as part of the carrying amount of the related long-lived asset) and accumulated depreciation of $12 million. FirstEnergy charged regulatory liabilities for $5 million upon adoption of FIN 47 for the transition amounts related to establishing the ARO for asbestos removal from substation control rooms and service center buildings for OE, Penn, CEI, TE and JCP&L. The remaining cumulative effect adjustment for unrecognized depreciation and accretion of $48 million was charged to income ($30 million, net of tax), -- $0.09 per share of common stock (basic and diluted) for the year ended December 31, 2005.

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The following table describes the changes to the ARO balances during 2007 and 2006.

	2007			2006
ARO Reconciliation	(In millions)
Balance at beginning of year	$	1,190		$	1,126
Liabilities settled		(2	)		(6	)
Accretion		79			72
Revisions in estimated cash flows		-			(2	)
Balance at end of year	$	1,267		$	1,190

13.   SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT

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 parties 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 Companies, with the exception of TE and JCP&L, each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company. The receivables financing borrowing capacity by company are shown in the following table. There were no outstanding borrowings as of December 31, 2007.

Subsidiary Company	Parent Company	Capacity		Annual Facility Fee
	(In millions)
OES Capital, Incorporated	OE	$	170		0.15	%
Centerior Funding Corp.	CEI		200		0.15
Penn Power Funding LLC	Penn		25		0.13
Met-Ed Funding LLC	Met-Ed		80		0.13
Penelec Funding LLC	Penelec		75		0.13
		$	550

The weighted average interest rates on short-term borrowings outstanding as of December 31, 2007 and 2006 were 5.42% and 5.71%, respectively. The annual facility fees on all current committed short-term bank lines of credit range from 0.125% to 0.15%.

14.   COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A)   NUCLEAR INSURANCE

The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.8 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. FirstEnergy's maximum potential assessment under the industry retrospective rating plan would be $402 million per incident but not more than $60 million in any one year for each incident.

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

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, 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.

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(B)   GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of December 31, 2007, outstanding guarantees and other assurances aggregated approximately $4.5 billion, consisting of parental guarantees - $1.0 billion, subsidiaries' guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $0.7 billion.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for subsidiary financings or refinancings of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.5 billion (included in the $1.0 billion discussed above) as of December 31, 2007 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating-downgrade or "material adverse event" the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of December 31, 2007, FirstEnergy's maximum exposure under these collateral provisions was $402 million.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $73 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions.

FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($19 million as of December 31, 2007), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

On July 13, 2007, FGCO completed the sale and leaseback for its 93.825% undivided interest in Bruce Mansfield Unit 1 (see Note 6). FES has unconditionally and irrevocably guaranteed all of FGCO's obligations under each of the leases.  The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust's undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES' lease guaranty.

(C)   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.

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The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the Clean Air Act. FirstEnergy has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided 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.

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.

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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.

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.

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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.

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.

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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.

(D)   OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages.  JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007.  Proceedings are continuing in the Superior Court.  FirstEnergy is defending this class action but is unable to predict the outcome of this matter.  No liability has been accrued as of December 31, 2007.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. Canada Power System Outage Task Forces final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy's Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energys Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 recommendations to prevent or minimize the scope of future blackouts. Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy's implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

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On February 5, 2008, the PUCO entered an order dismissing four separate complaint cases before it relating to the August 14, 2003 power outages. The dismissal was filed by the complainants in accordance with a resolution reached between the FirstEnergy companies and the complainants in those four cases. Two of those cases which were originally filed in Ohio State courts involved individual complainants and were subsequently dismissed for lack of subject matter jurisdiction.  Further appeals were unsuccessful. The other two complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured, seeking reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and AEP, as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003.  (Also relating to the August 14, 2003 power outages, a fifth case, involving another insurance company was voluntarily dismissed by the claimant in April 2007; and a sixth case, involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed by the court.)  The order dismissing the PUCO cases, noted above, concludes all pending litigation related to the August 14, 2003 outages and the resolution will not have a material adverse effect on the financial condition, results of operations or cash flows of either FirstEnergy or any of its subsidiaries.

Nuclear Plant Matters

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 NRCs 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 NRCs Office of Enforcement after it completes the key commitments embodied in the NRCs order. FENOCs compliance with these commitments is subject to future NRC review.

Other Legal Matters

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

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

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. 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.

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

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15.   FIRSTENERGY INTRA-SYSTEM 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 CEIs and TEs 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.

16.   SEGMENT INFORMATION

FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The Other segment primarily consists of telecommunications services and other non-core assets. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as reportable operating segments.

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

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

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

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							Ohio
	Energy			Competitive			Transitional
	Delivery			Energy			Generation						Reconciling
Segment Financial Information	Services			Services			Services			Other			Adjustments			Consolidated
	(In millions)
2007
External revenues	$	8,726		$	1,468		$	2,596		$	39		$	(27	)	$	12,802
Internal revenues		-			2,901			-			-			(2,901	)		-
Total revenues		8,726			4,369			2,596			39			(2,928	)		12,802
Depreciation and amortization		1,024			204			(125	)		4			26			1,133
Investment income		240			16			1			1			(138	)		120
Net interest charges		445			152			1			4			141			743
Income taxes		574			330			69			4			(94	)		883
Net income		862			495			103			12			(163	)		1,309
Total assets		23,352			7,669			231			303			513			32,068
Total goodwill		5,583			24			-			-			-			5,607
Property additions		814			740			-			21			58			1,633
2006
External revenues	$	7,623		$	1,429		$	2,390		$	95		$	(36	)	$	11,501
Internal revenues		14			2,609			-			-			(2,623	)		-
Total revenues		7,637			4,038			2,390			95			(2,659	)		11,501
Depreciation and amortization		845			190			(105	)		4			23			957
Investment income		328			35			-			1			(215	)		149
Net interest charges		433			188			1			6			74			702
Income taxes		595			262			75			(21	)		(116	)		795
Income from continuing operations		893			393			112			44			(184	)		1,258
Discontinued operations		-			-			-			(4	)		-			(4	)
Net income		893			393			112			40			(184	)		1,254
Total assets		22,863			6,978			215			297			843			31,196
Total goodwill		5,873			24			-			1			-			5,898
Property additions		629			644			-			1			41			1,315
2005
External revenues	$	8,165		$	1,550		$	1,568		$	115		$	(40	)	$	11,358
Internal revenues		33			2,425			-			-			(2,458	)		-
Total revenues		8,198			3,975			1,568			115			(2,498	)		11,358
Depreciation and amortization		1,341			187			(91	)		2			25			1,464
Investment income		262			79			-			-			(124	)		217
Net interest charges		375			191			1			6			83			656
Income taxes		672			132			(49	)		12			(18	)		749
Income (loss) from continuing operations		1,008			199			(73	)		14			(269	)		879
Discontinued operations		-			-			-			12			-			12
Cumulative effect of accounting change		(21	)		(9	)		-			-			-			(30	)
Net income (loss)		987			190			(73	)		26			(269	)		861
Total assets		23,834			6,556			141			605			705			31,841
Total goodwill		5,932			24			-			54			-			6,010
Property additions		782			375			-			8			43			1,208

Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses and elimination of intersegment transactions.

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Products and Services*

			Energy Related
	Electricity		Sales and
Year	Sales		Services
	(In millions)
2007	$	11,944		$	-
2006		10,671			48
2005		10,546			77
* See Note 8 for discussion of discontinued operations.

17.   NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 157 - "Fair Value Measurements"

In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value, which focuses on an exit price rather than entry price; (2) the methods used to measure fair value, such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement and its related FSPs are effective for fiscal years beginning after November 15, 2007, and interim periods within those years.  Under FSP FAS 157-2,  FirstEnergy has elected to defer the election of SFAS 157 for financial assets and financial liabilities measured at fair value on a non-recurring basis for one year.  FirstEnergy has evaluated the impact of this Statement and its FSPs, FSP FAS 157-2 and FSP FAS 157-1, which excludes SFAS 13, Accounting for Leases, and its related pronouncements from the scope of SFAS 157, and does not expect there to be a material effect on its financial statements.  The majority of our fair value measurements will be disclosed as level 1 or level 2 in the fair value hierarchy.

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

In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and financial liabilities at fair value. This Statement attempts to provide additional information that will help investors and other users of financial statements to more easily understand the effect of a companys choice to use fair value on its earnings.  The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet.  This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157 and SFAS 107. This Statement is effective for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy has analyzed its financial assets and financial liabilities within the scope of this Statement and no fair value elections were made as of January 1, 2008.

SFAS 141(R) - "Business Combinations"

In December 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination.  SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations FirstEnergy enters that close after January 1, 2009.  In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this standard. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

SFAS 160 - "Noncontrolling Interests in Consolidated Financial Statements an Amendment of ARB No. 51"

In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.  This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited.  The Statement is not expected to have a material impact on FirstEnergy's financial statements.

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FSP FIN 39-1 - "Amendment of FASB Interpretation No. 39"

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

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

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

18.   SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)

The following summarizes certain consolidated operating results by quarter for 2007 and 2006.

	March 31,		June 30,		September 30,		December 31,
Three Months Ended	2007		2007		2007		2007
	(In millions, except per share amounts)
Revenues	$	2,973	$	3,109	$	3,641	$	3,079
Expenses		2,336		2,381		2,791		2,479
Operating Income		637		728		850		600
Other Expense		147		168		164		144
Income From Continuing Operations Before Income Taxes		490		560		686		456
Income Taxes		200		222		273		188
Income From Continuing Operations		290		338		413		268
Net Income	$	290	$	338	$	413	$	268
Earnings Per Share of Common Stock:
Basic	$	0.92	$	1.11	$	1.36	$	0.88
Diluted	$	0.92	$	1.10	$	1.34	$	0.87

	March 31,		June 30,			September 30,		December 31,
Three Months Ended	2006		2006			2006		2006
	(In millions, except per share amounts)
Revenues	$	2,705	$	2,751		$	3,364	$	2,680
Expenses		2,234		2,081			2,505		2,076
Operating Income		471		670			859		604
Other Expense		117		142			134		160
Income From Continuing Operations Before Income Taxes		354		528			725		444
Income Taxes		135		216			273		170
Income From Continuing Operations		219		312			452		274
Discontinued Operations
(Net of Income Taxes) (Note 8)		2		(8	)		2		-
Net Income	$	221	$	304		$	454	$	274
Basic Earnings Per Share of Common Stock:
Income From Continuing Operations	$	0.67	$	0.94		$	1.40	$	0.85
Discontinued Operations		-		(0.02	)		0.01		-
Net Earnings Per Basic Share	$	0.67	$	0.92		$	1.41	$	0.85
Diluted Earnings Per Share of Common Stock:
Income From Continuing Operations	$	0.67	$	0.93		$	1.39	$	0.84
Discontinued Operations		-		(0.02	)		0.01		-
Net Earnings Per Diluted Share	$	0.67	$	0.91		$	1.40	$	0.84

111

EX-21

EXHIBIT 21

FIRSTENERGY CORP.

LIST OF SUBSIDIARIES OF THE REGISTRANT

AT DECEMBER 31, 2007

Ohio Edison Company - - Incorporated in Ohio

The Cleveland Electric Illuminating Company - Incorporated in Ohio

The Toledo Edison Company - Incorporated in Ohio

FirstEnergy Properties Inc. - Incorporated in Ohio

FirstEnergy Ventures Corp. - Incorporated in Ohio

FirstEnergy Facilities Services Group, LLC - Incorporated in Ohio

FirstEnergy Securities Transfer Company - Incorporated in Ohio

FirstEnergy Service Company - Incorporated in Ohio

FirstEnergy Solutions Corp. - Incorporated in Ohio

MARBEL Energy Corporation - Incorporated in Ohio

FirstEnergy Nuclear Operating Company - Incorporated in Ohio

FE Acquisition Corp. - Incorporated in Ohio

American Transmission Systems, Inc. - Incorporated in Ohio

FELHC, Inc. - Incorporated in Ohio

Jersey Central Power & Light Company - Incorporated in New Jersey

Metropolitan Edison Company - Incorporated in Pennsylvania

Pennsylvania Electric Company - Incorporated in Pennsylvania

GPU Capital, Inc. - Incorporated in Delaware

GPU Diversified Holdings, LLC - Incorporated in Delaware

GPU Nuclear, Inc. - Incorporated in New Jersey

GPU Power, Inc. - Incorporated in Delaware

FirstEnergy Telecom Services, Inc. - Incorporated in Delaware

FirstEnergy Foundation - Incorporated in Ohio

EX-23.1

EXHIBIT 23.1

FIRSTENERGY CORP.

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-48587, 333-102074 and 333-103865) and Form S-8 (Nos. 333-56094, 333-58279, 333-67798, 333-72766, 333-72768, 333-81183, 333-89356, 333-101472, 333-110662, and 333-146170) of FirstEnergy Corp. of our report dated February 28, 2008 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Stockholders, which is incorporated in this Annual Report on Form 10-K. We also consent to the incorporation by reference of our report dated February 28, 2008 relating to the financial statement schedules, which appears in this Form 10-K.

PricewaterhouseCoopers LLP

Cleveland, OH

February 28, 2008

EX-31.1

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this report on Form 10-K of FirstEnergy Corp.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:February 28, 2008

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

1

Exhibit 31.1

Certification

I, Charles E. Jones, certify that:

1.	I have reviewed this report on Form 10-K of FirstEnergy Solutions Corp.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:February 28, 2008

/s/ Charles E. Jones

Charles E. Jones

Chief Executive Officer

2

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this report on Form 10-K of Ohio Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

3

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this report on Form 10-K of The Cleveland Electric Illuminating Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

4

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this report on Form 10-K of The Toledo Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

5

Exhibit 31.1

Certification

I, Stephen E. Morgan, certify that:

1.	I have reviewed this report on Form 10-K of Jersey Central Power & Light Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Stephen E. Morgan

Stephen E. Morgan

Chief Executive Officer

6

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this report on Form 10-K of Metropolitan Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

7

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this report on Form 10-K of Pennsylvania Electric Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

8

EX-31.2

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-K of FirstEnergy Corp.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

1

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-K of FirstEnergy Solutions Corp.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

2

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-K of Ohio Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

3

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-K of The Cleveland Electric Illuminating Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

4

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-K of The Toledo Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

5

Exhibit 31.2

Certification

I, Paulette R. Chatman, certify that:

1.	I have reviewed this report on Form 10-K of Jersey Central Power & Light Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Paulette R. Chatman

Paulette R. Chatman

Chief Financial Officer

6

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-K of Metropolitan Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

7

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-K of Pennsylvania Electric Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

8

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of FirstEnergy Corp. (the "Company") on Form 10-K for the year ending December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: February 28, 2008

1

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of FirstEnergy Solutions Corp. (the "Company") on Form 10-K for the year ending December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Charles E. Jones

Charles E. Jones

President

(Chief Executive Officer)

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: February 28, 2008

2

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of Ohio Edison Company (the "Company") on Form 10-K for the year ending December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: February 28, 2008

3

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of The Cleveland Electric Illuminating Company (the "Company") on Form 10-K for the year ending December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: February 28, 2008

4

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of The Toledo Edison Company (the "Company") on Form 10-K for the year ending December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: February 28, 2008

5

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of Jersey Central Power & Light Company (the "Company") on Form 10-K for the year ending December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Stephen E. Morgan

Stephen E. Morgan

President

(Chief Executive Officer)

Date: February 28, 2008

/s/ Paulette R. Chatman

Paulette R. Chatman

Controller

(Chief Financial Officer)

Date: February 28, 2008

6

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of Metropolitan Edison Company (the "Company") on Form 10-K for the year ending December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: February 28, 2008

7

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of Pennsylvania Electric Company (the "Company") on Form 10-K for the year ending December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Date: February 28, 2008

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: February 28, 2008

8

EX-13.2

ANNUAL REPORT 2007

Contents		Page
Glossary of Terms		iii-v
FirstEnergy Solutions Corp.
	Management's Narrative Analysis of Results of Operations	1-5
	Management Reports	6
	Report of Independent Registered Public Accounting Firm	7
	Consolidated Statements of Income	8
	Consolidated Balance Sheets	9
	Consolidated Statements of Capitalization	10
	Consolidated Statements of Common Stockholder's Equity	11
	Consolidated Statements of Cash Flows	12
Ohio Edison Company
	Management's Narrative Analysis of Results of Operations	13-15
	Management Reports	16
	Report of Independent Registered Public Accounting Firm	17
	Consolidated Statements of Income	18
	Consolidated Balance Sheets	19
	Consolidated Statements of Capitalization	20
	Consolidated Statements of Common Stockholder's Equity	21
	Consolidated Statements of Cash Flows	22
The Cleveland Electric Illuminating Company
	Management's Narrative Analysis of Results of Operations	23-25
	Management Reports	26
	Report of Independent Registered Public Accounting Firm	27
	Consolidated Statements of Income	28
	Consolidated Balance Sheets	29
	Consolidated Statements of Capitalization	30
	Consolidated Statements of Common Stockholder's Equity	31
	Consolidated Statements of Cash Flows	32
The Toledo Edison Company
	Management's Narrative Analysis of Results of Operations	33-35
	Management Reports	36
	Report of Independent Registered Public Accounting Firm	37
	Consolidated Statements of Income	38
	Consolidated Balance Sheets	39
	Consolidated Statements of Capitalization	40
	Consolidated Statements of Common Stockholder's Equity	41
	Consolidated Statements of Cash Flows	42
Jersey Central Power & Light Company
	Management's Narrative Analysis of Results of Operations	43-46
	Management Reports	47
	Report of Independent Registered Public Accounting Firm	48
	Consolidated Statements of Income	49
	Consolidated Balance Sheets	50
	Consolidated Statements of Capitalization	51
	Consolidated Statements of Common Stockholder's Equity	52
	Consolidated Statements of Cash Flows	53

i

Contents (Cont'd)		Page
Metropolitan Edison Company
	Management's Narrative Analysis of Results of Operations	54-57
	Management Reports	58
	Report of Independent Registered Public Accounting Firm	59
	Consolidated Statements of Income	60
	Consolidated Balance Sheets	61
	Consolidated Statements of Capitalization	62
	Consolidated Statements of Common Stockholder's Equity	63
	Consolidated Statements of Cash Flows	64
Pennsylvania Electric Company
	Management's Narrative Analysis of Results of Operations	65-68
	Management Reports	69
	Report of Independent Registered Public Accounting Firm	70
	Consolidated Statements of Income	71
	Consolidated Balance Sheets	72
	Consolidated Statements of Capitalization	73
	Consolidated Statements of Common Stockholder's Equity	74
	Consolidated Statements of Cash Flows	75
Combined Management's Discussion and Analysis of Registrant Subsidiaries		76-90
Combined Notes to Consolidated Financial Statements		91-145

ii

GLOSSARY OF TERMS

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

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
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
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
Pennsylvania Companies	Met-Ed, Penelec and Penn
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
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
AOCI	Accumulated Other Comprehensive Income
AOCL	Accumulated Other Comprehensive Loss
APIC	Additional Paid-In Capital
AQC	Air Quality Control
ARB	Accounting Research Bulletin
ARO	Asset Retirement Obligation
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
CAT	Commercial Activity Tax
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
ECO	Electro-Catalytic Oxidation

iii

GLOSSARY OF TERMS Cont'd.

EIS	Energy Independence Strategy
EITF	Emerging Issues Task Force
EITF 06-11	EITF 06-11, "Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards"
EMP	Energy Master Plan
EPA	Environmental Protection Agency
EPACT	Energy Policy Act of 2005
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 39-1	FIN 39-1, "Amendment of FASB Interpretation No. 39"
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
FIN 48	FIN 48, "Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109"
FMB	First Mortgage Bonds
FSP	FASB Staff Position
FSP SFAS 115-1    and SFAS 124-1	FSP SFAS 115-1 and SFAS 124-1, "The Meaning of Other-Than-Temporary Impairment and its     Application to Certain Investments"
FTR	Financial Transmission Rights
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
HVAC	Heating, Ventilation and Air-conditioning
IRS	Internal Revenue Service
ISO	Independent System Operator
kv	Kilovolt
KWH	Kilowatt-hours
LOC	Letter of Credit
MEIUG	Met-Ed Industrial Users Group
MISO	Midwest Independent Transmission System Operator, Inc.
MTC	Market Transition Charge
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
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
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
REC	Renewable Energy Certificate
RECB	Regional Expansion Criteria and Benefits
RFP	Request for Proposal
ROP	Reactor Oversight Process
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization

iv

GLOSSARY OF TERMS Cont'd.

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
SERP	Supplemental Executive Retirement Plan
SFAS	Statement of Financial Accounting Standards
SFAS 13	SFAS No. 13, "Accounting for Leases"
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"
SFAS 107	SFAS No. 107, "Disclosure about Fair Value of Financial Instruments"
SFAS 109	SFAS No. 109, "Accounting for Income Taxes"
SFAS 115	SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities"
SFAS 123(R)	SFAS No. 123(R), "Share-Based Payment"
SFAS 133	SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities"
SFAS 141(R)	SFAS No. 141(R), "Business Combinations"
SFAS 142	SFAS No. 142, "Goodwill and Other Intangible Assets"
SFAS 143	SFAS No. 143, "Accounting for Asset Retirement Obligations"
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 157	SFAS No. 157, "Fair Value Measurements"
SFAS 158	SFAS No. 158, "Employers Accounting for Defined Benefit Pension and Other Postretirement    Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)"
SFAS 159	SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities Including an    Amendment of FASB Statement No. 115"
SFAS 160	SFAS No. 160, "Non-controlling Interests in Consolidated Financial Statements - an Amendment of ARB No. 51"
SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
TBC	Transition Bond Charge
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
VIE	Variable Interest Entity

v

This combined Annual Report is separately filed by 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.

Forward-Looking Statements: This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements 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.

FIRSTENERGY SOLUTIONS CORP.

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

FES' revenues are primarily from the sale of electricity (provided from FES' generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR and default service requirements. These affiliated power sales include a full-requirements PSA with the Ohio Companies to supply each of their PLR and default service obligations through 2008, at prices that take into consideration the Ohio Companies' respective PUCO authorized billing rates. FES also has a partial-requirements PSA with Met-Ed and Penelec to supply a portion of each of their respective PLR and default service obligations at fixed prices through 2010. The fixed prices under the partial requirements agreement are expected to remain below wholesale market prices during the term of the agreement (see Note 9). FES also supplies the majority of the default service requirements of Penn at market-based rates as a result of a competitive solicitation conducted by Penn. FES' existing contractual obligations to Penn expire on May 31, 2008, but could continue if FES successfully bids in future competitive solicitations. FES' revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, Maryland and Michigan.

Results of Operations

Net income increased to $529 million in 2007 from $419 million in 2006 primarily due to higher revenues and lower fuel and interest expenses, partially offset by higher purchased power costs and other operating expenses.

Revenues

Revenues increased by $314million, or 7.8%, in 2007 as compared to 2006 primarily due to increases in revenues from non-affiliated retail generation sales and affiliated wholesale sales, partially offset by lower non-affiliated wholesale sales.  Retail generation sales revenues increased by $122 million as a result of higher unit prices and increased KWH sales. Higher unit prices primarily reflected higher generation rates in the MISO and PJM markets where FES is an alternative supplier. Increased KWH sales to FES' commercial and industrial customers during 2007 were partially offset by a decrease in sales to residential customers, who returned to FES' Ohio utility affiliates for their generation requirements. Affiliated wholesale revenues were higher as a result of increased sales and higher unit prices for KWH sold to the Ohio and Pennsylvania Companies.

Non-affiliated wholesale revenues decreased by $73 million as a result of less generation available for the non-affiliated market due to increased affiliated company power sales requirements under the Ohio Companies' full-requirements PSA and the partial-requirements PSA with Met-Ed and Penelec.

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

Transmission revenue decreased $17 million due in part to reduced FTR revenues resulting from fewer FTRs allocated by MISO and PJM, partially offset by higher retail transmission revenues.

The change in revenues in 2007 from 2006 is summarized below:

					Increase
Revenues by Type of Service	2007		2006		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	712	$	590	$	122
Wholesale		603		676		(73	)
Total Non-Affiliated Generation Sales		1,315		1,266		49
Affiliated Generation Sales		2,901		2,609		292
Transmission		103		120		(17	)
Other		6		16		(10	)
Total Revenues	$	4,325	$	4,011	$	314

1

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated sales in 2007 compared to 2006:

	Increase
Source of Change in Non-Affiliated Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 10.8% increase in sales volumes	$	63
Change in prices		59
		122
Wholesale:
Effect of 22.7% decrease in sales volumes		(154	)
Change in prices		81
		(73	)
Net Increase in Non-Affiliated Generation Revenues	$	49

Source of Change in Affiliated Generation Revenues	Increase
	(In millions)
Ohio Companies:
Effect of 3.4% increase in sales volumes	$	68
Change in prices		118
		186
Pennsylvania Companies:
Effect of 14.9% increase in sales volumes		87
Change in prices		19
		106
Net Increase in Affiliated Generation Revenues	$	292

Expenses

Total expenses increased by $173 million in 2007 compared to 2006. The following table summarizes the factors contributing to the changes in fuel and purchased power costs from the prior year:

Source of Change in Fuel and Purchased Power	Increase  (Decrease)
	(In millions)
Fossil Fuel:
Change due to volume consumed	$	(22	)
Change due to increased unit costs		(11	)
		(33	)
Nuclear Fuel:
Change due to volume consumed		5
Change due to increased unit costs		9
		14
Purchased Power:
Change due to volume consumed		70
Change due to increased unit costs		81
		151
Net Increase in Fuel and Purchased Power Costs	$	132

Fossil fuel costs decreased $33 million in 2007 primarily as a result of reduced coal and emission allowance costs, partially offset by increased natural gas costs due to increased consumption. Reduced coal consumption reflected lower generation as a result of planned maintenance outages at Bruce Mansfield Units 2 and 3, Sammis Unit 6 and Eastlake Unit 5, and a forced outage at Bruce Mansfield Unit 1. The lower fossil fuel costs were partially offset by higher nuclear fuel costs of $14 million due to higher unit costs and increased nuclear generation in 2007 compared to 2006.  Increased nuclear generation primarily reflects the absence in 2007 of outages at Beaver Valley Unit 1 and Davis-Besse that was scheduled in 2006.

Purchased power costs increased as a result of higher unit prices in the MISO and PJM markets and increased volumes purchased. Volumes purchased in 2007 increased by 8.2% from 2006 primarily for replacement power related to forced outages at the Bruce Mansfield and Perry plants.

2

Other operating expenses increased by $13 million in 2007 primarily due to the absence of gains from the sale of emissions allowances recognized in 2006 and higher lease expenses associated with the assignment of CEI's and TE's leasehold interests in the Bruce Mansfield Plant to FGCO and the Bruce Mansfield Unit 1 sale and leaseback transaction completed in 2007.  Partially offsetting the higher other operating expenses were lower nuclear operating costs as a result of fewer outages in 2007 and decreased MISO transmission expense due to the resettlement of costs from generation providers to load serving entities.

Depreciation expense increased by $14 million in 2007 primarily due to fossil and nuclear property additions subsequent to 2006. General taxes increased by $14 million in 2007 compared to 2006 as a result of higher gross receipts and property taxes.

Other Expense

Other expense decreased by $38 million in 2007 compared to 2006 primarily as a result of lower interest expense, partially offset by decreased earnings on the nuclear decommissioning trust investments. Lower interest expense reflected the repayment of notes to associated companies related to the generation asset transfers, partially offset by the issuance of lower-cost pollution control debt in 2007.

Market Risk Information

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

Commodity Price Risk

FES is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices primarily due to fluctuations in electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowance prices. To manage the volatility relating to these exposures, FES uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FES' derivative contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the table below. The change in the fair value of commodity derivative contracts related to energy production during 2007 is summarized in the following table:

Increase (Decrease) in the Fair Value of Derivative Contracts	Non-Hedge			Hedge			Total
	(In millions)
Change in the fair value of commodity derivative contracts:
Outstanding net liability as of January 1, 2007	$	(3	)	$	(17	)	$	(20	)
Additions/change in value of existing contracts		(2	)		(21	)		(23	)
Settled contracts		5			12			17
Outstanding net liability as of December 31, 2007	$	-		$	(26	)	$	(26	)
Non-commodity net liabilities as of December 31, 2007:
Interest rate swaps	$	-		$	-		$	-
Net liabilities derivative contacts as of December 31, 2007	$	-		$	(26	)	$	(26	)
Impact of changes in commodity derivative contracts(*)
Income Statement effects (Pre-Tax)	$	3		$	-		$	3
Balance Sheet effects:
OCI (Pre-Tax)	$	-		$	(9	)	$	(9	)

(*) Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

3

Derivatives are included on the Consolidated Balance Sheet as of December 31, 2007 as follows:

Balance Sheet Classification	Non-Hedge		Hedge			Total
	(In millions)
Current-
Other assets	$	-	$	24		$	24
Other liabilities		-		(48	)		(48	)
Non-Current-
Other deferred charges		-		7			7
Other noncurrent liabilities		-		(9	)		(9	)
Net liabilities	$	-	$	(26	)	$	(26	)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. FES uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts by year are summarized in the following table:

Source of Information
- Fair Value by Contract Year	2008			2009			2010		2011		2012		Thereafter		Total
	(In millions)
Prices actively quoted(1)	$	(1	)	$	-		$	-	$	-	$	-	$	-	$	(1	)
Broker quote sheets.		(24	)		(1	)		-		-		-		-		(25	)
Total	$	(25	)	$	(1	)	$	-		-	$	-	$	-	$	(26	)

(1)     Exchange traded.

FES performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on FES' derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of December 31, 2007. Based on derivative contracts held as of December 31, 2007, an adverse 10% change in commodity prices would decrease net income by approximately $3 million for the next 12 months.

Interest Rate Risk

The table below presents principal amounts and related weighted average interest rates by year of maturity for FES' investment portfolio and debt obligations.

Comparison of Carrying Value to Fair Value
										There-						Fair
Year of Maturity		2008		2009	2010			2011	2012	after			Total			Value
		(Dollars in millions)
Assets
Investments other than Cash and Cash
Equivalents-Fixed Income					$	63				$	419		$	482		$	480
Average interest rate						5.4	%				4.8	%		4.9	%
Liabilities
Long-term Debt and Other
Long-term Obligations:
Fixed rate										$	63		$	63		$	59
Average interest rate											5.4	%		5.4	%
Variable rate										$	1,912		$	1,912		$	1,912
Average interest rate											3.7	%		3.7	%
Short-term Borrowings	$	564											$	564		$	564
Average interest rate		5.2	%											5.2	%

Fluctuations in the fair value of NGC's decommissioning trust balances will eventually affect earnings (immediately for unrealized losses and affecting OCI initially for unrealized gains) based on the guidance in SFAS 115, FSP SFAS 115-1 and SFAS 124-1. As of December 31, 2007, NGC's decommissioning trust balance totaled $1.3 billion. As of December 31, 2007, the trust balance was comprised of 69% equity securities and 31% debt instruments.

4

Equity Price Risk

Included in NGCs nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $919 million as of December 31, 2007. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $92 million reduction in fair value as of December 31, 2007 (see Note 5).

Credit Risk

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

FES maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FES aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB+ (S&P). As of December 31, 2007, the largest credit concentration with one non-affiliated party (currently rated investment grade) represented 9.7% of its total credit risk. As of December 31, 2007, 99.3%of FES credit exposure, net of collateral and reserves, was with non-affiliated investment-grade counterparties.

Legal Proceedings

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

New Accounting Standards and Interpretations

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

5

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of FirstEnergy Solutions Corp. (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Companys 2007 consolidated financial statements.

FirstEnergy Corp.s internal auditors, who are responsible to the Audit Committee of FirstEnergys Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.

FirstEnergys Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committees findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Companys independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management's programs to monitor compliance with the Companys policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 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 the Companys internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Companys internal control over financial reporting was effective as of December 31, 2007.

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.

6

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of FirstEnergy Solutions Corp.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder's equity and cash flows present fairly, in all material respects, the financial position of FirstEnergy Solutions Corp. and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in the notes to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007 (Note 8), defined benefit pension and other postretirement plans as of December 31, 2006 (Note 4) and conditional asset retirement obligations as of December 31, 2005 (Note 2(G) and Note 11).

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

7

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2007			2006			2005
	(In thousands)
REVENUES:
Electric sales to affiliates (Note 3)	$	2,901,154		$	2,609,299		$	2,425,251
Electric sales to non-affiliates		1,315,141			1,265,604			1,410,428
Other		108,732			136,450			131,560
Total revenues		4,325,027			4,011,353			3,967,239
EXPENSES (Note 3):
Fuel		1,087,010			1,105,657			1,005,877
Purchased power from affiliates		234,090			257,001			308,602
Purchased power from non-affiliates		764,090			590,491			957,570
Other operating expenses		1,041,039			1,027,564			980,182
Provision for depreciation		192,912			179,163			177,231
General taxes		87,098			73,332			67,302
Total expenses		3,406,239			3,233,208			3,496,764
OPERATING INCOME		918,788			778,145			470,475
OTHER INCOME (EXPENSE):
Investment income		41,438			45,937			78,787
Miscellaneous income (expense)		11,438			8,565			(34,143	)
Interest expense to affiliates (Note 3)		(65,501	)		(162,673	)		(184,317	)
Interest expense - other		(92,199	)		(26,468	)		(12,038	)
Capitalized interest		19,508			11,495			14,295
Total other expense		(85,316	)		(123,144	)		(137,416	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		833,472			655,001			333,059
INCOME TAXES		304,608			236,348			124,499
INCOME FROM CONTINUING OPERATIONS		528,864			418,653			208,560
Discontinued operations (net of income taxes of $3,761,000) (Note 2(H))		-			-			5,410
INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		528,864			418,653			213,970
Cumulative effect of a change in accounting principle (net of income
tax benefit of $5,507,000) (Note 2(G))		-			-			(8,803	)
NET INCOME	$	528,864		$	418,653		$	205,167
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral
part of these statements.

8

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
As of December 31,	2007		2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	2
Receivables-
Customers (less accumulated provisions of $8,072,000 and $7,938,000,
respectively, for uncollectible accounts)		133,846		129,843
Associated companies		376,499		235,532
Other (less accumulated provisions of $9,000 and $5,593,000,
respectively, for uncollectible accounts)		3,823		4,085
Notes receivable from associated companies		92,784		752,919
Materials and supplies, at average cost		427,015		460,239
Prepayments and other		92,340		57,546
		1,126,309		1,640,166
PROPERTY, PLANT AND EQUIPMENT:
In service		8,294,768		8,355,344
Less - Accumulated provision for depreciation		3,892,013		3,818,268
		4,402,755		4,537,076
Construction work in progress		761,701		339,886
		5,164,456		4,876,962
INVESTMENTS:
Nuclear plant decommissioning trusts		1,332,913		1,238,272
Long-term notes receivable from associated companies		62,900		62,900
Other		40,004		72,509
		1,435,817		1,373,681
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		276,923		-
Lease assignment receivable from associated companies		215,258		-
Goodwill		24,248		24,248
Property taxes		47,774		44,111
Pension assets (Note 4)		16,723		-
Unamortized sale and leaseback costs		70,803		-
Other		43,953		39,839
		695,682		108,198
	$	8,422,264	$	7,999,007
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,441,196	$	1,469,660
Short-term borrowings-
Associated companies		264,064		1,022,197
Other		300,000		-
Accounts payable-
Associated companies		445,264		556,049
Other		177,121		136,631
Accrued taxes		171,451		113,231
Other		237,806		100,941
		3,036,902		3,398,709
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		2,414,231		1,859,363
Long-term debt		533,712		1,614,222
		2,947,943		3,473,585
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		1,060,119		-
Accumulated deferred income taxes		-		121,449
Accumulated deferred investment tax credits		61,116		65,751
Asset retirement obligations		810,114		760,228
Retirement benefits		63,136		103,027
Property taxes		48,095		44,433
Lease market valuation liability		353,210		-
Other		41,629		31,825
		2,437,419		1,126,713
COMMITMENTS AND CONTINGENCIES (Notes 6 & 13)
	$	8,422,264	$	7,999,007
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp.
are an integral part of these balance sheets.

9

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2007			2006
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, authorized 750 shares,
7 and 8 shares outstanding, respectively	$	1,164,922		$	1,050,302
Accumulated other comprehensive income (Note 2(F))		140,654			111,723
Retained earnings (Note 10(A))		1,108,655			697,338
Total		2,414,231			1,859,363
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 10(C)):
Secured notes:
FGCO
3.980% due to associated companies 2025		-			770,912
4.380% due to associated companies 2025		-			35,952
5.390% due to associated companies 2025		-			13,967
5.990% due to associated companies 2025		-			221,485
		-			1,042,316
NGC
4.380% due to associated companies 2025		-			55,100
5.990% due to associated companies 2025		-			265,150
		-			320,250
Total secured notes		-			1,362,566
Unsecured notes:
FGCO
*   4.000% due 2017		28,525			28,525
*   3.740% due 2019		90,140			90,140
*   4.500% due 2020		141,260			-
*   3.450% due 2023		234,520			234,520
*   4.350% due 2028		15,000			15,000
*   4.000% due 2029		6,450			-
*   3.990% due 2029		100,000			-
*   3.340% due 2040		43,000			43,000
*   3.410% due 2041		129,610			129,610
*   3.750% due 2041		56,600			56,600
*   3.348% due 2041		26,000			26,000
		871,105			623,395
NGC
*   3.500% due 2033		15,500			15,500
*   3.470% due 2033		135,550			135,550
*   3.520% due 2033		62,500			62,500
*   3.430% due 2033		99,100			99,100
*   3.430% due 2033		8,000			8,000
*   3.380% due 2033		107,500			107,500
*   3.470% due 2033		46,500			46,500
*   4.650% due 2033		54,600			-
*   4.700% due 2033		26,000			-
*   3.420% due 2034		82,800			82,800
*   3.430% due 2034		7,200			7,200
*   3.470% due 2035		163,965			163,965
*   3.400% due 2035		72,650			72,650
*   3.740% due 2035		60,000			60,000
*   4.250% due 2035		98,900			-
3.980% due to associated companies 2025		-			56,000
5.390% due to associated companies 2025		62,900			180,720
		1,103,665			1,097,985
Total unsecured notes		1,974,770			1,721,380
Capital lease obligations (Note 6)		199			-
Net unamortized discount on debt		(61	)		(64	)
Long-term debt due within one year		(1,441,196	)		(1,469,660	)
Total long-term debt		533,712			1,614,222
TOTAL CAPITALIZATION	$	2,947,943		$	3,473,585
* Denotes variable rate issue with applicable year-end interest rate shown.
The accompanying Combined Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp.
are an integral part of these statements.

10

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
										Accumulated
				Common Stock						Other
	Comprehensive			Number			Carrying			Comprehensive			Retained
	Income			of Shares			Value			Income			Earnings
	(Dollars in thousands)
Balance, January 1, 2005					8		$	783,685		$	84,518		$	81,131
Net income	$	205,167												205,167
Net unrealized loss on derivative instruments, net
of $2,414,000 of income tax benefits		(3,595	)								(3,595	)
Unrealized loss on investments, net of
$9,658,000 of income tax benefits		(15,462	)								(15,462	)
Comprehensive income	$	186,110
Equity contribution from parent								262,200
Stock options exercised, restricted stock units
and other adjustments								2,849						841
Balance, December 31, 2005					8			1,048,734			65,461			287,139
Net income	$	418,653												418,653
Net unrealized loss on derivative instruments, net
of $5,082,000 of income tax benefits		(8,248	)								(8,248	)
Unrealized gain on investments, net of
$33,698,000 of income taxes		58,654									58,654
Comprehensive income	$	469,059
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $10,825,000 of income tax benefits (Note 4)											(4,144	)
Stock options exercised, restricted stock units
and other adjustments								1,568
Cash dividends declared on common stock														(8,454	)
Balance, December 31, 2006					8			1,050,302			111,723			697,338
Net income	$	528,864												528,864
Net unrealized loss on derivative instruments, net
of $3,337,000 of income tax benefits		(5,640	)								(5,640	)
Unrealized gain on investments, net of
$26,645,000 of income taxes		41,707									41,707
Pension and other postretirement benefits, net
of $604,000 of income taxes (Note 4)		(7,136	)								(7,136	)
Comprehensive income	$	557,795
Repurchase of common stock					(1	)		(600,000	)
Equity contribution from parent								700,000
Stock options exercised, restricted stock units
and other adjustments								4,141
Consolidated tax benefit allocation								10,479
FIN 48 cumulative effect adjustment														(547	)
Cash dividends declared on common stock														(117,000	)
Balance, December 31, 2007					7		$	1,164,922		$	140,654		$	1,108,655
The accompanying Combined Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral part of
these statements.

11

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2007			2006			2005
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	528,864		$	418,653		$	205,167
Adjustments to reconcile net income to net cash from
operating activities-
Provision for depreciation		192,912			179,163			177,231
Nuclear fuel amortization		100,720			89,178			86,748
Deferred income taxes and investment tax credits, net		(334,545	)		115,878			94,602
Investment impairment (Note 2(E))		22,817			10,255			-
Cumulative effect of a change in accounting principle		-			-			8,803
Accrued compensation and retirement benefits		6,419			25,052			27,960
Commodity derivative transactions, net		5,930			24,144			(219	)
Gain on asset sales		(12,105	)		(37,663	)		(30,239	)
Income from discontinued operations (Note 2(H))		-			-			(5,410	)
Cash collateral, net		(31,059	)		40,680			50,695
Pension trust contributions		(64,020	)		-			(13,291	)
Decrease (increase) in operating assets-
Receivables		(99,048	)		(15,462	)		(17,076	)
Materials and supplies		56,407			(1,637	)		(17,563	)
Prepayments and other current assets		(13,812	)		(5,237	)		(6,041	)
Increase (decrease) in operating liabilities-
Accounts payable		(104,599	)		19,970			44,792
Accrued taxes		61,119			12,235			35,252
Accrued interest		1,143			4,101			500
Other		(22,826	)		(20,469	)		5,437
Net cash provided from operating activities		294,317			858,841			647,348
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		427,210			1,156,841			-
Equity contributions from parent		700,000			-			262,200
Short-term borrowings, net		-			46,402			-
Redemptions and Repayments-
Common stock		(600,000	)		-			-
Long-term debt		(1,541,610	)		(1,137,740	)		-
Short-term borrowings, net		(458,321	)		-			(114,339	)
Common stock dividend payments		(117,000	)		(8,454	)		-
Net cash provided from (used for) financing activities		(1,589,721	)		57,049			147,861
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(738,709	)		(577,287	)		(411,560	)
Proceeds from asset sales		12,990			34,215			58,087
Proceeds from sale and leaseback transaction		1,328,919			-			-
Sales of investment securities held in trusts		655,541			1,066,271			1,097,276
Purchases of investment securities held in trusts		(697,763	)		(1,066,271	)		(1,186,381	)
Loan repayments from (loans to) associated companies		734,862			(333,030	)		(291,626	)
Other		(436	)		(39,788	)		(61,033	)
Net cash provided from (used for) investing activities		1,295,404			(915,890	)		(795,237	)
Net change in cash and cash equivalents		-			-			(28	)
Cash and cash equivalents at beginning of year		2			2			30
Cash and cash equivalents at end of year	$	2		$	2		$	2
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	136,121		$	173,337		$	195,519
Income taxes	$	613,814		$	155,771		$	20,274
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp.
are an integral part of these statements.

12

OHIO EDISON COMPANY

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They provide generation services to those customers electing to retain OE and Penn as their power supplier. OEs power supply requirements are provided by FES  an affiliated company. Penn purchases power from FES and third-party suppliers through a competitive RFP process.

Results of Operations

Earnings on common stock decreased to $197 million from $207 million in 2006. The decrease in earnings primarily resulted from higher purchased power costs and lower investment income, partially offset by higher electric sales revenues and the deferral of new regulatory assets.

Revenues

Revenues increased by $64 million or 2.6% in 2007 compared with 2006, primarily due to a $75 million increase in retail generation revenues, partially offset by a decrease in revenues from distribution throughput of $9 million.

Higher retail generation revenues from residential customers reflected increased sales volume and the impact of higher average unit prices. Higher weather-related usage in 2007 compared to 2006 contributed to the increased KWH sales to residential customers (heating degree days increased 8.4% and 6.2% and cooling degree days increased by 34.5% and 33.2% in OEs and Penns service territories, respectively). Commercial retail generation revenues increased primarily due to higher average unit prices, partially offset by reduced KWH sales. Average prices increased due to the higher generation prices that were effective in January 2007 under Penns competitive RFP process. Retail generation revenues from the industrial sector decreased primarily due to an increase in customer shopping in Penns service territory in 2007 as compared to 2006. The percentage of shopping customers increased to 28.1% in 2007 from 15.7% in 2006.

Changes in retail generation sales and revenues in 2007 from 2006 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)
Residential		6.5
Commercial		(2.2	)%
Industrial		(15.9	)%
Net Decrease in Generation Sales		(4.2	)%

Retail Generation Revenues	Increase (Decrease)
	(In millions)
Residential	$	102
Commercial		25
Industrial		(52	)
Net Increase in Generation Revenues	$	75

Decreases in distribution revenues from commercial and industrial customers were partially offset by increased revenues from residential customers. The increase from residential customers reflected higher deliveries due to the weather conditions described above, partially offset by lower composite unit prices. Reduced distribution revenues from commercial customers in 2007 resulted from lower unit prices, partially offset by increased KWH deliveries. Distribution revenues from industrial customers decreased in 2007 as a result of lower unit prices and reduced KWH deliveries.

13

Changes in distribution KWH deliveries and revenues in 2007 from 2006 are summarized in the following tables.

Distribution KWH Deliveries	Increase (Decrease)
Residential		5.4	%
Commercial		3.3	%
Industrial		(1.5	)%
Other		-
Net Increase in Distribution Deliveries		2.3	%

Distribution Revenues	Increase (Decrease)
	(In millions)
Residential	$	5
Commercial		(2	)
Industrial		(14	)
Other		2
Net Decrease in Distribution Revenues	$	(9	)

Expenses

Total expenses increased by $64 million in 2007 from 2006. The following table presents changes from the prior year by expense category.

Expenses Changes	Increase (Decrease)
	(In millions)
Fuel costs	$	1
Purchased power costs		83
Nuclear operating costs		(12	)
Other operating costs		3
Provision for depreciation		4
Amortization of regulatory assets		2
Deferral of new regulatory assets		(18	)
General taxes		1
Net Increase in Expenses	$	64

The increase in purchased power costs in 2007 primarily reflected higher unit prices under Penns 2007 competitive RFP process and OEs PSA with FES. The decrease in nuclear operating costs for 2007 compared to 2006 was primarily due to the absence of a refueling outage at Beaver Valley Unit 2 in 2007, partially offset by costs associated with Perrys 2007 refueling outage. OE incurs costs associated with Beaver Valley Unit 2 and Perry because of its leasehold interests in the plants (21.66% for Beaver Valley Unit 2 and 12.58% for Perry). The increase in other operating costs for 2007 was primarily due to higher transmission expenses related to MISO operations and higher labor costs reflecting increased staffing levels. Higher depreciation expense in 2007 reflected capital additions since the end of 2006. The increase in the deferral of new regulatory assets for 2007 was primarily due to higher  MISO costs deferred in excess of transmission revenues.

Other Income

Other income decreased $37 million in 2007 compared with 2006 primarily due to reductions in interest income on notes receivable resulting from principal payments from associated companies since the end of 2006, partially offset by lower interest expense.

Interest Rate Risk

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

14

Comparison of Carrying Value to Fair Value
																There-						Fair
Year of Maturity	2008			2009			2010			2011			2012			after			Total			Value
	(Dollars in millions)
Assets
Investments Other Than Cash
and Cash Equivalents-
Fixed Income	$	17		$	25		$	29		$	30		$	34		$	424		$	559		$	626
Average interest rate		8.2	%		8.5	%		8.6	%		8.6	%		8.7	%		7.5	%		7.7	%
Liabilities
Long-term Debt and Other
Long-Term Obligations:
Fixed rate	$	177		$	2		$	65		$	1		$	1		$	780		$	1,026		$	1,041
Average interest rate		4.1	%		8.0	%		5.5	%		9.7	%		9.7	%		6.4	%		6.0	%
Variable rate																$	156		$	156		$	156
Average interest rate																	3.7	%		3.7	%
Short-term Borrowings	$	53																	$	53		$	53
Average interest rate		4.8	%																	4.8	%

Equity Price Risk

Included in OEs nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $82 million as of December 31, 2007. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $8 million reduction in fair value as of December 31, 2007 (see Note 5). As part of the intra-system generation asset transfers (see Note 14), OEs nuclear decommissioning trust investments were transferred to NGC with the exception of its retained leasehold interests in nuclear generation assets.

Legal Proceedings

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

New Accounting Standards and Interpretations

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

15

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of Ohio Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Companys 2007 consolidated financial statements.

FirstEnergy Corp.s internal auditors, who are responsible to the Audit Committee of FirstEnergys Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.

FirstEnergys Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committees findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Companys independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management's programs to monitor compliance with the Companys policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 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 the Companys internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Companys internal control over financial reporting was effective as of December 31, 2007.

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.

16

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Ohio Edison Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder's equity and cash flows present fairly, in all material respects, the financial position of Ohio Edison Company and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

As discussed in the notes to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007 (Note 8), defined benefit pension and other postretirement plans as of December 31, 2006 (Note 4) and conditional asset retirement obligations as of December 31, 2005 (Note 2(G) and Note 11).

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

17

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2007			2006			2005
	(In thousands)
REVENUES (Note 3):
Electric sales	$	2,375,306		$	2,312,956		$	2,861,043
Excise and gross receipts tax collections		116,223			114,500			114,510
Total revenues		2,491,529			2,427,456			2,975,553
EXPENSES (Note 3):
Fuel		11,691			11,047			53,113
Purchased power		1,359,783			1,275,975			939,193
Nuclear operating costs		174,696			186,377			337,901
Other operating costs		381,339			378,717			404,763
Provision for depreciation		77,405			72,982			108,583
Amortization of regulatory assets		191,885			190,245			457,205
Deferral of new regulatory assets		(177,633	)		(159,465	)		(151,032	)
General taxes		181,104			180,446			193,284
Total expenses		2,200,270			2,136,324			2,343,010
OPERATING INCOME		291,259			291,132			632,543
OTHER INCOME (EXPENSE) (Note 3):
Investment income		85,848			130,853			99,269
Miscellaneous income (expense)		4,409			1,751			(25,190	)
Interest expense		(83,343	)		(90,355	)		(75,388	)
Capitalized interest		266			2,198			10,849
Subsidiary's preferred stock dividend requirements		-			(597	)		(1,689	)
Total other income		7,180			43,850			7,851
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		298,439			334,982			640,394
INCOME TAXES		101,273			123,343			309,996
INCOME BEFORE CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE		197,166			211,639			330,398
Cumulative effect of a change in accounting principle
(net of income tax benefit of $9,223,000) (Note 2(G))		-			-			(16,343	)
NET INCOME		197,166			211,639			314,055
PREFERRED STOCK DIVIDEND REQUIREMENTS
AND REDEMPTION PREMIUM		-			4,552			2,635
EARNINGS ON COMMON STOCK	$	197,166		$	207,087		$	311,420
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Ohio Edison Company
are an integral part of these statements.

18

OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2007		2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	732	$	712
Receivables-
Customers (less accumulated provisions of $8,032,000 and $15,033,000, respectively,
for uncollectible accounts)		248,990		234,781
Associated companies		185,437		141,084
Other (less accumulated provisions of $5,639,000 and $1,985,000, respectively,
for uncollectible accounts)		12,395		13,496
Notes receivable from associated companies		595,859		458,647
Prepayments and other		10,341		13,606
		1,053,754		862,326
UTILITY PLANT:
In service		2,769,880		2,632,207
Less - Accumulated provision for depreciation		1,090,862		1,021,918
		1,679,018		1,610,289
Construction work in progress		50,061		42,016
		1,729,079		1,652,305
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		258,870		1,219,325
Investment in lease obligation bonds (Note 6)		253,894		291,393
Nuclear plant decommissioning trusts		127,252		118,209
Other		36,037		38,160
		676,053		1,667,087
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		737,326		741,564
Pension assets		228,518		68,420
Property taxes		65,520		60,080
Unamortized sale and leaseback costs		45,133		50,136
Other		48,075		18,696
		1,124,572		938,896
	$	4,583,458	$	5,120,614
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	333,224	$	159,852
Short-term borrowings-
Associated companies		50,692		113,987
Other		2,609		3,097
Accounts payable-
Associated companies		174,088		115,252
Other		19,881		13,068
Accrued taxes		89,571		187,306
Accrued interest		22,378		24,712
Other		65,163		64,519
		757,606		681,793
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		1,576,175		1,972,385
Long-term debt and other long-term obligations		840,591		1,118,576
		2,416,766		3,090,961
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		781,012		674,288
Accumulated deferred investment tax credits		16,964		20,532
Asset retirement obligations		93,571		88,223
Retirement benefits		178,343		167,379
Deferred revenues - electric service programs		46,849		86,710
Other		292,347		310,728
		1,409,086		1,347,860
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	4,583,458	$	5,120,614
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of
these balance sheets.

19

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2007			2006
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, 175,000,000 shares authorized,
60 and 80 shares outstanding, respectively	$	1,220,512		$	1,708,441
Accumulated other comprehensive income (Note 2(F))		48,386			3,208
Retained earnings (Note 10(A))		307,277			260,736
Total		1,576,175			1,972,385
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 10(C)):
Ohio Edison Company-
Secured notes:
5.375% due 2028		13,522			13,522
*   3.780% due 2029		-			100,000
*   3.750% due 2029		-			6,450
7.008% weighted average interest rate due 2007-2010		3,900			8,253
Total		17,422			128,225
Unsecured notes:
4.000% due 2008		175,000			175,000
*   3.400% due 2014		50,000			50,000
5.450% due 2015		150,000			150,000
6.400% due 2016		250,000			250,000
*   3.850% due 2018		33,000			33,000
*   3.800% due 2018		23,000			23,000
*   3.750% due 2023		50,000			50,000
6.875% due 2036		350,000			350,000
Total		1,081,000			1,081,000
Pennsylvania Power Company-
First mortgage bonds:
9.740% due 2007-2019		11,721			12,695
7.625% due 2023		6,500			6,500
Total		18,221			19,195
Secured notes:
5.400% due 2013		1,000			1,000
5.375% due 2028		1,734			1,734
Total		2,734			2,734
Unsecured notes:
5.390% due 2010 to associated company		62,900			62,900
Total		62,900			62,900
Capital lease obligations (Note 6)		329			362
Net unamortized discount on debt		(8,791	)		(15,988	)
Long-term debt due within one year		(333,224	)		(159,852	)
Total long-term debt and other long-term obligations		840,591			1,118,576
TOTAL CAPITALIZATION	$	2,416,766		$	3,090,961
* Denotes variable rate issue with applicable year-end interest rate shown.
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an
integral part of these statements.

20

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
										Accumulated
				Common Stock						Other
	Comprehensive			Number			Carrying			Comprehensive			Retained
	Income			of Shares			Value			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2005					100		$	2,098,729		$	(47,118	)	$	442,198
Net income	$	314,055												314,055
Minimum liability for unfunded retirement
benefits, net of $49,027,000 of income taxes		69,463									69,463
Unrealized loss on investments, net of
$13,068,000 of income tax benefits		(18,251	)								(18,251	)
Comprehensive income	$	365,267
Affiliated company asset transfers								198,147						(106,774	)
Restricted stock units								32
Preferred stock redemption adjustment								345
Cash dividends on preferred stock														(2,635	)
Cash dividends on common stock														(446,000	)
Balance, December 31, 2005					100			2,297,253			4,094			200,844
Net income	$	211,639												211,639
Unrealized gain on investments, net of
$4,455,000 of income taxes		7,954									7,954
Comprehensive income	$	219,593
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $22,287,000 of income tax benefits (Note 4)											(8,840	)
Affiliated company asset transfers								(87,893	)
Restricted stock units								58
Stock based compensation								82
Repurchase of common stock					(20	)		(500,000	)
Preferred stock redemption adjustments								(1,059	)					604
Preferred stock redemption premiums														(2,928	)
Cash dividends on preferred stock														(1,423	)
Cash dividends on common stock														(148,000	)
Balance, December 31, 2006					80			1,708,441			3,208			260,736
Net income	$	197,166												197,166
Unrealized gain on investments, net of
$2,784,000 of income taxes		3,874									3,874
Pension and other postretirement benefits, net
of $37,820,000 of income taxes (Note 4)		41,304									41,304
Comprehensive income	$	242,344
Restricted stock units								129
Stock based compensation								17
Repurchase of common stock					(20	)		(500,000	)
Consolidated tax benefit allocation								11,925
FIN 48 cumulative effect adjustment														(625	)
Cash dividends on common stock														(150,000	)
Balance, December 31, 2007					60		$	1,220,512		$	48,386		$	307,277
The accompanying Combined Notes to Consolidated Financial Statements as the relate to Ohio Edison Company are an integral
part of these statements.

21

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2007			2006			2005
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	197,166		$	211,639		$	314,055
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		77,405			72,982			108,583
Amortization of regulatory assets		191,885			190,245			457,205
Deferral of new regulatory assets		(177,633	)		(159,465	)		(151,032	)
Nuclear fuel and lease amortization		33			735			45,769
Amortization of lease costs		(7,425	)		(7,928	)		(6,365	)
Deferred income taxes and investment tax credits, net		423			(68,259	)		(29,750	)
Accrued compensation and retirement benefits		(46,313	)		5,004			14,506
Cumulative effect of a change in accounting principle		-			-			16,343
Pension trust contributions		(20,261	)		-			(106,760	)
Decrease (increase) in operating assets-
Receivables		(57,461	)		103,925			84,688
Materials and supplies		-			-			(3,367	)
Prepayments and other current assets		3,265			1,275			(1,778	)
Increase (decrease) in operating liabilities-
Accounts payable		65,649			(53,798	)		45,149
Accrued taxes		(81,079	)		23,436			10,470
Accrued interest		(2,334	)		16,379			(3,659	)
Electric service prepayment programs		(39,861	)		(34,983	)		121,692
Other		6,096			5,882			(464	)
Net cash provided from operating activities		109,555			307,069			915,285
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			592,180			146,450
Short-term borrowings, net		-			-			26,404
Redemptions and Repayments-
Common stock		(500,000	)		(500,000	)		-
Preferred stock		-			(78,480	)		(37,750	)
Long-term debt		(112,497	)		(613,002	)		(414,020	)
Short-term borrowings, net		(114,475	)		(186,511	)		-
Dividend Payments-
Common stock		(150,000	)		(148,000	)		(446,000	)
Preferred stock		-			(1,423	)		(2,635	)
Net cash used for financing activities		(876,972	)		(935,236	)		(727,551	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(145,311	)		(123,210	)		(266,823	)
Sales of investment securities held in trusts		37,736			39,226			283,816
Purchases of investment securities held in trusts		(43,758	)		(41,300	)		(315,356	)
Loan repayments from (loans to) associated companies, net		(79,115	)		78,101			(35,553	)
Collection of principal on long-term notes receivable		960,327			553,734			199,848
Cash investments		37,499			112,584			(49,270	)
Other		59			8,815			(4,697	)
Net cash provided from (used for) investing activities		767,437			627,950			(188,035	)
Net increase (decrease) in cash and cash equivalents		20			(217	)		(301	)
Cash and cash equivalents at beginning of year		712			929			1,230
Cash and cash equivalents at end of year	$	732		$	712		$	929
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	80,958		$	57,243		$	67,239
Income taxes	$	133,170		$	156,610		$	285,819
The accompanying Combined Notes to Consolidated Financial Statements as the relate to Ohio Edison Company are an integral part of
these statements.

22

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

Results of Operations

Earnings on common stock in 2007 decreased to $276 million from $306 million in 2006. The decrease resulted primarily from higher purchased power costs, higher other operating costs and lower investment income, partially offset by higher electric sales revenues and the deferral of new regulatory assets.

Revenues

Revenues increased by $53 million or 3% in 2007 compared to 2006 primarily due to higher retail generation and distribution revenues, partially offset by a decrease in wholesale generation revenues.

Retail generation revenues increased by $38 million in 2007 compared to 2006 due to increased KWH sales and higher composite unit prices for all customer classes.  Higher weather-related usage in 2007 compared to  2006 primarily contributed to the increased KWH sales in the residential and commercial sectors (cooling degree days increased 28% and heating degree days increased 10% from 2006).   Increased KWH sales in the industrial sector reflected a slight decrease in customer shopping.

Increases in retail generation sales and revenues in 2007 compared to 2006 are summarized in the following tables:

Retail Generation KWH Sales	Increase
Residential		3.9	%
Commercial		5.3	%
Industrial		0.9	%
Increase in Retail Generation Sales		2.8	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	11
Commercial		17
Industrial		10
Increase in Generation Revenues	$	38

Wholesale generation revenues decreased by $4 million in 2007 compared to 2006, primarily due to the assignment of CEIs leasehold interests in the Bruce Mansfield Plant to FGCO on October 16, 2007. Prior to the assignment, CEI sold power from its interests in the plant to FGCO.

Revenues from distribution throughput increased by $17 million in 2007 compared to 2006 primarily due to increased KWH deliveries to all customer classes, partially offset by lower composite unit prices. Increased KWH deliveries were primarily a result of the weather effects in 2007 compared to 2006 as described above.

Changes in distribution KWH deliveries and revenues in 2007 compared to 2006 are summarized in the following tables.

Distribution KWH Deliveries	Increase
Residential		4.2	%
Commercial		3.2	%
Industrial		0.5	%
Increase in Distribution Deliveries		2.2	%

23

Distribution Revenues	Increase (Decrease)
	(In millions)
Residential	$	10
Commercial		9
Industrial		(2	)
Net Increase in Distribution Revenues	$	17

Expenses

Total expenses increased by $67 million in 2007 compared to 2006. The following table presents the change from the prior year by expense category:

Expenses  - Changes	Increase (Decrease)
	(In millions)
Fuel costs	$	(10	)
Purchased power costs		44
Other operating costs		19
Provision for depreciation		11
Amortization of regulatory assets		17
Deferral of new regulatory assets		(21	)
General taxes		7
Net Increase in Expenses	$	67

Lower fuel costs resulted from the assignment of CEIs leasehold interests in the Bruce Mansfield Plant to FGCO as described above. Prior to the assignment, CEI incurred fuel expenses on its leasehold interest in the plant. Higher purchased power costs in 2007 compared to 2006 primarily reflect higher unit prices associated with the PSA with FES and an increase in purchased power to meet CEIs higher retail generation sales requirements. Higher other operating costs in 2007 compared to 2006 reflect increases in MISO transmission expenses due to increased transmission volumes. The increased depreciation in 2007 is primarily due to property additions since 2006 as well as the absence of a credit adjustment recognized in 2006 ($6.5 million pre-tax and $4 million after tax).

The increased amortization of regulatory assets in 2007 compared to 2006 was due to increased transition cost amortization reflecting the higher KWH sales discussed above and increases due to the impact from using the effective interest method.  The increase in the deferral of new regulatory assets in 2007 reflects a higher level of MISO costs deferred in excess of transmission revenues and increased carrying charges deferred under CEIs RCP. General taxes were higher in 2007 compared to 2006 primarily as a result of higher real and personal property taxes.

Other Expense

Other expense increased by $41 million due to lower investment income on associated company notes receivable in 2007, primarily due to repayments from FGCO and NGC in December 2006 related to the generation asset transfers.

Interest Rate Risk

CEI has little exposure to fluctuations in market interest rates because most of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for CEIs investment portfolio and debt obligations.

24

Comparison of Carrying Value to Fair Value
																There-						Fair
Year of Maturity	2008			2009			2010			2011			2012			after			Total			Value
	(Dollars in millions)
Assets
Investments Other Than Cash
and Cash Equivalents-
Fixed Income	$	38		$	37		$	49		$	53		$	66		$	221		$	464		$	532
Average interest rate		7.7	%		7.7	%		7.7	%		7.7	%		7.7	%		7.7	%		7.7	%
Liabilities
Long-term Debt and Other
Long-Term Obligations:
Fixed rate	$	125		$	162		$	18		$	20		$	22		$	1,237		$	1,584		$	1,624
Average interest rate		6.9	%		7.4	%		7.7	%		7.7	%		7.7	%		6.4	%		6.6	%
Variable rate																$	82		$	82		$	82
Average interest rate																	3.8	%		3.8	%
Short-term Borrowings	$	532		$															$	532		$	532
Average interest rate		5.1	%																	5.1	%

Legal Proceedings

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

New Accounting Standards and Interpretations

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

25

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of The Cleveland Electric Illuminating Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Companys 2007 consolidated financial statements.

FirstEnergy Corp.s internal auditors, who are responsible to the Audit Committee of FirstEnergys Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.

FirstEnergys Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committees findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Companys independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management's programs to monitor compliance with the Companys policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 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 the Companys internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Companys internal control over financial reporting was effective as of December 31, 2007.

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.

26

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of Directors of

The Cleveland Electric Illuminating Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder's equity and cash flows present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in the notes to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007 (Note 8), defined benefit pension and other postretirement plans as of December 31, 2006 (Note 4) and conditional asset retirement obligations as of December 31, 2005 (Note 2(G) and Note 11).

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

27

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2007			2006			2005
	(In thousands)
REVENUES (Note 3):
Electric sales	$	1,753,385		$	1,702,089		$	1,799,211
Excise tax collections		69,465			67,619			68,950
Total revenues		1,822,850			1,769,708			1,868,161
EXPENSES (Note 3):
Fuel		40,551			50,291			85,993
Purchased power		748,214			704,517			557,593
Nuclear operating costs		-			-			142,698
Other operating costs		310,274			290,904			301,366
Provision for depreciation		75,238			63,589			127,959
Amortization of regulatory assets		144,370			127,403			227,221
Deferral of new regulatory assets		(149,556	)		(128,220	)		(163,245	)
General taxes		141,551			134,663			152,678
Total expenses		1,310,642			1,243,147			1,432,263
OPERATING INCOME		512,208			526,561			435,898
OTHER INCOME (EXPENSE) (Note 3):
Investment income		57,724			100,816			86,898
Miscellaneous income (expense)		7,902			6,428			(9,031	)
Interest expense		(138,977	)		(141,710	)		(132,226	)
Capitalized interest		918			2,618			2,533
Total other expense		(72,433	)		(31,848	)		(51,826	)
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		439,775			494,713			384,072
INCOME TAXES		163,363			188,662			153,014
INCOME BEFORE CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE		276,412			306,051			231,058
Cumulative effect of a change in accounting principle (net of income
tax benefit of $2,101,000) (Note 2(G))		-			-			(3,724	)
NET INCOME		276,412			306,051			227,334
PREFERRED STOCK DIVIDEND REQUIREMENTS		-			-			2,918
EARNINGS ON COMMON STOCK	$	276,412		$	306,051		$	224,416
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.

28

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2007		2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	232	$	221
Receivables-
Customers (less accumulated provisions of $7,540,000 and		251,000		245,193
$6,783,000, respectively, for uncollectible accounts)
Associated companies		166,587		249,735
Other		12,184		14,240
Notes receivable from associated companies		52,306		27,191
Prepayments and other		2,327		2,314
		484,636		538,894
UTILITY PLANT:
In service		2,256,956		2,136,766
Less - Accumulated provision for depreciation		872,801		819,633
		1,384,155		1,317,133
Construction work in progress		41,163		46,385
		1,425,318		1,363,518
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		-		486,634
Investment in lessor notes (Note 7)		463,431		519,611
Other		10,285		13,426
		473,716		1,019,671
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,688,521		1,688,521
Regulatory assets		870,695		854,588
Pension assets (Note 4)		62,471		-
Property taxes		76,000		65,000
Other		32,987		33,306
		2,730,674		2,641,415
	$	5,114,344	$	5,563,498
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	207,266	$	120,569
Short-term borrowings-
Associated companies		531,943		218,134
Accounts payable-
Associated companies		169,187		365,678
Other		5,295		7,194
Accrued taxes		94,991		128,829
Accrued interest		13,895		19,033
Lease market valuation liability		-		60,200
Other		34,350		52,101
		1,056,927		971,738
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		1,489,835		1,468,903
Long-term debt and other long-term obligations		1,459,939		1,805,871
		2,949,774		3,274,774
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		725,523		470,707
Accumulated deferred investment tax credits		18,567		20,277
Lease market valuation liability		-		547,800
Retirement benefits		93,456		122,862
Deferred revenues - electric service programs		27,145		51,588
Lease assignment payable to associated companies		131,773		-
		111,179		103,752
		1,107,643		1,316,986
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	5,114,344	$	5,563,498
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
Company are an integral part of these balance sheets.

29

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2007			2006
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, 105,000,000 shares authorized,
67,930,743 shares outstanding	$	873,536		$	860,133
Accumulated other comprehensive loss (Note 2(F))		(69,129	)		(104,431	)
Retained earnings (Note 10(A))		685,428			713,201
Total		1,489,835			1,468,903
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 10(C)):
First mortgage bonds-
6.860% due 2008		125,000			125,000
Total		125,000			125,000
Secured notes-
7.130% due 2007		-			120,000
7.430% due 2009		150,000			150,000
7.880% due 2017		300,000			300,000
6.000% due 2020		-			62,560
6.100% due 2020		-			70,500
5.375% due 2028		5,993			5,993
*   3.750% due 2030		81,640			81,640
*   3.650% due 2035		-			53,900
Total		537,633			844,593
Unsecured notes-
6.000% due 2013		-			78,700
5.650% due 2013		300,000			300,000
5.700% due 2017		250,000			-
9.000% due 2031		-			103,093
5.950% due 2036		300,000			300,000
7.651% due to associated companies 2008-2016 (Note 7)		153,044			167,696
Total		1,003,044			949,489
Capital lease obligations (Note 6)		3,748			4,371
Net unamortized premium (discount) on debt		(2,220	)		2,987
Long-term debt due within one year		(207,266	)		(120,569	)
Total long-term debt and other long-term obligations		1,459,939			1,805,871
TOTAL CAPITALIZATION	$	2,949,774		$	3,274,774
* Denotes variable rate issue with applicable year-end interest rate shown.
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
Company are an integral part of these statements.

30

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
										Accumulated
				Common Stock						Other
	Comprehensive			Number			Carrying			Comprehensive			Retained
	Income			of Shares			Value			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2005					79,590,689		$	1,281,962		$	17,859		$	553,740
Net income	$	227,334												227,334
Unrealized loss on investments, net of
$27,734,000 of income tax benefits		(39,472	)								(39,472	)
Minimum liability for unfunded retirement benefits,
net of $15,186,000 of income taxes		21,613									21,613
Comprehensive income	$	209,475
Equity contribution from parent								75,000
Affiliated company asset transfers								(2,086	)
Restricted stock units								48
Cash dividends on preferred stock														(2,924	)
Cash dividends on common stock														(191,000	)
Balance, December 31, 2005					79,590,689			1,354,924			-			587,150
Net income and comprehensive income	$	306,051												306,051
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $69,609,000 of income tax benefits (Note 4)											(104,431	)
Repurchase of common stock					(11,659,946	)		(300,000	)
Affiliated company asset transfers								(194,910	)
Restricted stock units								86
Stock based compensation								33
Cash dividends on common stock														(180,000	)
Balance, December 31, 2006					67,930,743			860,133			(104,431	)		713,201
Net income	$	276,412												276,412
Pension and other postretirement benefits, net
of $30,705,000 of income taxes (Note 4)		35,302									35,302
Comprehensive income	$	311,714
Restricted stock units								184
Stock based compensation								10
Consolidated tax benefit allocation								13,209
FIN 48 cumulative effect adjustment														(185	)
Cash dividends on common stock														(304,000	)
Balance, December 31, 2007					67,930,743		$	873,536		$	(69,129	)	$	685,428
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.

31

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,		2007			2006			2005
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	276,412		$	306,051		$	227,334
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation			75,238			63,589			127,959
Amortization of regulatory assets			144,370			127,403			227,221
Deferral of new regulatory assets			(149,556	)		(128,220	)		(163,245	)
Nuclear fuel and capital lease amortization			235			239			25,803
Deferred rents and lease market valuation liability			(357,679	)		(71,943	)		(67,353	)
Deferred income taxes and investment tax credits, net			(22,767	)		(17,093	)		42,024
Accrued compensation and retirement benefits			3,196			2,367			4,624
Cumulative effect of a change in accounting principle			-			-			3,724
Pension trust contributions			(24,800	)		-			(93,269	)
Tax refund related to pre-merger period			-			-			9,636
Decrease (increase) in operating assets-
Receivables			209,426			(137,711	)		(103,018	)
Materials and supplies			-			-			(12,934	)
Prepayments and other current assets			(152	)		160			233
Increase (decrease) in operating liabilities-
Accounts payable			(216,638	)		293,214			(82,434	)
Accrued taxes			(33,659	)		7,342			(7,967	)
Accrued interest			(5,138	)		147			(3,216	)
Electric service prepayment programs			(24,443	)		(19,673	)		53,447
Other			471			(6,626	)		(40,878	)
Net cash provided from (used for) operating activities			(125,484	)		419,246			147,691
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt			247,362			295,662			141,004
Short-term borrowings, net			277,581			-			155,883
Equity contribution from parent			-			-			75,000
Redemptions and Repayments-
Common stock			-			(300,000	)		-
Preferred stock			-			-			(101,900	)
Long-term debt			(493,294	)		(376,702	)		(147,923	)
Short-term borrowings, net			-			(143,272	)		-
Dividend Payments-
Common stock			(304,000	)		(180,000	)		(191,000	)
Preferred stock			-			-			(2,260	)
Net cash used for financing activities			(272,351	)		(704,312	)		(71,196	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(149,131	)		(119,795	)		(148,783	)
Loan repayments from (loans to) associated companies, net			6,714			(7,813	)		(387,746	)
Collection of principal on long-term notes receivable			486,634			376,135			466,378
Investments in lessor notes			56,179			44,556			32,479
Sales of investment securities held in trusts			-			-			490,126
Purchases of investment securities held in trusts			-			-			(519,150	)
Other			(2,550	)		(8,003	)		(9,789	)
Net cash provided from (used for) investing activities			397,846			285,080			(76,485	)
Net increase in cash and cash equivalents			11			14			10
Cash and cash equivalents at beginning of year			221			207			197
Cash and cash equivalents at end of year		$	232		$	221		$	207
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)		$	141,390		$	135,276		$	144,730
Income taxes		$	186,874		$	180,941		$	116,323
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.

32

THE TOLEDO EDISON COMPANY

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

Results of Operations

Earnings on common stock in 2007 increased to $91 million from $90 million in 2006. The increase resulted primarily from higher electric sales revenues, the deferral of new regulatory assets and lower preferred stock dividend requirements, partially offset by increased operating expenses, increased interest expense and lower investment income.

Revenues

Revenues increased $36 million or 3.9% in 2007 compared to 2006 primarily due to increases in retail generation revenues ($26 million), distribution revenues ($13 million) and other revenues ($2 million), partially offset by lower wholesale generation revenues ($5 million). Retail generation revenues increased in 2007 due to higher average prices and increased KWH sales across all customer classes compared to 2006. Average prices increased primarily due to higher composite unit prices for retail generation shopping customers returning to TE. The increase in sales volume reflects increased weather-related usage in 2007 (heating and cooling degree days increased 11.1% and 14.0%, respectively, from 2006). The lower wholesale generation revenues resulted from decreased sales to associated companies ($3 million) and non-associated companies ($2 million).

Increases in retail electric generation KWH sales and revenues in 2007 from 2006 are summarized in the following tables.

Retail Generation KWH Sales	Increase
Residential		6.5	%
Commercial		3.0	%
Industrial		1.2	%
Increase in Retail Generation  Sales		2.8	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	9
Commercial		5
Industrial		12
Increase in Retail Generation Revenues	$	26

Revenues from distribution throughput increased by $13 million in 2007 compared to 2006 due to higher KWH deliveries to all customer sectors and higher average unit prices for residential and commercial customers, partially offset by lower average unit prices for industrial customers. The higher KWH deliveries to residential and commercial customers in 2007 reflected the weather impacts described above.

Changes in distribution KWH deliveries and revenues in 2007 from 2006 are summarized in the following tables.

Distribution KWH Deliveries	Increase
Residential		4.4	%
Commercial		2.4	%
Industrial		1.3	%
Increase in Distribution Deliveries		2.3	%

33

Distribution Revenues	Increase (Decrease)
	(In millions)
Residential	$	9
Commercial		5
Industrial		(1	)
Net Increase in Distribution Revenues	$	13

Expenses

Total expenses increased $29 million in 2007 from 2006. The following table presents changes from the prior year by expense category:

Expenses Changes	Increase (Decrease)
	(In millions)
Fuel costs	$	(5	)
Purchased power costs		30
Nuclear operating costs		(10	)
Other operating costs		10
Provision for depreciation		3
Amortization of regulatory assets		9
Deferral of new regulatory assets		(8	)
Net increase in expenses	$	29

Lower fuel costs in 2007 compared to 2006 were primarily due to the assignment of TE's leasehold interests in the Bruce Mansfield Plant to FGCO effective October 16, 2007. Higher purchased power costs reflected higher unit prices associated with the PSA with FES and an increase in purchased power to meet the higher retail generation sales requirements. Lower nuclear operating costs in 2007 resulted primarily from the absence of a nuclear refueling outage in 2007. TE has a leasehold interest in Beaver Valley Unit 2, which had a 42-day extended nuclear refueling outage in 2006.

Other operating costs were higher primarily due to a $15 million increase in MISO network transmission expenses in 2007, partially offset by a $4 million decrease in Bruce Mansfield Plant lease expenses. Depreciation expense was higher due to an increase in depreciable property, reflecting plant additions in 2007. Higher amortization of regulatory assets was due to increased amortization of transition cost deferrals ($5 million) and MISO transmission cost deferrals ($4 million). The change in the deferral of new regulatory assets was primarily due to increased deferrals for MISO transmission expenses ($8 million) and RCP distribution costs ($3 million), partially offset by lower deferred shopping incentive interest ($2 million) and RCP fuel cost deferrals ($2 million).

Other Expense

Other expense increased $21 million in 2007 compared to 2006 primarily due to lower investment income and higher interest expense. The decrease in investment income resulted primarily from the principal repayments in 2007 on notes receivable from associated companies. The higher interest expense is principally associated with new long-term debt issued in November 2006.

Interest Rate Risk

TE has little exposure to fluctuations in market interest rates because most of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for TEs investment portfolio and debt obligations.

34

Comparison of Carrying Value to Fair Value
																There-						Fair
Year of Maturity	2008			2009			2010			2011			2012			after			Total			Value
	(Dollars in millions)
Assets
Investments Other Than Cash and Cash Equivalents-
Fixed Income	$	15		$	12		$	18		$	21		$	22		$	183		$	271		$	304
Average interest rate		7.7	%		7.7	%		7.7	%		7.7	%		7.7	%		6.7	%		7.0	%
Liabilities
Long-term Debt:
Fixed rate																$	304		$	304		$	283
Average interest rate																	6.1	%		6.1	%
Short-term Borrowings	$	13																	$	13		$	13
Average interest rate		5.0	%																	5.0	%

Legal Proceedings

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

New Accounting Standards and Interpretations

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

35

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of The Toledo Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Companys 2007 consolidated financial statements.

FirstEnergy Corp.s internal auditors, who are responsible to the Audit Committee of FirstEnergys Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.

FirstEnergys Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committees findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Companys independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management's programs to monitor compliance with the Companys policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 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 the Companys internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Companys internal control over financial reporting was effective as of December 31, 2007.

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.

36

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of The Toledo Edison Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder's equity and cash flows present fairly, in all material respects, the financial position of The Toledo Edison Company and its subsidiary at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in the notes to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007 (Note 8) and defined benefit pension and other postretirement plans as of December 31, 2006 (Note 4).

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

37

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2007			2006			2005
	(In thousands)
REVENUES (Note 3):
Electric sales	$	934,772		$	899,930		$	1,011,239
Excise tax collections		29,173			28,071			28,947
Total revenues		963,945			928,001			1,040,186
EXPENSES (Note 3):
Fuel		31,199			36,313			58,897
Purchased power		398,423			368,654			296,720
Nuclear operating costs		71,657			81,845			181,410
Other operating costs		176,191			166,403			168,522
Provision for depreciation		36,743			33,310			62,486
Amortization of regulatory assets		104,348			95,032			141,343
Deferral of new regulatory assets		(62,664	)		(54,946	)		(58,566	)
General taxes		50,640			50,869			57,108
Total expenses		806,537			777,480			907,920
OPERATING INCOME		157,408			150,521			132,266
OTHER INCOME (EXPENSE) (Note 3):
Investment income		27,713			38,187			49,440
Miscellaneous expense		(6,651	)		(7,379	)		(10,587	)
Interest expense		(34,135	)		(23,179	)		(21,489	)
Capitalized interest		640			1,123			465
Total other income (expense)		(12,433	)		8,752			17,829
INCOME BEFORE INCOME TAXES		144,975			159,273			150,095
INCOME TAXES		53,736			59,869			73,931
NET INCOME		91,239			99,404			76,164
PREFERRED STOCK DIVIDEND REQUIREMENTS		-			9,409			7,795
EARNINGS ON COMMON STOCK	$	91,239		$	89,995		$	68,369
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company
are an integral part of these statements.

38

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2007		2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	22	$	22
Receivables-
Customers		449		772
Associated companies		88,796		13,940
Other (less accumulated provisions of $615,000 and $430,000,
respectively, for uncollectible accounts)		3,116		3,831
Notes receivable from associated companies		154,380		100,545
Prepayments and other		865		851
		247,628		119,961
UTILITY PLANT:
In service		931,263		894,888
Less - Accumulated provision for depreciation		420,445		394,225
		510,818		500,663
Construction work in progress		19,740		16,479
		530,558		517,142
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		154,646		169,493
Long-term notes receivable from associated companies		37,530		128,858
Nuclear plant decommissioning trusts		66,759		61,094
Other		1,756		1,871
		260,691		361,316
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		500,576		500,576
Regulatory assets		203,719		247,595
Pension assets (Note 4)		28,601		-
Property taxes		21,010		22,010
		20,496		30,042
		774,402		800,223
	$	1,813,279	$	1,798,642
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	34	$	30,000
Accounts payable-
Associated companies		245,215		84,884
Other		4,449		4,021
Notes payable to associated companies		13,396		153,567
Accrued taxes		30,245		47,318
Lease market valuation liability		36,900		24,600
Other		22,747		37,551
		352,986		381,941
CAPITALIZATION (See Statements of Capitalization):
Common stockholder's equity		485,191		481,415
Long-term debt and other long-term obligations		303,397		358,281
		788,588		839,696
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		103,463		161,024
Accumulated deferred investment tax credits		10,180		11,014
Lease market valuation liability		310,000		218,800
Retirement benefits		63,215		77,843
Asset retirement obligations		28,366		26,543
Deferred revenues - electric service programs		12,639		23,546
Lease assignment payable to associated companies		83,485		-
Other		60,357		58,235
		671,705		577,005
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	1,813,279	$	1,798,642
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an
integral part of these balance sheets.

39

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2007			2006
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, $5 par value, 60,000,000 shares authorized,
29,402,054 shares outstanding	$	147,010		$	147,010
Other paid-in capital		173,169			166,786
Accumulated other comprehensive loss (Note 2(F))		(10,606	)		(36,804	)
Retained earnings (Note 10(A))		175,618			204,423
Total		485,191			481,415
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 10(C)):
Secured notes-
7.130% due 2007		-			30,000
6.100% due 2027		-			10,100
5.375% due 2028		3,751			3,751
*   3.750% due 2035		-			45,000
Total		3,751			88,851
Unsecured notes-
6.150% due 2037		300,000			300,000
Total		300,000			300,000
Capital lease obligations (Note 6)		114			-
Net unamortized discount on debt		(434	)		(570	)
Long-term debt due within one year		(34	)		(30,000	)
Total long-term debt		303,397			358,281
TOTAL CAPITALIZATION	$	788,588		$	839,696
* Denotes variable-rate issue with applicable year-end interest rate shown.
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company
are an integral part of these statements.

40

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
													Accumulated
				Common Stock						Other			Other
	Comprehensive			Number			Par			Paid-In			Comprehensive			Retained
	Income			of Shares			Value			Capital			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2005					39,133,887		$	195,670		$	428,559		$	20,039		$	191,059
Net income	$	76,164															76,164
Unrealized loss on investments, net
of $16,884,000 of income tax benefits		(23,654	)											(23,654	)
Minimum liability for unfunded retirement benefits,
net of $5,836,000 of income taxes		8,305												8,305
Comprehensive income	$	60,815
Affiliated company asset transfers											45,060
Restricted stock units											19
Cash dividends on preferred stock																	(7,795	)
Cash dividends on common stock																	(70,000	)
Balance, December 31, 2005					39,133,887			195,670			473,638			4,690			189,428
Net income	$	99,404															99,404
Unrealized gain on investments, net
of $211,000 of income taxes		462												462
Comprehensive income	$	99,866
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $26,929,000 of income tax benefits (Note 4)														(41,956	)
Affiliated company asset transfers											(130,571	)
Repurchase of common stock					(9,731,833	)		(48,660	)		(176,341	)
Preferred stock redemption premiums																	(4,840	)
Restricted stock units											38
Stock based compensation											22
Cash dividends on preferred stock																	(4,569	)
Cash dividends on common stock																	(75,000	)
Balance, December 31, 2006					29,402,054			147,010			166,786			(36,804	)		204,423
Net income	$	91,239															91,239
Unrealized gain on investments, net
of $1,089,000 of income taxes		1,901												1,901
Pension and other postretirement benefits, net
of $15,077,000 of income taxes (Note 4)		24,297												24,297
Comprehensive income	$	117,437
Restricted stock units											53
Stock based compensation											2
Consolidated tax benefit allocation											6,328
FIN 48 cumulative effect adjustment																	(44	)
Cash dividends on common stock																	(120,000	)
Balance, December 31, 2007					29,402,054		$	147,010		$	173,169		$	(10,606	)	$	175,618
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral
part of these statements.

41

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2007			2006			2005
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	91,239		$	99,404		$	76,164
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		36,743			33,310			62,486
Amortization of regulatory assets		104,348			95,032			141,343
Deferral of new regulatory assets		(62,664	)		(54,946	)		(58,566	)
Nuclear fuel and capital lease amortization		23			-			18,463
Deferred rents and lease market valuation liability		265,981			(32,925	)		(30,088	)
Deferred income taxes and investment tax credits, net		(26,318	)		(37,133	)		(6,519	)
Accrued compensation and retirement benefits		5,276			4,415			5,396
Pension trust contributions		(7,659	)		-			(19,933	)
Tax refund related to pre-merger period		-			-			8,164
Decrease (increase) in operating assets-
Receivables		(64,489	)		6,387			10,813
Materials and supplies		-			-			(3,210	)
Prepayments and other current assets		(13	)		208			91
Increase (decrease) in operating liabilities-
Accounts payable		43,722			39,847			(45,416	)
Accrued taxes		(14,954	)		(2,026	)		2,387
Accrued interest		(1,350	)		1,899			(1,557	)
Electric service prepayment programs		(10,907	)		(9,060	)		32,605
Other		5,165			4,640			(36,939	)
Net cash provided from operating activities		364,143			149,052			155,684
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			296,663			45,000
Short-term borrowings, net		-			62,909			-
Redemptions and Repayments-
Common stock		-			(225,000	)		-
Preferred stock		-			(100,840	)		(30,000	)
Long-term debt		(85,797	)		(202,550	)		(138,859	)
Short-term borrowings, net		(153,567	)		-			(8,996	)
Dividend Payments-
Common stock		(120,000	)		(75,000	)		(70,000	)
Preferred stock		-			(4,569	)		(7,795	)
Net cash used for financing activities		(359,364	)		(248,387	)		(210,650	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(58,871	)		(61,232	)		(71,976	)
Loans to associated companies		(51,002	)		(52,178	)		(409,409	)
Collection of principal on long-term notes receivable		91,308			202,787			552,613
Redemption of lessor notes (Note 6)		14,847			9,305			11,894
Sales of investment securities held in trusts		44,682			53,458			365,807
Purchases of investment securities held in trusts		(47,853	)		(53,724	)		(394,348	)
Other		2,110			926			385
Net cash provided from (used for) investing activities		(4,779	)		99,342			54,966
Net change in cash and cash equivalents		-			7			-
Cash and cash equivalents at beginning of year		22			15			15
Cash and cash equivalents at end of year	$	22		$	22		$	15
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	33,841		$	17,785		$	29,709
Income taxes	$	73,845		$	95,753		$	78,265
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral
part of these statements.

42

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

Results of Operations

Earnings on common stock decreased to $186 million in 2007 from $190 million in 2006. The decrease was primarily due to higher purchased power costs, increased amortization of regulatory assets and higher interest expense, partially offset by higher electric sales revenues.

Revenues

Revenues increased $576 million or 22% in 2007 compared with 2006 due to higher retail generation revenues ($339 million), higher wholesale revenues ($98 million) and increased revenues from distribution throughput ($117 million). Retail generation sales revenues increased in 2007 from 2006 due to higher unit prices resulting from the BGS auctions effective June 1, 2006 and June 1, 2007, and higher retail generation KWH sales. Residential and commercial sales volumes increased as a result of higher weather-related usage in 2007 compared to 2006 (heating degree days were 15.6% higher and cooling degree days were 6.0% higher than in 2006). Industrial generation KWH sales declined in 2007 compared to 2006 due to an increase in customer shopping.

Revenues from wholesale sales increased in 2007 due to higher market prices in PJM, partially offset by a 1.9% decrease in sales volume compared to 2006.

Changes in retail generation KWH sales and revenues by customer class in 2007 compared to 2006 are summarized in the following table:

Retail Generation KWH Sales	Increase (Decrease)
Residential		3.1	%
Commercial		2.5	%
Industrial		(5.9	)%
Net Increase in Generation Sales		2.4	%

Retail Generation Revenues		Increase
	(In millions)
Residential		$	191
Commercial			139
Industrial			9
Increase in Generation Revenues		$	339

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

Changes in distribution KWH deliveries and revenues in 2007 compared to 2006 are summarized in the following tables.

Distribution KWH Deliveries	Increase
Residential		3.1	%
Commercial		4.4	%
Industrial		1.9	%
Increase in Distribution Deliveries		3.5	%

Distribution Revenues	Increase
	(In millions)
Residential	$	51
Commercial		56
Industrial		10
Increase in Distribution Revenues	$	117

43

The higher revenues for 2007 also included $17 million of increased revenues resulting from the August 2006 securitization of deferred costs associated with JCP&L's BGS supply. These higher revenues were offset by increased amortization and interest expense, resulting in no material effects to current period earnings.

Expenses

Total expenses increased by $560 million in 2007 as compared to 2006. The following table presents changes from the prior year by expense category:

Expenses  - Changes	Increase
	(In millions)
Purchased power costs	$	437
Other operating costs		5
Provision for depreciation		2
Amortization of regulatory assets		114
General taxes		2
Increase in expenses	$	560

The increase in purchased power costs primarily reflected higher unit prices resulting from the June 2006 and June 2007 BGS auctions and, to a lesser extent, higher generation KWH sales. Increased amortization of regulatory assets in 2007 was due to higher cost recovery associated with the December 2006 NUGC rate increase.

Other Expenses

Other expense increased $18 million in 2007 from 2006 primarily due to interest expense associated with JCP&L's $550 million issuance of senior unsecured notes in May 2007, lower miscellaneous income reflecting reduced market returns on insurance policies and the absence of gains on property sales in 2006.

Market Risk Information

JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergys Risk Policy Committee, comprised of members of senior management, provides general oversight to risk management activities.

Commodity Price Risk

JCP&L is exposed to market risk primarily due to fluctuations in electricity, energy transmission and natural gas prices. To manage the volatility relating to these exposures, JCP&L uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of JCP&L's derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the table below. Contracts that are not exempt from such treatment include power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during 2007 is summarized in the following table:

Decrease in the Fair Value of Derivative Contracts	Non-Hedge			Hedge		Total
	(In millions)
Change in the fair value of commodity derivative contracts:
Outstanding net liabilities as of January 1, 2007	$	(1,170	)	$	-	$	(1,170	)
Additions/Changes in value of existing contracts		116			-		116
Settled contracts		314			-		314
Net Liabilities - Derivatives Contracts as of December 31, 2007(1)	$	(740	)	$	-	$	(740	)
Impact of Changes in Commodity Derivative Contracts(2)
Income Statement Effects (Pre-Tax)	$	-		$	-	$	-
Balance Sheet Effects:
Regulatory Asset (Net)	$	(430	)	$	-	$	(430	)

(1) Includes $740 million in non-hedge commodity derivative contracts (primarily with NUGs) that are offset by a regulatory asset, with no impact to earnings.

(2) Represents the change in value of existing contracts, settled contracts and changes in techniques/ assumptions.

44

Derivatives are included on the Consolidated Balance Sheet as of December 31, 2007 as follows:

Balance Sheet Classification	Non-Hedge			Hedge		Total
	(In millions)
Non-Current-
Other deferred charges	$	9		$	-	$	9
Other noncurrent liabilities		(749	)		-		(749	)
Net liabilities	$	(740	)	$	-	$	(740	)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, JCP&L relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of December 31, 2007 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2008			2009			2010			2011			2012			Thereafter			Total
	(In millions)
Broker quote sheets	$	(226	)	$	(177	)	$	(157	)	$	(97	)	$	-		$	-		$	(657	)
Prices based on models		-			-			-			-			(28	)		(55	)		(83	)
Total(1)	$	(226	)	$	(177	)	$	(157	)	$	(97	)	$	(28	)	$	(55	)	$	(740	)

 (1) Includes $740 million in non-hedge commodity derivative contracts (primarily with NUGs) that are offset by a regulatory asset, with no impact to earnings.

JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on JCP&L's consolidated financial position or cash flows as of December 31, 2007. Based on derivative contracts held as of December 31, 2007, an adverse 10% change in commodity prices would not have a material effect on JCP&L's net income for the next 12 months.

Interest Rate Risk

JCP&L's exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for JCP&L's investment portfolio and debt obligations.

Comparison of Carrying Value to Fair Value
																There-						Fair
Year of Maturity	2008			2009			2010			2011			2012			after			Total			Value
(Dollars in millions)
Assets
Investments Other Than Cash and Cash Equivalents-
Fixed Income							$	1								$	248		$	249		$	249
Average interest rate								4.0	%								4.7	%		4.7	%
Liabilities
Long-term Debt:
Fixed rate	$	27		$	29		$	31		$	33		$	34		$	1,443		$	1,597		$	1,560
Average interest rate		5.3	%		5.3	%		5.4	%		5.6	%		5.7	%		5.8	%		5.8	%
Short-term Borrowings	$	130																	$	130		$	130
Average interest rate		5.0	%																	5.0	%

Equity Price Risk

Included in JCP&L's nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $102 million as of December 31, 2007. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $10 million reduction in fair value as of December 31, 2007 (see Note 5).

45

Legal Proceedings

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

New Accounting Standards and Interpretations

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

46

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of Jersey Central Power & Light Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Companys 2007 consolidated financial statements.

FirstEnergy Corp.s internal auditors, who are responsible to the Audit Committee of FirstEnergys Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.

FirstEnergys Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committees findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Companys independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management's programs to monitor compliance with the Companys policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 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 the Companys internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Companys internal control over financial reporting was effective as of December 31, 2007.

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.

47

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of Directors of

Jersey Central Power & Light Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder's equity and cash flows present fairly, in all material respects, the financial position of Jersey Central Power & Light Company and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in the notes to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007 (Note 8) and defined benefit pension and other postretirement plans as of December 31, 2006 (Note 4).

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

48

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2007			2006			2005
	(In thousands)
REVENUES (Note 3):
Electric sales	$	3,191,999		$	2,617,390		$	2,550,208
Excise tax collections		51,848			50,255			52,026
Total revenues		3,243,847			2,667,645			2,602,234
EXPENSES:
Purchased power (Note 3)		1,957,975			1,521,329			1,429,998
Other operating costs (Note 3)		325,814			320,847			375,502
Provision for depreciation		85,459			83,172			80,013
Amortization of regulatory assets		388,581			274,704			292,668
Deferral of new regulatory assets		-			-			(28,862	)
General taxes		66,225			63,925			64,538
Total expenses		2,824,054			2,263,977			2,213,857
OPERATING INCOME		419,793			403,668			388,377
OTHER INCOME (EXPENSE):
Miscellaneous income		8,570			13,323			10,084
Interest expense (Note 3)		(96,988	)		(83,411	)		(81,428	)
Capitalized interest		3,789			3,758			1,740
Total other expense		(84,629	)		(66,330	)		(69,604	)
INCOME BEFORE INCOME TAXES		335,164			337,338			318,773
INCOME TAXES		149,056			146,731			135,846
NET INCOME		186,108			190,607			182,927
PREFERRED STOCK DIVIDEND REQUIREMENTS		-			1,018			500
EARNINGS ON COMMON STOCK	$	186,108		$	189,589		$	182,427
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.

49

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2007		2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	94	$	41
Receivables-
Customers (less accumulated provisions of $3,691,000 and $3,524,000,
respectively, for uncollectible accounts)		321,026		254,046
Associated companies		21,297		11,574
Other		59,244		40,023
Notes receivable - associated companies		18,428		24,456
Prepaid taxes		1,012		13,333
Other		17,603		20,119
		438,704		363,592
UTILITY PLANT:
In service		4,175,125		4,029,070
Less - Accumulated provision for depreciation		1,516,997		1,473,159
		2,658,128		2,555,911
Construction work in progress		90,508		78,728
		2,748,636		2,634,639
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		176,512		171,045
Nuclear plant decommissioning trusts		175,869		164,108
Other		2,083		2,047
		354,464		337,200
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		1,595,662		2,152,332
Goodwill		1,826,190		1,962,361
Pension assets		100,615		14,660
Other		16,307		17,781
		3,538,774		4,147,134
	$	7,080,578	$	7,482,565
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	27,206	$	32,683
Short-term borrowings-
Associated companies		130,381		186,540
Accounts payable-
Associated companies		7,541		80,426
Other		193,848		160,359
Cash collateral from suppliers		373		32,311
Other		115,355		112,048
		474,704		604,367
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		3,017,864		3,159,598
Long-term debt and other long-term obligations		1,560,310		1,320,341
		4,578,174		4,479,939
NONCURRENT LIABILITIES:
Power purchase contract loss liability		749,671		1,182,108
Accumulated deferred income taxes		800,214		803,944
Nuclear fuel disposal costs		192,402		183,533
Asset retirement obligations		89,669		84,446
Other		195,744		144,228
		2,027,700		2,398,259
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	7,080,578	$	7,482,565
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are
an integral part of these balance sheets.

50

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2007			2006
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, $10 par value, 16,000,000 shares authorized,
14,421,637 and 15,009,335 shares outstanding, respectively	$	144,216		$	150,093
Other paid-in capital		2,655,941			2,908,279
Accumulated other comprehensive loss (Note 2(F))		(19,881	)		(44,254	)
Retained earnings (Note 10(A))		237,588			145,480
Total		3,017,864			3,159,598
LONG-TERM DEBT (Note 10(C)):
First mortgage bonds-
7.100% due 2015		-			12,200
7.500% due 2023		-			125,000
6.750% due 2025		-			150,000
Total		-			287,200
Secured notes-
4.190% due 2007		-			17,942
5.390% due 2007-2010		52,273			52,297
5.250% due 2007-2012		41,631			56,348
5.810% due 2010-2013		77,075			77,075
6.160% due 2013-2017		99,517			99,517
5.410% due 2012-2014		25,693			25,693
5.520% due 2014-2018		49,220			49,220
5.625% due 2016		-			300,000
4.800% due 2018		-			150,000
5.610% due 2018-2021		51,139			51,139
6.400% due 2036		-			200,000
Total		396,548			1,079,231
Unsecured notes-
5.625% due 2016		300,000			-
5.650% due 2017		250,000			-
4.800% due 2018		150,000			-
6.400% due 2036		200,000			-
6.150% due 2037		300,000			-
Total		1,200,000			-
Net unamortized discount on debt		(9,032	)		(13,407	)
Long-term debt due within one year		(27,206	)		(32,683	)
Total long-term debt		1,560,310			1,320,341
TOTAL CAPITALIZATION	$	4,578,174		$	4,479,939
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light
Company are an integral part of these statements.

51

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
												Accumulated
			Common Stock						Other			Other
	Comprehensive		Number			Par			Paid-In			Comprehensive			Retained
	Income		of Shares			Value			Capital			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2005				15,371,270			153,713			3,013,912			(55,534	)		31,463
Net income	$	182,927														182,927
Net unrealized gain on derivative instruments,
net of $113,000 of income taxes		163											163
Minimum liability for unfunded retirement
benefits, net of $36,838,000 of income taxes		53,341											53,341
Comprehensive income	$	236,431
Cash dividends on preferred stock																(500	)
Cash dividends on common stock																(158,000	)
Purchase accounting fair value adjustment										(10,722	)
Balance, December 31, 2005				15,371,270			153,713			3,003,190			(2,030	)		55,890
Net income	$	190,607														190,607
Net unrealized gain on derivative instruments,
net of $101,000 of income taxes		147											147
Comprehensive income	$	190,754
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $42,233,000 of income tax benefits (Note 4)													(42,371	)
Repurchase of common stock				(361,935	)		(3,620	)		(73,381	)
Preferred stock redemption premium																(663	)
Restricted stock units										101
Stock based compensation										48
Cash dividends on preferred stock																(354	)
Cash dividends on common stock																(100,000	)
Purchase accounting fair value adjustment										(21,679	)
Balance, December 31, 2006				15,009,335		$	150,093		$	2,908,279		$	(44,254	)	$	145,480
Net income	$	186,108														186,108
Net unrealized gain on derivative instruments,
net of $11,000 of income taxes		293											293
Pension and other postretirement benefits, net
of $23,644,000 of income taxes (Note 4)		24,080											24,080
Comprehensive income	$	210,481
Restricted stock units										198
Stock based compensation										3
Consolidated tax benefit allocation										4,637
Repurchase of common stock				(587,698	)		(5,877	)		(119,123	)
Cash dividends on common stock																(94,000	)
Purchase accounting fair value adjustment										(138,053	)
Balance, December 31, 2007				14,421,637		$	144,216		$	2,655,941		$	(19,881	)	$	237,588
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are
an integral part of these statements.

52

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2007			2006			2005
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	186,108		$	190,607		$	182,927
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		85,459			83,172			80,013
Amortization of regulatory assets		388,581			274,704			292,668
Deferral of new regulatory assets		-			-			(28,862	)
Deferred purchased power and other costs		(203,157	)		(281,498	)		(257,418	)
Deferred income taxes and investment tax credits, net		(30,791	)		43,896			36,125
Accrued compensation and retirement benefits		(23,441	)		(12,670	)		(10,431	)
Cash collateral from (returned to) suppliers		(31,938	)		(109,108	)		134,563
Pension trust contributions		(17,800	)		-			(79,120	)
Accrued liability from arbitration decision		-			-			16,141
Decrease (increase) in operating assets-
Receivables		(73,259	)		1,103			28,108
Materials and supplies		(364	)		61			331
Prepaid taxes		12,321			5,385			15,514
Other current assets		2,096			(2,134	)		(1,090	)
Increase (decrease) in operating liabilities-
Accounts payable		(39,396	)		53,330			42,118
Accrued taxes		11,658			(52,905	)		34,448
Accrued interest		(5,140	)		(5,458	)		1,717
Other		5,369			1,272			18,970
Net cash provided from operating activities		266,306			189,757			506,722
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		543,198			382,400			-
Short-term borrowings, net		-			5,194			-
Redemptions and Repayments-
Long-term debt		(325,337	)		(207,231	)		(72,536	)
Short-term borrowings, net		(56,159	)		-			(67,187	)
Common stock		(125,000	)		(77,000	)		-
Preferred stock		-			(13,312	)		-
Dividend Payments-
Common stock		(94,000	)		(100,000	)		(158,000	)
Preferred stock		-			(354	)		(500	)
Net cash used for financing activities		(57,298	)		(10,303	)		(298,223	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(199,856	)		(160,264	)		(209,118	)
Loan repayments from (loans to) associated companies, net		6,029			(6,037	)		2,017
Sales of investment securities held in trusts		195,973			216,521			164,506
Purchases of investment securities held in trusts		(212,263	)		(219,416	)		(167,401	)
Other		1,162			(10,319	)		1,437
Net cash used for investing activities		(208,955	)		(179,515	)		(208,559	)
Net increase (decrease) in cash and cash equivalents		53			(61	)		(60	)
Cash and cash equivalents at beginning of year		41			102			162
Cash and cash equivalents at end of year	$	94		$	41		$	102
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	102,492		$	80,101		$	78,750
Income taxes	$	156,073		$	134,279		$	12,385
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.

53

METROPOLITAN EDISON COMPANY

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

Results of Operations

In 2007, Met-Ed reported net income of $95 million compared to a net loss of $240 million in 2006, primarily due to a $355 million non-cash goodwill impairment charge in the fourth quarter of 2006 (see Note 2(E)). Excluding the impairment charge, earnings decreased by $20 million in 2007 primarily due to increased purchased power costs, amortization of regulatory assets, and other operating costs, partially offset by higher revenues.

Revenues

Revenues increased by $267 million, or 21.5%, in 2007 compared to 2006 primarily due to higher retail and wholesale generation sales, distribution throughput revenues, and PJM transmission revenues.

In 2007, retail generation revenues increased by $27 million primarily due to higher KWH sales to residential and commercial customers, partially offset by a slight decrease in KWH sales to industrial customers. The increase in retail generation revenues in the residential and commercial sectors primarily resulted from higher weather-related usage in 2007 as compared to 2006 (heating degree days increased by 14.9% and cooling degree days increased by 14.4%).

Changes in retail generation sales and revenues in 2007 compared to 2006 are summarized in the following tables:

	Increase
Retail Generation KWH Sales	(Decrease)
Residential		5.8	%
Commercial		4.6	%
Industrial		(0.1	)%
Net Increase in Retail Generation Sales		3.7	%

	Increase
Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	15
Commercial		12
Industrial		-
Increase in Retail Generation Revenues	$	27

Wholesale revenues increased by $155 million in 2007 compared to 2006 due to Met-Ed selling additional available power into the PJM market beginning in January 2007.

Revenues from distribution throughput increased by $74 million in 2007 compared to 2006. The increase was due to higher KWH deliveries, reflecting the effect of the weather discussed above, and an increase in composite unit prices resulting from the January 2007 PPUC authorization to increase transmission rates, partially offset by a decrease in distribution rates.

Changes in distribution KWH deliveries and revenues in 2007 compared to 2006 are summarized in the following tables:

	Increase
Distribution KWH Deliveries	(Decrease)
Residential		5.8	%
Commercial		4.6	%
Industrial		(0.4	)%
Increase in Distribution Deliveries		3.6	%

54

	Increase (Decrease)
Distribution Throughput Revenues	Transmission Rider Revenues		Distribution Revenues			Total
	(In millions)
Residential	$	56	$	(4	)	$	52
Commercial		43		(36	)		7
Industrial		33		(18	)		15
Increase (Decrease) in Distribution         Throughput Revenues	$	132	$	(58	)	$	74

PJM transmission revenues increased by $14 million in 2007 as a result of higher transmission volumes and additional PJM auction revenue rights, compared to the prior year. Met-Ed defers the difference between revenue from its transmission rider and total transmission costs incurred, resulting in no material effect to current period earnings.

Operating Expenses

Total expenses decreased by $76 million in 2007 compared to 2006. The following table presents changes from the prior year by expense category:

Expenses Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	150
Other operating costs		115
Provision for Depreciation		1
Amortization of regulatory assets		8
Deferral of new regulatory assets		2
Goodwill Impairment		(355	)
General taxes		3
Net decrease in expenses	$	(76	)

Purchased power costs increased in 2007 by $150 million due to higher volumes purchased to source higher retail and wholesale generation sales, combined with higher composite unit costs. Other operating costs increased in 2007 primarily due to higher congestion costs and other transmission expenses associated with increased transmission volumes ($101 million) and increased expenses related to Met-Eds customer assistance programs ($4 million). Other operating costs were also impacted by increased labor and contractor service expenses, which were partially due to ice storms that hit Met-Eds region and caused widespread damage to its electrical system in the fourth quarter of 2007 ($7 million).

Amortization of regulatory assets increased in 2007 primarily due to the recovery (through Met-Eds transmission rider discussed above) of certain transmission costs deferred in 2006 and the amortization of the Saxton nuclear research facilitys decommissioning costs as authorized by the PPUC in January 2007. The deferral of new regulatory assets decreased in 2007 primarily due to lower PJM transmission deferrals, partially offset by the deferral of previously expensed Saxton decommissioning costs of $15 million (see Note 9).

The goodwill impairment in 2006 was the result of an interim review of Met-Eds goodwill associated with the January 11, 2007 PPUC order regarding Met-Eds comprehensive rate filing, which allowed for a rate increase that was substantially less than what Met-Ed requested (see Note 2(E)).

In 2007, general taxes increased primarily due to higher gross receipts taxes, partially offset by lower capital stock taxes.

Sale of Investment

On October 1, 2007, Met-Ed sold 100% of its interest in York Haven Power Company for $5 million. The sale was subject to regulatory accounting and did not have a material impact on Met-Eds earnings.

Other Expense

Total other expense increased by $17 million in 2007 primarily due to a $6 million increase in interest on debt to associated companies, reflecting an increase in money pool borrowings, a $5 million decrease in interest earned on Met-Eds stranded regulatory assets (reflecting a lower regulatory asset base) and a $5 million loss on the sale of York Haven Power Company. The loss was recorded as an adjustment to regulatory assets and resulted in no material impact on Met-Eds earnings (see discussion above).

55

Market Risk Information

Met-Ed uses various market risk sensitive instruments, including derivative contracts, to manage the risk of price and interest rate fluctuations. FirstEnergys Risk Policy Committee, comprised of members of senior management, provides general oversight to risk management activities.

Commodity Price Risk

Met-Ed is exposed to market risk primarily due to fluctuations in electricity, energy transmission and natural gas prices. To manage the volatility relating to these exposures, Met-Ed uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts, and swaps. The derivatives are used principally for hedging purposes. All derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of Met-Eds derivative hedging contracts, however, qualify for the normal purchase and normal sale exception under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during 2007 is summarized in the following table:

Increase (Decrease) in the Fair Value of Derivative Contracts	Non-Hedge			Hedge		Total
	(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Outstanding net assets as of January 1, 2007	$	23		$	-	$	23
Additions/Changes in value of existing contracts		1			-		1
Settled contracts		(6	)		-		(6	)
Net Assets - Derivatives Contracts as of December 31, 2007(1)	$	18		$	-	$	18
Impact of Changes in Commodity Derivative Contracts(2)
Income Statement Effects (Pre-Tax)	$	-		$	-	$	-
Balance Sheet Effects:
Regulatory Liability (net)	$	5		$	-	$	5

(1) Includes $18 million from an embedded option that is offset by a regulatory liability, with no impact to earnings.

(2) Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

Derivatives are included on the Consolidated Balance Sheet as of December 31, 2007 as follows:

	Non-Hedge		Hedge		Total
	(In millions)
Non-Current-
Other Deferred Charges	$	18	$	-	$	18
Other noncurrent liabilities		-		-		-
Net assets	$	18	$	-	$	18

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of December 31, 2007 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2008		2009		2010		2011		2012		Thereafter		Total
	(In millions)
Broker quote sheets	$	10	$	4	$	4	$	-	$	-	$	-	$	18
Total(1)	$	10	$	4	$	4	$	-	$	-	$	-	$	18

(1) Includes $18 million from an embedded option that is offset by a regulatory liability, with no impact to earnings.

56

Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on Met-Eds consolidated financial position or cash flows as of December 31, 2007. Based on derivative contracts held as of December 31, 2007, an adverse 10% change in commodity prices would not have a material effect on Met-Eds net income for the next 12 months.

Interest Rate Risk

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

Comparison of Carrying Value to Fair Value
								There-						Fair
Year of Maturity	2008	2009	2010			2011	2012	after			Total			Value
(Dollars in millions)
Assets
Investments Other Than Cash and Cash Equivalents-
Fixed Income								$	115		$	115		$	115
Average interest rate									4.8	%		4.8	%
Liabilities
Long-term Debt:
Fixed rate			$	100				$	414		$	514		$	506
Average interest rate				4.5	%				4.9	%		4.8	%
Variable rate								$	28		$	28		$	28
Average interest rate									4.5	%		4.5	%
Short-term Borrowings	$ 285										$	285		$	285
Average interest rate	5.2%											5.2	%

Equity Price Risk

Included in Met-Eds nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $172 million as of December 31, 2007. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $17 million reduction in fair value as of December 31, 2007 (see Note 5).

Legal Proceedings

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

New Accounting Standards and Interpretations

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

57

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of Metropolitan Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Companys 2007 consolidated financial statements.

FirstEnergy Corp.s internal auditors, who are responsible to the Audit Committee of FirstEnergys Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.

FirstEnergys Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committees findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Companys independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management's programs to monitor compliance with the Companys policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 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 the Companys internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Companys internal control over financial reporting was effective as of December 31, 2007.

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.

58

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Metropolitan Edison Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder's equity and cash flows present fairly, in all material respects, the financial position of Metropolitan Edison Company and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in the notes to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007 (Note 8), defined benefit pension and other postretirement plans as of December 31, 2006 (Note 4) and conditional asset retirement obligations as of December 31, 2005 (Note 2(G) and Note 11).

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

59

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2007			2006			2005
	(In thousands)
REVENUES:
Electric sales	$	1,437,498		$	1,175,655		$	1,113,228
Gross receipts tax collections		73,012			67,403			63,190
Total revenues		1,510,510			1,243,058			1,176,418
EXPENSES:
Purchased power (Note 3)		784,489			634,433			620,764
Other operating costs (Note 3)		419,512			304,243			251,442
Provision for depreciation		42,798			41,715			42,684
Amortization of regulatory assets		123,410			115,672			112,117
Deferral of new regulatory assets		(124,821	)		(126,571	)		-
Goodwill impairment (Note 2(E))		-			355,100			-
General taxes		80,135			77,411			73,989
Total expenses		1,325,523			1,402,003			1,100,996
OPERATING INCOME (LOSS)		184,987			(158,945	)		75,422
OTHER INCOME (EXPENSE):
Interest income		28,953			34,402			36,500
Miscellaneous income (expense)		(339	)		8,042			8,366
Interest expense (Note 3)		(51,022	)		(47,385	)		(44,655	)
Capitalized interest		1,154			1,017			370
Total other income (expense)		(21,254	)		(3,924	)		581
INCOME (LOSS) BEFORE INCOME TAXES		163,733			(162,869	)		76,003
INCOME TAXES		68,270			77,326			30,084
INCOME (LOSS) BEFORE CUMULATIVE EFFECT
OF A CHANGE IN ACCOUNTING PRINCIPLE		95,463			(240,195	)		45,919
Cumulative effect of a change in accounting principle (net of income tax
benefit of $220,000) (Note 2(G))		-			-			(310	)
NET INCOME (LOSS)	$	95,463		$	(240,195	)	$	45,609
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an
integral part of these statements.

60

METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2007		2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	135	$	130
Receivables-
Customers (less accumulated provisions of $4,327,000 and $4,153,000,
respectively, for uncollectible accounts)		142,872		127,084
Associated companies		27,693		3,604
Other		18,909		8,107
Notes receivable from associated companies		12,574		31,109
Prepaid taxes		14,615		13,533
Other		1,348		1,424
		218,146		184,991
UTILITY PLANT:
In service		1,972,388		1,920,563
Less - Accumulated provision for depreciation		751,795		739,719
		1,220,593		1,180,844
Construction work in progress		30,594		18,466
		1,251,187		1,199,310
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		286,831		269,777
Other		1,360		1,362
		288,191		271,139
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		424,313		496,129
Regulatory assets		494,947		409,095
Pension assets		51,427		7,261
Other		36,411		46,354
		1,007,098		958,839
	$	2,764,622	$	2,614,279
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	-	$	50,000
Short-term borrowings-
Associated companies		185,327		141,501
Other		100,000		-
Accounts payable-
Associated companies		29,855		100,232
Other		66,694		59,077
Accrued taxes		16,020		11,300
Accrued interest		6,778		7,496
Other		27,393		22,825
		432,067		392,431
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		1,048,632		1,014,939
Long-term debt and other long-term obligations		542,130		542,009
		1,590,762		1,556,948
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		438,890		387,456
Accumulated deferred investment tax credits		8,390		9,244
Nuclear fuel disposal costs		43,462		41,459
Asset retirement obligations		160,726		151,107
Retirement benefits		8,681		19,599
Other		81,644		56,035
		741,793		664,900
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	2,764,622	$	2,614,279
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of
these balance sheets.

61

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2007			2006
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, 900,000 shares authorized,
859,500 shares outstanding	$	1,203,186		$	1,276,075
Accumulated other comprehensive loss (Note 2(F))		(15,397	)		(26,516	)
Retained earnings (Accumulated deficit) (Note 10(A))		(139,157	)		(234,620	)
Total		1,048,632			1,014,939
LONG-TERM DEBT (Note 10(C)):
First mortgage bonds-
5.950% due 2027		13,690			13,690
Total		13,690			13,690
Unsecured notes-
5.930% due 2007		-			50,000
4.450% due 2010		100,000			100,000
4.950% due 2013		150,000			150,000
4.875% due 2014		250,000			250,000
*   4.500% due 2021		28,500			28,500
Total		528,500			578,500
Net unamortized discount on debt		(60	)		(181	)
Long-term debt due within one year		-			(50,000	)
Total long-term debt		542,130			542,009
TOTAL CAPITALIZATION	$	1,590,762		$	1,556,948
* Denotes variable rate issue with applicable year-end interest rate shown.
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company
are an integral part of these statements.

62

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
									Accumulated			Retained
				Common Stock					Other			Earnings
	Comprehensive			Number		Carrying			Comprehensive			(Accumulated
	Income (Loss)			of Shares		Value			Income (Loss)			Deficit)
	(Dollars in thousands)
Balance, January 1, 2005					859,500	$	1,289,943		$	(43,490	)	$	38,966
Net income	$	45,609											45,609
Net unrealized gain on investments,
net of $27,000 of income taxes		39								39
Net unrealized gain on derivative instruments,
net of $140,000 of income taxes		196								196
Minimum liability for unfunded retirement benefits,
net of $29,564,000 of income taxes		41,686								41,686
Comprehensive income	$	87,530
Restricted stock units							28
Cash dividends on common stock													(54,000	)
Purchase accounting fair value adjustment							(2,878	)
Balance, December 31, 2005					859,500		1,287,093			(1,569	)		30,575
Net loss	$	(240,195	)										(240,195	)
Net unrealized gain on derivative instruments,
net of $139,000 of income taxes		196								196
Comprehensive loss	$	(239,999	)
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $26,715,000 of income tax benefits (Note 4)										(25,143	)
Restricted stock units							50
Stock based compensation							38
Cash dividends on common stock													(25,000	)
Purchase accounting fair value adjustment							(11,106	)
Balance, December 31, 2006					859,500		1,276,075			(26,516	)		(234,620	)
Net Income	$	95,463											95,463
Net unrealized gain on derivative instruments		335								335
Pension and other postretirement benefits, net
of $11,666,000 of income taxes (Note 4)		10,784								10,784
Comprehensive income	$	106,582
Restricted stock units							104
Stock based compensation							7
Consolidated tax benefit allocation							1,237
Purchase accounting fair value adjustment							(74,237	)
Balance, December 31, 2007					859,500	$	1,203,186		$	(15,397	)	$	(139,157	)
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these statements.

63

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,		2007			2006			2005
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	95,463		$	(240,195	)	$	45,609
Adjustments to reconcile net income (loss) to net cash from operating activities-
Provision for depreciation			42,798			41,715			42,684
Amortization of regulatory assets			123,410			115,672			112,117
Deferred costs recoverable as regulatory assets			(70,778	)		(82,674	)		(67,763	)
Deferral of new regulatory assets			(124,821	)		(126,571	)		-
Deferred income taxes and investment tax credits, net			35,502			50,278			(2,157	)
Accrued compensation and retirement benefits			(18,852	)		(6,876	)		(5,378	)
Goodwill impairment			-			355,100			-
Loss on sale of investment			5,432			-			-
Cash collateral from (to) suppliers			1,600			(1,580	)		-
Cumulative effect of a change in accounting principle			-			-			310
Pension trust contributions			(11,012	)		-			(35,789	)
Decrease (increase) in operating assets-
Receivables			(38,220	)		37,107			77,981
Prepayments and other current assets			(926	)		(4,385	)		3,145
Increase (decrease) in operating liabilities-
Accounts payable			(62,760	)		94,582			(50,249	)
Accrued taxes			10,128			(5,647	)		5,954
Accrued interest			(718	)		(1,804	)		(2,180	)
Other			12,870			(2,633	)		893
Net cash provided from (used for) operating activities			(884	)		222,089			125,177
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt			-			-			28,500
Short-term borrowings, net			143,791			1,253			60,150
Redemptions and Repayments-
Long-term debt			(50,000	)		(100,000	)		(66,330	)
Dividend Payments-
Common stock			-			(25,000	)		(54,000	)
Net cash provided from (used for) financing activities			93,791			(123,747	)		(31,680	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(103,711	)		(84,817	)		(85,627	)
Proceeds from sale of investment			4,953			-			-
Sales of investment securities held in trusts			184,619			176,460			166,711
Purchases of investment securities held in trusts			(196,140	)		(185,943	)		(176,194	)
Loan repayments from (loans to) associated companies, net			18,535			(3,242	)		1,355
Other			(1,158	)		(790	)		258
Net cash used for investing activities			(92,902	)		(98,332	)		(93,497	)
Net change in cash and cash equivalents			5			10			-
Cash and cash equivalents at beginning of year			130			120			120
Cash and cash equivalents at end of year		$	135		$	130		$	120
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)		$	44,501		$	44,597		$	43,266
Income taxes (refund)		$	30,741		$	42,173		$	(11,961	)
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an
integral part of these statements.

64

PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

Results of Operations

Net income increased to $93 million in 2007, compared to $84 million in 2006. The increase in net income was primarily due to higher revenues, partially offset by increased purchased power costs and other operating costs and a decrease in the deferral of new regulatory assets.

Revenues

Revenues increased by $254 million, or 22.1%, in 2007 as compared to 2006 primarily due to higher retail and wholesale generation revenues, distribution throughput revenues and PJM transmission revenues.

In 2007, retail generation revenues increased $19 million primarily due to higher KWH sales to all customer classes. The increase in retail generation revenues in the residential and commercial sectors resulted primarily from higher weather-related usage in 2007 (heating degree days increased 9.1% and cooling degree days increased 21.9%) as compared to 2006.

Increases in retail generation sales and revenues in 2007 compared to 2006 are summarized in the following tables:

Retail Generation KWH Sales	Increase
Residential		2.7	%
Commercial		3.6	%
Industrial		0.2	%
Increase in Retail Generation Sales		2.2	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	7
Commercial		10
Industrial		2
Increase in Retail Generation Revenues	$	19

Wholesale revenues increased $173 million in 2007, compared to 2006 due to Penelec selling additional available power into the PJM market beginning in January 2007.

Revenues from distribution throughput increased $50 million in 2007 due to higher KWH deliveries reflecting the effect of the weather discussed above and an increase in composite unit prices resulting from a January 2007 PPUC authorization to increase transmission rates, partially offset by a decrease in distribution rates.

Changes in distribution KWH deliveries and revenues in 2007 compared to 2006 are summarized in the following tables:

	Increase
Distribution KWH Deliveries	(Decrease)
Residential		2.6	%
Commercial		3.6	%
Industrial		(1.5	)%
Net Increase in Distribution Deliveries		1.6	%

65

	Increase (Decrease)
Distribution Throughput Revenues	Transmission Rider Revenues		Distribution Revenues			Total
	(In millions)
Residential	$	21	$	29		$	50
Commercial		21		(25	)		(4	)
Industrial		14		(10	)		4
Increase (Decrease) in Distribution         Throughput Revenues	$	56	$	(6	)	$	50

PJM transmission revenues increased by $12 million in 2007 compared to 2006 due to higher transmission volumes and additional PJM auction revenue rights in 2007. Penelec defers the difference between revenue from its transmission rider and total transmission costs incurred, resulting in no material effect to current period earnings.

Operating Expenses

During 2007, total expenses increased by $225 million, as compared with 2006. The following table presents changes from the prior year by expense category:

Expenses - Changes	Increase
	(In millions)
Purchased power costs	$	164
Other operating costs		31
Provision for depreciation		2
Amortization of regulatory assets		3
Deferral of new regulatory assets		22
General taxes		3
Increase in Expenses	$	225

Purchased power costs increased by $164 million, or 26.2% in 2007, compared to 2006 primarily due to higher KWH purchases to source increased retail and wholesale generation sales, combined with higher composite unit costs. Other operating costs increased by $31 million in 2007 principally due to higher congestion costs and other transmission expenses associated with increased transmission volumes.

Amortization of regulatory assets increased in 2007 primarily due to the recovery (through Penelecs transmission rider discussed above) of certain transmission costs deferred in 2006 and the amortization of TMI-2 and Saxton nuclear research facilitys decommissioning costs as authorized by the PPUC in January 2007. The deferral for new regulatory assets decreased primarily due to lower transmission cost deferrals in 2007, partially offset by the deferral of previously expensed decommissioning costs ($12 million) associated with the Saxton nuclear research facility (see Note 9).

In 2007, general taxes increased $3 million as compared to 2006, primarily due to higher gross receipts taxes.

Other Expense

In 2007, other expense increased primarily due to higher interest expense associated with: Penelecs $300 million senior note issuance in August 2007, increased debt to associated companies, primarily due to increased money pool borrowings, and increased borrowings under Penelecs revolving credit facility.

Market Risk Information

Penelec uses various market risk sensitive instruments, including derivative contracts, to manage the risk of price and interest rate fluctuations. FirstEnergys Risk Policy Committee, comprised of members of senior management, provides general oversight to risk management activities.

66

Commodity Price Risk

Penelec is exposed to market risk primarily due to fluctuations in electricity, energy transmission and natural gas prices. To manage the volatility relating to these exposures, Penelec uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts, and swaps. The derivatives are used principally for hedging purposes. All derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of Penelecs derivative hedging contracts, however, qualify for the normal purchase and normal sale exception under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during 2007 is summarized in the following table:

Increase (Decrease) in the Fair Value of Derivative Contracts	Non-Hedge			Hedge		Total
	(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Outstanding net assets as of January 1, 2007	$	11		$	-	$	11
Additions/Changes in value of existing contracts		1			-		1
Settled contracts		(3	)		-		(3	)
Net Assets - Derivatives Contracts as of December 31, 2007(1)	$	9		$	-	$	9
Impact of Changes in Commodity Derivative Contracts(2)
Income Statement Effects (Pre-Tax)	$	-		$	-	$	-
Balance Sheet Effects:
Regulatory Liability (net)	$	2		$	-	$	2

(1) Includes $9 million from an embedded option that is offset by a regulatory liability, with no impact to earnings.

(2) Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

Derivatives are included on the Consolidated Balance Sheet as of December 31, 2007 as follows:

	Non-Hedge		Hedge		Total
	(In millions)
Non-Current-
Other Deferred Charges	$	9	$	-	$	9
Other noncurrent liabilities		-		-		-
Net assets	$	9	$	-	$	9

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of December 31, 2007 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2008		2009		2010		2011		2011		Thereafter		Total
	(In millions)
Broker quote sheets	$	5	$	2	$	2	$	-	$	-	$	-	$	9
Total(1)	$	5	$	2	$	2	$	-	$	-	$	-	$	9

(1) Includes $9 million from an embedded option that is offset by a regulatory liability, with no impact to earnings.

Penelec performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on Penelecs consolidated financial position or cash flows as of December 31, 2007. Based on derivative contracts held as of December 31, 2007, an adverse 10% change in commodity prices would not have a material effect on Penelecs net income for the next 12 months.

Interest Rate Risk

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

67

Comparison of Carrying Value to Fair Value
										There-						Fair
Year of Maturity	2008	2009			2010			2011	2012	after			Total			Value
(Dollars in millions)
Assets
Investments Other Than Cash and Cash Equivalents-
Fixed Income										$	167		$	167		$	167
Average interest rate											4.7	%		4.7	%
Liabilities
Long-term Debt:
Fixed rate		$	100		$	59				$	575		$	734		$	734
Average interest rate			6.1	%		6.8	%				5.9	%		6.0	%
Variable rate										$	45		$	45		$	45
Average interest rate											4.3	%		4.3	%
Short-term Borrowings	$ 215												$	215		$	215
Average interest rate	5.0%													5.0	%

Equity Price Risk

Included in Penelecs nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $83 million as of December 31, 2007. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $8 million reduction in fair value as of December 31, 2007 (see Note 5).

Legal Proceedings

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

New Accounting Standards and Interpretations

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

68

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of Pennsylvania Electric Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Companys 2007 consolidated financial statements.

FirstEnergy Corp.s internal auditors, who are responsible to the Audit Committee of FirstEnergys Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.

FirstEnergys Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committees findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Companys independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management's programs to monitor compliance with the Companys policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 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 the Companys internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Companys internal control over financial reporting was effective as of December 31, 2007.

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.

69

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Pennsylvania Electric Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder's equity and cash flows present fairly, in all material respects, the financial position of Pennsylvania Electric Company and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in the notes to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007 (Note 8), defined benefit pension and other postretirement plans as of December 31, 2006 (Note 4) and conditional asset retirement obligations as of December 31, 2005 (Note 2(G) and Note 11).

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

70

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2007			2006			2005
	(In thousands)
REVENUES:
Electric sales	$	1,336,517		$	1,086,781		$	1,063,841
Gross receipts tax collections		65,508			61,679			58,184
Total revenues		1,402,025			1,148,460			1,122,025
EXPENSES:
Purchased power (Note 3)		790,354			626,367			620,509
Other operating costs (Note 3)		234,949			203,868			257,869
Provision for depreciation		49,558			48,003			49,410
Amortization of regulatory assets		55,863			52,477			50,348
Deferral of new regulatory assets		(9,102	)		(30,590	)		(3,239	)
General taxes		76,050			72,612			68,984
Total expenses		1,197,672			972,737			1,043,881
OPERATING INCOME		204,353			175,723			78,144
OTHER INCOME (EXPENSE):
Miscellaneous income		6,501			8,986			5,013
Interest expense (Note 3)		(54,840	)		(45,278	)		(39,900	)
Capitalized interest		939			1,290			908
Total other expense		(47,400	)		(35,002	)		(33,979	)
INCOME BEFORE INCOME TAXES		156,953			140,721			44,165
INCOME TAX EXPENSE		64,015			56,539			16,612
INCOME BEFORE CUMULATIVE EFFECT
OF A CHANGE IN ACCOUNTING PRINCIPLE		92,938			84,182			27,553
Cumulative effect of a change in accounting principle
(net of income tax benefit of $566,000) (Note 2(G))		-			-			(798	)
NET INCOME	$	92,938		$	84,182		$	26,755
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.

71

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2007		2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	46	$	44
Receivables-
Customers (less accumulated provisions of $3,905,000 and $3,814,000,
respectively, for uncollectible accounts)		137,455		126,639
Associated companies		22,014		49,728
Other		19,529		16,367
Notes receivable from associated companies		16,313		19,548
Prepayments and other		3,077		4,236
		198,434		216,562
UTILITY PLANT:
In service		2,219,002		2,141,324
Less - Accumulated provision for depreciation		838,621		809,028
		1,380,381		1,332,296
Construction work in progress		24,251		22,124
		1,404,632		1,354,420
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		137,859		125,216
Non-utility generation trusts		112,670		99,814
Other		531		531
		251,060		225,561
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		777,904		860,716
Pension assets		66,111		11,474
Other		33,893		36,059
		877,908		908,249
	$	2,732,034	$	2,704,792
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Short-term borrowings-
Associated companies	$	214,893	$	199,231
Accounts payable-
Associated companies		83,359		92,020
Other		51,777		47,629
Accrued taxes		15,111		11,670
Accrued interest		13,167		7,224
Other		25,311		21,178
		403,618		378,952
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		1,072,057		1,378,058
Long-term debt and other long-term obligations		777,243		477,304
		1,849,300		1,855,362
NONCURRENT LIABILITIES:
Regulatory liabilities		73,559		96,151
Accumulated deferred income taxes		210,776		193,662
Retirement benefits		41,298		50,394
Asset retirement obligations		81,849		76,924
Other		71,634		53,347
		479,116		470,478
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	2,732,034	$	2,704,792
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.

72

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2007			2006
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, $20 par value, 5,400,000 shares authorized,
4,427,577 and 5,290,596 shares outstanding, respectively	$	88,552		$	105,812
Other paid-in capital		920,616			1,189,434
Accumulated other comprehensive income (loss) (Note 2(F))		4,946			(7,193	)
Retained earnings (Note 10(A))		57,943			90,005
Total		1,072,057			1,378,058
LONG-TERM DEBT (Note 10(C)):
First mortgage bonds-
5.350% due 2010		12,310			12,310
5.350% due 2010		12,000			12,000
Total		24,310			24,310
Unsecured notes-
6.125% due 2009		100,000			100,000
7.770% due 2010		35,000			35,000
5.125% due 2014		150,000			150,000
6.050% due 2017		300,000			-
6.625% due 2019		125,000			125,000
*   4.250% due 2020		20,000			20,000
*   4.350% due 2025		25,000			25,000
Total		755,000			455,000
Net unamortized discount on debt		(2,067	)		(2,006	)
Total long-term debt		777,243			477,304
TOTAL CAPITALIZATION	$	1,849,300		$	1,855,362
* Denotes variable rate issue with applicable year-end interest rate shown.
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company
are an integral part of these statements.

73

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
												Accumulated
			Common Stock						Other			Other
	Comprehensive		Number			Par			Paid-In			Comprehensive			Retained
	Income (Loss)		of Shares			Value			Capital			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2005				5,290,596		$	105,812		$	1,205,948		$	(52,813	)	$	46,068
Net income	$	26,755														26,755
Net unrealized gain on investments, net
of $4,000 of income taxes		3											3
Net unrealized gain on derivative instruments, net
of $24,000 of income taxes		40											40
Minimum liability for unfunded retirement benefits,
net of $37,206,000 of income taxes		52,461											52,461
Comprehensive income	$	79,259
Restricted stock units										20
Cash dividends on common stock																(47,000	)
Purchase accounting fair value adjustment										(3,417	)
Balance, December 31, 2005				5,290,596			105,812			1,202,551			(309	)		25,823
Net income	$	84,182														84,182
Net unrealized gain on investments, net
of $4,000 of income taxes		2											2
Net unrealized gain on derivative instruments, net
of $27,000 of income taxes		38											38
Comprehensive income	$	84,222
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $17,340,000 of income tax benefits (Note 4)													(6,924	)
Restricted stock units										46
Stock based compensation										21
Cash dividends on common stock																(20,000	)
Purchase accounting fair value adjustment										(13,184	)
Balance, December 31, 2006				5,290,596			105,812			1,189,434			(7,193	)		90,005
Net income	$	92,938														92,938
Net unrealized gain on investments net of
of $12,000 of income tax benefits		21											21
Net unrealized gain on derivative instruments, net
of $16,000 of income taxes		49											49
Pension and other postretirement benefits, net
of $15,413,000 of income taxes (Note 4)		12,069											12,069
Comprehensive income	$	105,077
Restricted stock units										107
Stock based compensation										7
Consolidated tax benefit allocation										1,261
Repurchase of common stock				(863,019	)		(17,260	)		(182,740	)
Cash dividends on common stock																(125,000	)
Purchase accounting fair value adjustment										(87,453	)
Balance, December 31, 2007				4,427,577		$	88,552		$	920,616		$	4,946		$	57,943
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.

74

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,		2007			2006			2005
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	92,938		$	84,182		$	26,755
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation			49,558			48,003			49,410
Amortization of regulatory assets			55,863			52,477			50,348
Deferral of new regulatory assets			(9,102	)		(30,590	)		(3,239	)
Deferred costs recoverable as regulatory assets			(71,939	)		(80,942	)		(59,224	)
Deferred income taxes and investment tax credits, net			10,713			28,568			8,823
Accrued compensation and retirement benefits			(20,830	)		5,125			3,596
Cumulative effect of a change in accounting principle			-			-			798
Pension trust contributions			(13,436	)		-			(20,000	)
Decrease (increase) in operating assets-
Receivables			18,771			14,299			70,330
Prepayments and other current assets			1,159			683			(737	)
Increase (decrease) in operating liabilities-
Accounts payable			(4,513	)		67,602			(10,067	)
Accrued taxes			4,743			(1,524	)		19,905
Accrued interest			5,943			(638	)		(790	)
Other			13,125			8,363			7,158
Net cash provided from operating activities			132,993			195,608			143,066
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt			296,899			-			45,000
Short-term borrowings, net			15,662			-			19,663
Redemptions and Repayments-
Common Stock			(200,000	)		-			-
Long-term debt			-			-			(56,538	)
Short-term borrowings, net			-			(61,928	)		-
Dividend Payments-
Common stock			(125,000	)		(20,000	)		(47,000	)
Net cash used for financing activities			(12,439	)		(81,928	)		(38,875	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(94,991	)		(106,980	)		(107,602	)
Loan repayments from (loans to) associated companies, net			3,235			(1,924	)		3,730
Sales of investment securities held in trusts			175,222			99,469			92,623
Purchases of investment securities held in trusts			(199,375	)		(99,469	)		(92,623	)
Other, net			(4,643	)		(4,767	)		(320	)
Net cash used for investing activities			(120,552	)		(113,671	)		(104,192	)
Net increase (decrease) in cash and cash equivalents			2			9			(1	)
Cash and cash equivalents at beginning of year			44			35			36
Cash and cash equivalents at end of year		$	46		$	44		$	35
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)		$	44,503		$	41,976		$	35,387
Income taxes (refund)		$	2,996		$	29,189		$	(42,324	)
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.

75

COMBINED MANAGEMENT'S DISCUSSION

AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain disclosures referenced in Management's Narrative Analysis of Results of Operations of FES and the Companies. This information should be read in conjunction with FES' and the Companies' respective Consolidated Financial Statements and Management's Narrative Analysis of Results of Operations and the Combined Notes to Consolidated Financial Statements.

Regulatory Matters(Applicable to each of the Companies)

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

▪ restructuring the electric generation business and allowing the Companies' customers to select a competitive electric generation supplier other than the Companies;

▪ establishing or defining the PLR obligations to customers in the Companies' service areas;

▪ providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

▪ itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges;

▪ continuing regulation of the Companies' transmission and distribution systems; and

▪ requiring corporate separation of regulated and unregulated business activities.

The Companies 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. As of December 31, 2007, regulatory assets that did not earn a current return totaled approximately $84 million for JCP&L, $54 million for Met-Ed and $2 million for Penelec. Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets by company:

	December 31,		December 31,		Increase
Regulatory Assets*	2007		2006		(Decrease)
	(In millions)
OE	$	737	$	741	$	(4	)
CEI		871		855		16
TE		204		248		(44	)
JCP&L		1,596		2,152		(556	)
Met-Ed		495		409		86

* Penelec had net regulatory liabilities of approximately $74 million and $96 million as of December 31, 2007 and December 31, 2006, respectively. These net regulatory liabilities are included in Non-current Liabilities-Other on the Consolidated Balance Sheets.

Ohio (Applicable to OE, CEI and TE)

The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP. On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies' RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2008 through 2010:

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Amortization							Total
Period	OE		CEI		TE		Ohio
	(In millions)
2008	$	207	$	126	$	113	$	446
2009		-		212		-		212
2010		-		273		-		273
Total Amortization	$	207	$	611	$	113	$	931

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.

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 (OE - $28 million, CEI - $22 million and TE - $14 million). 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 (OE - $156 million, CEI - $108 million and TE - $68 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 (OE - $57 million to $66 million, CEI - $54 million to $61 million and TE - $50 million to $53 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 (OE - $6 million, CEI - $5 million and TE - $2 million) of interest costs deferred through December 31, 2007. 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.

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On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing 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 utilitys total load notwithstanding the customers 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, the Ohio Companies cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on their operations.

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

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.

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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 their results of operations.

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.

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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 companys 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 Governors 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, the Pennsylvania Companies are unable to predict what impact, if any, such legislation may have on their operations.

New Jersey (Applicable to JCP&L)

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of December 31, 2007, the accumulated deferred cost balance totaled approximately $322 million.

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 Governors Office and the Governors 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 Jerseys electricity needs with renewable energy resources by that date;

▪ Reduce air pollution related to energy use;

▪ Encourage and maintain economic growth and development;

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▪ 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, JCP&L cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations.

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, JCP&L cannot predict the outcome of this process nor determine the impact, if any, such regulations may have on its operations.

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

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 ALJs decision and recommendations.  On April 19, 2007, the FERC issued an order rejecting the ALJs 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 PJMs 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.

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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.

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.

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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.

MISOs 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 FERCs 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 MISOs 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.

Duquesnes 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 PJMs forward capacity market.  FirstEnergy believes that Duquesnes filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesnes proposal. Consequently, on December 4, 2007 and January 3, 2008, FirstEnergy submitted responsive filings that, while conceding Duquesnes rights to exit PJM, contested various aspects of Duquesnes proposal.  FirstEnergy particularly focused on Duquesnes proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesnes 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 Duquesnes 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 Duquesnes plans.

On January 17, 2008, the FERC conditionally approved Duquesnes 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 Owners Agreement. The FERC likewise directed the MISO to submit a compliance filing in forty-five days (or by March 3, 2008) detailing the MISOs 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 Duquesnes 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.

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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.

Environmental Matters

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

Clean Air Act Compliance(Applicable to FES)

FES is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in 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. FES believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the Clean Air Act. FES has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided 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.

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

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act, alleging violations of air pollution laws at the 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.

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National Ambient Air Quality Standards(Applicable to FES)

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). FES' Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO2 and 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(Applicable to FES)

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, 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, FES only Pennsylvania coal-fired power plant, until 2015, if at all.

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

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.

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, FGCO, OE and Penn 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).

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.

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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 (Applicable to FES)

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

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

Clean Water Act (Applicable to FES)

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

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

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

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Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.  As of December 31, 2007, FES and the Companies 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. CEI, TE and JCP&L have recognized liabilities of $1.3 million, $2.5 million and $64.9 million, respectively, as of December 31, 2007.

Other Legal Proceedings

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

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

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages.  JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007.  Proceedings are continuing in the Superior Court. JCP&L is defending this class action but is unable to predict the outcome of this matter.  No liability has been accrued as of December 31, 2007.

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On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. Canada Power System Outage Task Forces final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy's Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energys Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 recommendations to prevent or minimize the scope of future blackouts. Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy's implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

On February 5, 2008, the PUCO entered an order dismissing four separate complaint cases before it relating to the August 14, 2003 power outages. The dismissal was filed by the complainants in accordance with a resolution reached between the FirstEnergy companies and the complainants in those four cases. Two of those cases which were originally filed in Ohio State courts involved individual complainants and were subsequently dismissed for lack of subject matter jurisdiction.  Further appeals were unsuccessful. The other two complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured, seeking reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and AEP, as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003.  (Also relating to the August 14, 2003 power outages, a fifth case, involving another insurance company was voluntarily dismissed by the claimant in April 2007; and a sixth case, involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed by the court.) The order dismissing the PUCO cases, noted above, concludes all pending litigation related to the August 14, 2003 outages and the resolution will not have a material adverse effect on the financial condition, results of operations or cash flows of either FirstEnergy or any of its subsidiaries.

Nuclear Plant Matters(Applicable to FES)

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 NRCs 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 NRCs Office of Enforcement after it completes the key commitments embodied in the NRCs order. FENOCs compliance with these commitments is subject to future NRC review.

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Other Legal Matters (Applicable to OE and JCP&L)

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

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. 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.

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

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

SFAS 157 - "Fair Value Measurements"

In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value, which focuses on an exit price rather than entry price; (2) the methods used to measure fair value, such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement and its related FSPs are effective for fiscal years beginning after November 15, 2007, and interim periods within those years. Under FSP FAS 157-2, FES and the Companies have elected to defer the election of SFAS 157 for financial assets and financial liabilities measured at fair value on a non-recurring basis for one year.  FES and the Companies have evaluated the impact of this Statement and its FSPs, FAS 157-2 and FSP FAS 157-1, which excludes SFAS 13, Accounting for Leases, and its related pronouncements from the scope of SFAS 157, and are not expecting there to be a material effect on their financial statements. The majority of the FES and the Companies fair value measurements will be disclosed as level 1 or level 2 in the fair value hierarchy.

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

In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and financial liabilities at fair value. This Statement attempts to provide additional information that will help investors and other users of financial statements to more easily understand the effect of a companys choice to use fair value on its earnings. The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157 and SFAS 107. This Statement is effective for fiscal years beginning after November 15, 2007, and interim periods within those years. FES and the Companies have analyzed their financial assets and financial liabilities within the scope of this Statement and no fair value elections were made as of January 1, 2008.

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SFAS 141(R) - "Business Combinations"

In December 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will impact business combinations entered into by FES and the Companies that close after January 1, 2009 and is not expected to have a material impact on FES and the Companies financial statements.

SFAS 160 - "Noncontrolling Interests in Consolidated Financial Statements an Amendment of ARB No. 51"

In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FES and the Companies' financial statements.

FSP FIN 39-1 - "Amendment of FASB Interpretation No. 39"

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

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

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

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.      ORGANIZATION AND BASIS OF PRESENTATION

FES and the Companies are wholly owned subsidiaries of FirstEnergy. FES consolidated financial statements include its wholly owned subsidiaries, FGCO and NGC. OEs consolidated financial statements include its wholly owned subsidiary, Penn. In the fourth quarter of 2005, the Ohio Companies and Penn completed the intra-system transfers of their non-nuclear and nuclear generation assets to FGCO and NGC, respectively (see Note 14).

FES' consolidated financial statements as of December 31, 2007 and 2006 and for the three years ended December 31, 2007 represent the financial position, results of operations and cash flows as if the intra-system generation asset transfers had occurred as of December 31, 2003. Certain financial results, net assets and net cash flows related to the ownership of the Ohio Companies and Penn of the transferred generation assets prior to the asset transfers are reflected in FES' consolidated financial statements.

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 a second tier subsidiary of FirstEnergy. FENOC continues to operate and maintain the nuclear generation assets. FES' consolidated financial statements assume that this corporate restructuring occurred as of December 31, 2003, with the FES' and NGC's financial position, results of operations and cash flows combined at the end of 2003 and associated company transactions and balances eliminated in consolidation.

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

FES and the Companies consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FES and the Companies consolidate a VIE (see Note 7) when they are determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FES and the Companies have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) are accounted for under the equity method. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity's earnings is reported in the Consolidated Statements of Income.

Certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications did not change previously reported earnings for 2006 and 2005. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

2.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(A)      ACCOUNTING FOR THE EFFECTS OF REGULATION

The Companies account for the effects of regulation through the application of SFAS 71 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:

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▪ 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.

Regulatory Assets

The Companies recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $140 million as of December 31, 2007 (JCP&L - $84 million, Met-Ed - $54 million and Penelec - $2 million). Regulatory assets not earning a current return will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec.

Regulatory assets on the Companies' Consolidated Balance Sheets are comprised of the following:

Regulatory Assets *	OE			CEI			TE			JCP&L			Met-Ed
December 31, 2007	(In millions)
Regulatory transition costs	$	197		$	227		$	71		$	1,630		$	237
Customer shopping incentives		91			393			32			-			-
Customer receivables (payables) for future income taxes		101			18			(1	)		51			126
Loss (Gain) on reacquired debt		23			2			(3	)		25			10
Employee postretirement benefit costs		-			8			4			17			10
Nuclear decommissioning, decontamination
and spent fuel disposal costs		-			-			-			-			(115	)
Asset removal costs		(6	)		(18	)		(11	)		(148	)		-
Property losses and unrecovered plant costs		-			-			-			9			-
MISO/PJM transmission costs		56			34			24			-			226
Fuel costs RCP		111			77			33			-			-
Distribution costs RCP		148			122			51			-			-
Other		16			8			4			12			1
Total	$	737		$	871		$	204		$	1,596		$	495
December 31, 2006
Regulatory transition costs	$	280		$	360		$	134		$	2,207		$	285
Customer shopping incentives		174			368			61			-			-
Customer receivables (payables) for future income taxes		81			3			(4	)		22			116
Societal benefits charge		-			-			-			11			-
Loss (Gain) on reacquired debt		24			-			(3	)		11			11
Employee postretirement benefit costs		-			10			5			20			12
Nuclear decommissioning, decontamination
and spent fuel disposal costs		-			-			-			(1	)		(144	)
Asset removal costs		(2	)		(12	)		(5	)		(148	)		-
Property losses and unrecovered plant costs		-			-			-			19			-
MISO/PJM transmission costs		44			26			16			-			127
Fuel costs RCP		57			39			17			-			-
Distribution costs RCP		74			57			24			-			-
Other		9			4			3			11			2
Total	$	741		$	855		$	248		$	2,152		$	409

* Penn had net regulatory liabilities of approximately $67 million and $68 million as of December 31, 2007 and 2006, respectively. Penelec had net regulatory liabilities of approximately $74 million and $96 million as of December 31, 2007 and 2006, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

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In accordance with the RCP, recovery of the aggregate of the regulatory transition costs and the Extended RTC (deferred customer shopping incentives and interest costs) amounts are expected to be complete for OE and TE by December 31, 2008. CEI's recovery of regulatory transition costs is projected to be complete by April 2009 at which time recovery of its Extended RTC will begin, with recovery estimated to be complete as of December 31, 2010. At the end of their respective recovery periods, any remaining unamortized regulatory transition costs and Extended RTC balances will be reduced by applying any remaining cost of removal regulatory liability balances -- any remaining regulatory transition costs and Extended RTC balances will be written off. The RCP allows the Ohio Companies to defer and capitalize certain distribution costs during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the years 2006, 2007 and 2008. These deferrals will be recovered in distribution rates effective on or after January 1, 2009. In addition, the Ohio Companies deferred certain fuel costs through December 31, 2007 that were incurred above the amount collected through a fuel recovery mechanism in accordance with the RCP (see Note 9(B)).

Transition Cost Amortization

The Ohio Companies amortize transition costs using the effective interest method. Extended RTC amortization is equal to the related revenue recovery that is recognized. The following table provides the estimated net amortization of regulatory transition costs and Extended RTC amounts (including associated carrying charges) under the RCP for the period 2008 through 2010:

Amortization
Period	OE		CEI		TE
	(In millions)
2008	$	207	$	126	$	113
2009		-		212		-
2010		-		273		-
Total Amortization	$	207	$	611	$	113

JCP&L's and Met-Eds regulatory transition costs include the deferral of above-market costs for power supplied from NUGs of $875 million for JCP&L (recovered through BGS and MTC revenues) and $185 million for Met-Ed (recovered through CTC revenues). The liability for JCP&L's projected above-market NUG costs and corresponding regulatory asset are adjusted to fair value at the end of each quarter. Recovery of the remaining regulatory transition costs is expected to continue pursuant to various regulatory proceedings in New Jersey and Pennsylvania (See Note 9).

        (B)      REVENUES AND RECEIVABLES

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

Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2007 with respect to any particular segment of customers. Billed and unbilled customer receivables for FES and the Companies as of December 31, 2007 and 2006 are shown below.

Customer Receivables	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
December 31, 2007	(In millions)
Billed	$	107	$	143	$	144	$	-	$	162	$	80	$	75
Unbilled		27		106		107		-		159		63		62
Total	$	134	$	249	$	251	$	-	$	321	$	143	$	137
December 31, 2006
Billed	$	104	$	127	$	137	$	1	$	128	$	70	$	69
Unbilled		26		108		108		-		126		57		58
Total	$	130	$	235	$	245	$	1	$	254	$	127	$	127

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        (C)      EMISSION ALLOWANCES

FES holds emission allowances for SO2 and NOX in order to comply with programs implemented by the EPA designed to regulate emissions of SO2 and NOX produced by power plants. Emission allowances are either granted by the EPA at zero cost or are purchased at fair value as needed to meet emission requirements.  Emission allowances are not purchased with the intent of resale. Emission allowances eligible to be used in the current year are recorded in materials and supplies inventory at the lesser of weighted average cost or market value. Emission allowances eligible for use in future years are recorded as other investments. FES recognizes emission allowance costs as fuel expense during the periods that emissions are produced by its generating facilities. Excess emission allowances that are not needed to meet emission requirements may be sold and are reported as a reduction to other operating expenses.

        (D)      PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment reflects original cost (except for nuclear generating assets which were adjusted to fair value in accordance with SFAS 144), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FES' accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.

FES and the Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite rates for FES and the Companies electric plant in 2007, 2006 and 2005 are shown in the following table:

	Annual Composite
	Depreciation Rate
	2007			2006			2005
OE		2.9	%		2.8	%		2.1	%
CEI		3.6			3.2			2.9
TE		3.9			3.8			3.1
Penn		2.3			2.6			2.4
JCP&L		2.1			2.1			2.2
Met-Ed		2.3			2.3			2.4
Penelec		2.3			2.3			2.6
FGCO		4.0			4.1			N/A
NGC		2.8			2.7			N/A

Jointly-Owned Generating Stations

JCP&L holds a 50% ownership interest in Yards Creek Pumped Storage Facility with a net book value of approximately $19.5 million as of December 31, 2007.

Asset Retirement Obligations

FES and the Companies recognize liabilities for retirement obligations associated with tangible assets in accordance with SFAS 143 and FIN 47. These standards require recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and depreciated over time, as described further in Note 11.

Nuclear Fuel

FES property, plant and equipment includes nuclear fuel recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. Nuclear fuel is amortized based on the units of production method.

(E)      ASSET IMPAIRMENTS

Long-Lived Assets

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

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Goodwill

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FES and the Companies evaluate their goodwill for impairment at least annually and make such evaluations more frequently if indicators of impairment arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment is indicated, a loss is recognized - calculated as the difference between the implied fair value of goodwill and the carrying value of goodwill. FES' and the Companies' 2007 annual review was completed in the third quarter of 2007 with no impairment indicated. In the third quarter of 2007, JCP&L, Met-Ed and Penelec adjusted goodwill due to the realization of tax benefits that had been reserved in purchase accounting.

FES' and the Companies' 2006 annual review was completed in the third quarter of 2006 with no impairment indicated. On January 11, 2007, the PPUC issued its order related to the comprehensive rate filing made by Met-Ed and Penelec on April 10, 2006 (see Note 9).  The rate increase granted was substantially lower than the amounts Met-Ed and Penelec had requested. Prior to issuing the order, the PPUC conducted an informal, nonbinding polling of Commissioners at its public meeting on December 21, 2006 that indicated the rate increase ultimately granted would be substantially below the amounts requested.  As a result of the polling, Met-Ed and Penelec determined that an interim review of goodwill would be required.  As a result, Met-Ed recognized an impairment charge of $355 million in the fourth quarter of 2006. No impairment was indicated for Penelec.

The forecasts used in the evaluations of goodwill reflect operations consistent with FES' and the Companies' general business assumptions. Unanticipated changes in those assumptions could have a significant effect on future evaluations of goodwill. The impairment analysis includes a significant source of cash representing the Companies' recovery of transition costs as described in Note 9. The Companies estimate that the completion of their transition cost recovery will not result in an impairment of goodwill.

A summary of the changes in FES' and the Companies' goodwill for the three years ended December 31, 2007 is shown below.

Goodwill	FES			CEI			TE			JCP&L			Met-Ed			Penelec
	(In millions)
Balance as of January 1, 2005	$	26		$	1,694		$	505		$	1,998		$	870		$	888
Non-core sset sales		(2	)		-			-			-			-			-
Adjustments related to GPU acquisition											(12	)		(6	)		(6	)
Adjustments related to Centerior acquisition					(5	)		(4	)
Balance as of December 31, 2005		24			1,689			501			1,986			864			882
Impairment charges														(355	)
Adjustments related to Centerior acquisition
Adjustments related to GPU acquisition											(24	)		(13	)		(21	)
Balance as of December 31, 2006		24			1,689			501			1,962			496			861
Adjustments related to GPU acquisition											(136	)		(72	)		(83	)
Balance as of December 31, 2007	$	24		$	1,689		$	501		$	1,826		$	424		$	778

Investments

At the end of each reporting period, FES and the Companies evaluate their investments for impairment. In accordance with SFAS 115 and FSP SFAS 115-1 and SFAS 124-1, investments classified as available-for-sale securities are evaluated to determine whether a decline in fair value below the cost basis is other-than-temporary. FES and the Companies first consider their intent and ability to hold the investment until recovery and then consider, among other factors, the duration and the extent to which the security's fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. If the decline in fair value is determined to be other-than-temporary, the cost basis of the investment is written down to fair value. Upon adoption of FSP SFAS 115-1 and SFAS 124-1, FES, OE and TE began recognizing in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of other-than-temporary impairment. The fair value and unrealized gains and losses of FES' and the Companies' investments are disclosed in Note 5.

        (F)       COMPREHENSIVE INCOME

Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with stockholders and from the adoption of SFAS 158.  Accumulated other comprehensive income (loss), net of tax, included on FES' and the Companies' Consolidated Balance Sheets as of December 31, 2007 and 2006 is comprised of the following components:

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Accumulated Other Comprehensive Income (Loss)	FES			OE			CEI			TE			JCP&L			Met-Ed			Penelec
	(In millions)
Net liability for unfunded retirement benefits     including the implementation of SFAS 158	$	(4	)	$	(9	)	$	(104	)	$	(42	)	$	(42	)	$	(25	)	$	(7	)
Unrealized gain on investments		126			12			-			5			-			-			-
Unrealized gain (loss) on derivative hedges		(10	)		-			-			-			(2	)		(1	)		-
AOCI (AOCL) Balance, December 31, 2006	$	112		$	3		$	(104	)	$	(37	)	$	(44	)	$	(26	)	$	(7	)
Net liability for unfunded retirement benefits     including the implementation of SFAS 158	$	(11	)	$	32		$	(69	)	$	(18	)	$	(18	)	$	(14	)	$	5
Unrealized gain on investments		168			16			-			7			-			-			-
Unrealized gain (loss) on derivative hedges		(16	)		-			-			-			(2	)		(1	)		-
AOCI (AOCL) Balance, December 31, 2007	$	141		$	48		$	(69	)	$	(11	)	$	(20	)	$	(15	)	$	5

Other comprehensive income (loss) reclassified to net income in the three years ended December 31, 2007 is as follows:

2007	FES			OE			CEI		TE			JCP&L			Met-Ed			Penelec
	(In millions)
Pension and other postretirement      benefits	$	(5	)	$	(14	)	$	5	$	2		$	(8	)	$	(6	)	$	(11	)
Loss on investments		(13	)		(3	)		-		-			-			-			-
Loss on derivative hedges		(12	)		-			-		-			-			-			-
Reclassification to net income		(30	)		(17	)		5		2			(8	)		(6	)		(11	)
Income taxes (benefits) related to     reclassification to net income		(13	)		(6	)		2		1			(4	)		(3	)		(5	)
Reclassification to net income, net of      income taxes (benefits)	$	(17	)	$	(11	)	$	3	$	1		$	(4	)	$	(3	)	$	(6	)
2006
Gain (Loss) on investments	$	28		$	-		$	-	$	(1	)	$	-		$	-		$	-
Loss on derivative hedges		(9	)		-			-		-			-			-			-
Reclassification to net income		19			-			-		(1	)		-			-			-
Income taxes related to     reclassification to net income		7			-			-		-			-			-			-
Reclassification to net income, net of      income taxes	$	12		$	-		$	-	$	(1	)	$	-		$	-		$	-
2005
Gain on investments	$	1		$	18		$	28	$	20		$	-		$	-		$	-
Gain on derivative hedges		3			-			-		-			-			-			-
Reclassification to net income		4			18			28		20			-			-			-
Income taxes related to     reclassification to net income		2			7			11		8			-			-			-
Reclassification to net income, net of      income taxes	$	2		$	11		$	17	$	12		$	-		$	-		$	-

(G)      CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE

Results in 2005 included after-tax charges of $8.8 million for FES, $16.3 million for OE, $3.7 million for CEI, $0.3 million for Met-Ed and $0.8 million for Penelec recorded as the cumulative effect of a change in accounting principle upon the adoption of FIN 47 in December 2005. Applicable legal obligations as defined under FIN 47 were identified at FES' active and retired generating units and the Companies' substation control rooms, service center buildings, line shops and office buildings, with asbestos remediation recognized as the primary conditional ARO. See Note 11 for further discussion of FES' and the Companies' asset retirement obligations.

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(H)      DIVESTITURES AND DISCONTINUED OPERATIONS

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

On March 31, 2005, FES completed the sale of its retail natural gas business for an after-tax gain of $5 million. The net results of $5 million (including the gain on the sale of assets) associated with the divested business are reported as discontinued operations on its Consolidated Statements of Income for 2005. Revenues and pre-tax operating results associated with discontinued operations in 2005 were $146 million and $1 million, respectively.

3.      TRANSACTIONS WITH AFFILIATED COMPANIES

FES' and the Companies' operating revenues, operating expenses, investment income and interest expense include transactions with affiliated companies.  These affiliated company transactions include PSAs between FES and the Companies, support service billings from FESC, FENOC and interest on associated company notes. In the fourth quarter of 2005, the Ohio Companies and Penn completed the intra-system transfers of their non-nuclear and nuclear generation assets to FGCO and NGC, respectively, excluding the leasehold interests of the Ohio Companies in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliated entities (see Note 14). This resulted in the elimination of the fossil generating units lease arrangement and the nuclear generation PSA between FES and the Ohio Companies with the exception of those arrangements related to the leasehold interests not included in the transfer. The Ohio Companies continue to have a PSA with FES to meet their PLR and default service obligations. Met-Ed and Penelec also have a partial requirements PSA with FES to meet a portion of their PLR and default service obligations (see Note 9(C)). FES was a supplier to JCP&L as a result of the BGS auction process through May 31, 2006. FES is incurring interest expense through FGCO and NGC on associated company notes payable to the Ohio Companies and Penn related to the intra-system generation asset transfers. The primary affiliated company transactions for FES and the Companies for the three years ended December 31, 2007 are as follows:

Affiliated Company Transactions - 2007	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Revenues:
Electric sales to affiliates	$	2,901	$	73	$	92	$	167	$	-	$	-	$	-
Ground lease with ATSI		-		12		7		2		-		-		-
Expenses:
Purchased power from affiliates		234		1,261		770		392		-		290		285
Support services		560		146		70		55		100		54		58
Investment Income:
Interest income from affiliates		-		30		17		18		1		1		1
Interest income from FirstEnergy		28		29		2		-		-		-		-
Interest Expense:
Interest expense to affiliates		31		1		1		-		1		1		1
Interest expense to FirstEnergy		34		-		1		10		11		10		11

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Affiliated Company Transactions - 2006	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Revenues:
Electric sales to affiliates	$	2,609	$	80	$	95	$	170	$	14	$	-	$	-
Ground lease with ATSI		-		12		7		2		-		-		-
Expenses:
Purchased power from affiliates		257		1,264		727		363		25		178		154
Support services		602		143		63		63		93		51		55
Investment Income:
Interest income from affiliates		-		75		58		32		1		1		1
Interest income from FirstEnergy		12		25		-		-		-		-		-
Interest Expense:
Interest expense to affiliates		109		-		-		-		-		-		-
Interest expense to FirstEnergy		53		-		7		7		11		5		11

Affiliated Company Transactions - 2005	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Revenues:
Electric sales to affiliates	$	2,425	$	355	$	362	$	300	$	33	$	-	$	-
Generating units rent from FES		-		146		49		12		-		-		-
Ground lease with ATSI		-		12		7		2		-		-		-
Expenses:
Purchased power from affiliates		308		938		557		295		78		348		321
Support services		64		314		257		171		94		45		51
Investment Income:
Interest income from affiliates		-		25		7		22		-		-		-
Interest income from FirstEnergy		-		22		-		-		-		-		-
Interest Expense:
Interest expense to affiliates		129		-		-		-		-		-		-
Interest expense to FirstEnergy		55		1		-		11		4		2		4

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

In the three years ended December 31, 2007, TE sold 150 MW of its Beaver Valley Unit 2 leased capacity entitlement to CEI ($98 million in 2007, $102 million in 2006 and $105 million in 2005). This sale agreement was terminated at the end of 2007.

4.     PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees and non-qualified plans that cover certain employees. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy's funding policy is based on actuarial computations using the projected unit credit method. On January 2, 2007, FirstEnergy made a $300 million voluntary cash contribution to its qualified pension plan. Projections indicated that additional cash contributions will not be required before 2017.

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

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

In December 2006, FirstEnergy adopted SFAS 158.  This Statement requires employers to recognize an asset or liability for the overfunded or underfunded status of their pension and other postretirement benefit plans.  For a pension plan, the asset or liability is the difference between the fair value of the plan's assets and the projected benefit obligation.  For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan's assets and the accumulated postretirement benefit obligation.  The Statement required employers to recognize all unrecognized prior service costs and credits and unrecognized actuarial gains and losses in AOCL, net of tax.  Such amounts will be adjusted as they are subsequently recognized as components of net periodic benefit cost or income pursuant to the current recognition and amortization provisions.  The incremental impact of adopting SFAS 158 was a decrease of $1.0 billion in pension assets, a decrease of $383 million in pension liabilities and a decrease in AOCL of $327 million, net of tax.

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Obligations and Funded Status	Pension Benefits						Other Benefits
As of December 31	2007			2006			2007			2006
	(In millions)
Change in benefit obligation
Benefit obligation as of January 1	$	5,031		$	4,911		$	1,201		$	1,884
Service cost		88			87			21			34
Interest cost		294			276			69			105
Plan participants' contributions		-			-			23			20
Plan amendments		-			-			-			(620	)
Medicare retiree drug subsidy		-			-			-			6
Actuarial (gain) loss		(381	)		38			(30	)		(119	)
Benefits paid		(282	)		(281	)		(102	)		(109	)
Benefit obligation as of December 31	$	4,750		$	5,031		$	1,182		$	1,201
Change in fair value of plan assets
Fair value of plan assets as of January 1	$	4,818		$	4,525		$	607		$	573
Actual return on plan assets		438			567			43			69
Company contribution		311			7			47			54
Plan participants' contribution		-			-			23			20
Benefits paid		(282	)		(281	)		(102	)		(109	)
Fair value of plan assets as of December 31	$	5,285		$	4,818		$	618		$	607
Qualified plan	$	700		$	(43	)
Non qualified plans		(165	)		(170	)
Funded status	$	535		$	(213	)	$	(564	)	$	(594	)
Accumulated benefit obligation	$	4,397		$	4,585
Amounts Recognized in the Statement of
Financial Position
Noncurrent assets	$	700		$	-		$	-		$	-
Current liabilities		(7	)		(7	)		-			-
Noncurrent liabilities		(158	)		(206	)		(564	)		(594	)
Net asset (liability) as of December 31	$	535		$	(213	))	$	(564	)	$	(594	)
Amounts Recognized in
Accumulated Other Comprehensive Income
Prior service cost (credit)	$	83		$	97		$	(1,041	)	$	(1,190	)
Actuarial loss		623			1,039			635			702
Net amount recognized	$	706		$	1,136		$	(406	)	$	(488	)
Assumptions Used to Determine
Benefit Obligations As of December 31
Discount rate		6.50	%		6.00	%		6.50	%		6.00	%
Rate of compensation increase		5.20	%		3.50	%
Allocation of Plan Assets
As of December 31
Asset Category
Equity securities		61	%		64	%		69	%		72	%
Debt securities		30			29			27			26
Real estate		7			5			2			1
Private equities		1			1			-			-
Cash		1			1			2			1
Total		100	%		100	%		100	%		100	%

FES' and the Companies' share of the net pension and OPEB asset (liability) as of December 31, 2007 and 2006 is as follows:

	Pension Benefits					Other Benefits
Net Pension and OPEB Asset (Liability)	2007		2006			2007			2006
	(In millions)
FES	$	42	$	(157	)	$	(102	)	$	(81	)
OE		229		68			(178	)		(167	)
CEI		62		(13	)		(93	)		(110	)
TE		29		(3	)		(63	)		(74	)
JCP&L		93		15			8			(8	)
Met-Ed		51		7			(8	)		(19	)
Penelec		66		11			(40	)		(49	)

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Estimated Items to be Amortized in 2008
Net Periodic Pension Cost from	Pension		Other
Accumulated Other Comprehensive Income	Benefits		Benefits
	(In millions)
Prior service cost (credit)	$	13	$	(149	)
Actuarial loss	$	8	$	47

		Pension Benefits									Other Benefits
Components of Net Periodic Benefit Costs			2007			2006			2005			2007			2006			2005
	(In millions)
Service cost		$	88		$	87		$	80		$	21		$	34		$	40
Interest cost			294			276			262			69			105			111
Expected return on plan assets			(449	)		(396	)		(345	)		(50	)		(46	)		(45	)
Amortization of prior service cost			13			13			10			(149	)		(76	)		(45	)
Recognized net actuarial loss			45			62			39			45			56			40
Net periodic cost		$	(9	)	$	42		$	46		$	(64	)	$	73		$	101
Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost		Pension Benefits									Other Benefits
for Years Ended December 31		2007			2006			2005			2007			2006			2005
Discount rate			6.00	%		5.75	%		6.00	%		6.00	%		5.75	%		6.00	%
Expected long-term return on plan assets			9.00	%		9.00	%		9.00	%		9.00	%		9.00	%		9.00	%
Rate of compensation increase			3.50	%		3.50	%		3.50	%

FES' and the Companies' share of the net periodic pension and OPEB cost for the three years ended December 31, 2007 is as follows:

	Pension Benefits									Other Benefits
Net Periodic Pension and OPEB Costs	2007			2006			2005			2007			2006		2005
	(In millions)
FES	$	21		$	40		$	33		$	(10	)	$	14	$	23
OE		(16	)		(6	)		0			(11	)		17		28
CEI		1			4			1			4			11		15
TE		-			1			1			5			8		9
JCP&L		(9	)		(5	)		(1	)		(16	)		2		7
Met-Ed		(7	)		(7	)		(4	)		(10	)		3		1
Penelec		(10	)		(5	)		(5	)		(13	)		7		8

In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. The assumed rates of return on pension plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy's pension trusts. The long-term rate of return is developed considering the portfolio's asset allocation strategy.

FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

FES and the Companies have assessed the impact of recent market developments, including a series of rating agency downgrades of subprime mortgage-related assets, on the value of the assets held in their pension and other postretirement benefit trusts. Based on this assessment, FES and the Companies believe that the fair value of their investments as of December 31, 2007 will not be materially affected by the subprime credit crisis due to their relatively small exposure to subprime assets.

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Assumed Health Care Cost Trend Rates
As of December 31	2007			2006
Health care cost trend rate assumed for next
year (pre/post-Medicare)		9-11	%		9-11	%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)		5	%		5	%
Year that the rate reaches the ultimate trend
rate (pre/post-Medicare)		2015-2017			2011-2013

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

	1-Percentage-		1-Percentage-
	Point Increase		Point Decrease
	(In millions)
Effect on total of service and interest cost	$	5	$	(4	)
Effect on accumulated postretirement benefit obligation	$	48	$	(42	)

Taking into account estimated employee future service, FirstEnergy expects to make the following pension benefit payments from plan assets and other benefit payments, net of the Medicare subsidy:

	Pension		Other
	Benefits		Benefits
	(In millions)
2008	$	300	$	83
2009		300		86
2010		307		90
2011		313		94
2012		322		95
Years 2013- 2017		1,808		495

5.      FAIR VALUE OF FINANCIAL INSTRUMENTS

        (A)      LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS

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

	2007				2006
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
FES	$	1,975	$	1,971	$	3,084	$	3,084
OE		1,182		1,197		1,294		1,337
CEI		1,666		1,706		1,919		2,000
TE		304		283		389		388
JCP&L		1,597		1,560		1,366		1,388
Met-Ed		542		535		592		572
Penelec		779		779		479		490

The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FES and the Companies.

        (B)      INVESTMENTS

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities. FES and the Companies periodically evaluate their investments for other-than-temporary impairment. They first consider their intent and ability to hold the investment until recovery and then consider, among other factors, the duration and the extent to which the securitys fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment.

102

FES and the Companies have assessed the impact of recent market developments, including a series of rating agency downgrades of subprime mortgage-related assets, on the value of the assets held in their nuclear decommissioning trusts. Based on this assessment, FES and the Companies believe that the fair value of their investments as of December 31, 2007 will not be materially affected by the subprime credit crisis due to their relatively small exposure to subprime assets.

Available-For-Sale Securities

FES and the Companies hold debt and equity securities within their nuclear decommissioning trusts, nuclear fuel disposal trusts and NUG trusts. These trust investments are classified as available-for-sale with the fair value representing quoted market prices. FES and the Companies have no securities held for trading purposes.

The following table provides the carrying value, which approximates fair value, of investments in available-for-sale securities as of December 31, 2007 and 2006. The fair value was determined using the specific identification method.

	2007				2006
	Debt		Equity		Debt		Equity
	Securities		Securities		Securities		Securities
	(In millions)
FES	$	417	$	916	$	365	$	873
OE		45		82		38		80
TE		67		-		61		-
JCP&L(1)		248		102		235		97
Met-Ed		115		172		106		164
Penelec(2)		167		83		151		72

(1)	Excludes $2 million and $3 million of cash in 2007 and 2006, respectively
(2)	Excludes $1 million and $2 million of cash in 2007 and 2006, respectively

The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities as of December 31:

	2007								2006
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
Debt securities	(In millions)
FES	$	402	$	15	$	-	$	417	$	360	$	5	$	-	$	365
OE		43		2		-		45		38		-		-		38
TE		63		4		-		67		61		-		-		61
JCP&L		249		3		4		248		237		2		4		235
Met-Ed		112		3		-		115		105		1		-		106
Penelec		166		1		-		167		150		1		-		151
Equity securities
FES	$	631	$	285	$	-	$	916	$	652	$	221	$	-	$	873
OE		59		23		-		82		61		19		-		80
JCP&L		89		13		-		102		73		24		-		97
Met-Ed		136		36		-		172		114		50		-		164
Penelec		80		3		-		83		55		17		-		72

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income for the three years ended December 31, 2007 were as follows:

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	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
2007
Proceeds from sales	$	656	$	38	$	-	$	45	$	196	$	185	$	175
Realized gains		29		1		-		1		23		30		19
Realized losses		42		4		-		1		3		2		1
Interest and dividend income		42		4		-		3		13		8		10
2006
Proceeds from sales	$	1,066	$	39	$	-	$	53	$	217	$	176	$	99
Realized gains		118		1		-		-		1		1		-
Realized losses		90		1		-		1		5		4		4
Interest and dividend income		36		3		-		3		13		7		7
2005
Proceeds from sales	$	1,097	$	284	$	490	$	366	$	165	$	167	$	93
Realized gains		109		35		49		35		4		6		4
Realized losses		39		7		20		15		5		7		6
Interest and dividend income		32		13		12		9		13		6		7

Upon adoption of FSP SFAS 115-1 and SFAS 124-1, FES, OE and TE began expensing unrealized losses on available-for-sale securities held in its nuclear decommissioning trusts since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of other-than-temporary impairment.

Unrealized gains applicable to OE's, TE's and the majority of FES' decommissioning trusts are recognized in OCI in accordance with SFAS 115, as fluctuations in fair value will eventually impact earnings. The decommissioning trusts of JCP&L, Met-Ed and Penelec are subject to regulatory accounting in accordance with SFAS 71. Net unrealized gains and losses are recorded as regulatory assets or liabilities since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers.

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

Held-To-Maturity Securities

The following table provides the amortized cost basis (carrying value), unrealized gains and losses and fair values of investments in held-to-maturity securities with maturity dates ranging from 2008 to 2017 excluding; restricted funds, whose carrying value is assumed to approximate market value, notes receivable, whose fair value represents the present value of the cash inflows based on the yield to maturity, and other investments of $87 million and $127 million in 2007 and 2006, respectively, excluded by SFAS 107, "Disclosures about Fair Values of Financial Instruments," as of December 31:

	2007						2006
	Cost		Unrealized	Unrealized		Fair	Cost		Unrealized	Unrealized		Fair
	Basis		Gains	Losses		Value	Basis		Gains	Losses		Value
Debt securities	(In millions)
OE		254	28		-	282		291	34		-	325
CEI		463	68		-	531		523	65		-	588
JCP&L		1	-		-	1		-	-		-	-
Equity securities
OE		2	-		-	2		3	-		-	3

The following table provides the approximate fair value and related carrying amounts of notes receivable as of December 31:

	2007			2006
	Carrying		Fair	Carrying		Fair
	Value		Value	Value		Value
Notes receivable	(In millions)
FES		65	63		69	66
OE		259	299		1,219	1,251
CEI		1	1		487	487
TE		192	223		298	327

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The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity.  The yields assumed were based on financial instruments with similar characteristics and terms.  The maturity dates range from 2008 to 2040.

        (C)      DERIVATIVES

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

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

FES hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases. FES maximum hedge terms are typically two years. The effective portion of such hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings. The ineffective portion of cash flow hedge was immaterial during this period.

FES net deferred losses of $16 million included in AOCL as of December 31, 2007, for derivative hedging activity, as compared to $10 million as of December 31, 2006, resulted from a net $14 million increase related to current hedging activity and an $8 million decrease due to net hedge losses reclassified to earnings during 2007. Based on current estimates, approximately $15 million (after tax) of the net deferred losses on derivative instruments in AOCL as of December 31, 2007 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.

6. LEASES

FES and the Companies lease certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion (net after-tax proceeds of approximately $1.2 billion) for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034.  A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates.  The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCOs obligations under each of the leases. This transaction, which is classified as an operating lease under GAAP for FES and a financing for FGCO, generated tax capital gains of approximately $742 million, all of which were offset by existing tax capital loss carryforwards.

In 1987, OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. In that same year, CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respective leases, OE, CEI and TE continue to be responsible, to the extent of their leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. They have the right, at the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes.

105

Effective October 16, 2007 CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. FGCO assumed all of CEIs and TEs obligations arising under those leases. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCOs 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.

The rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2007 are summarized as follows:

	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
2007
Operating leases
Interest element	$	29.8	$	82.8	$	23.8	$	38.2	$	2.9	$	2.1	$	0.8
Other		14.6		62.2		37.6		62.8		5.4		1.6		3.9
Capital leases
Interest element		-		0.1		0.4		-		-		-		-
Other		0.1		-		0.6		-		-		-		-
Total rentals	$	44.5	$	145.1	$	62.4	$	101.0	$	8.3	$	3.7	$	4.7
2006
Operating leases
Interest element	$	-	$	87.1	$	26.3	$	41.1	$	2.8	$	2.0	$	0.6
Other		-		57.5		48.1		68.2		4.5		1.4		3.8
Capital leases
Interest element		-		0.3		0.4		-		-		-		-
Other		-		1.3		0.6		-		-		-		-
Total rentals	$	-	$	146.2	$	75.4	$	109.3	$	7.3	$	3.4	$	4.4
2005
Operating leases
Interest element	$	-	$	93.4	$	28.4	$	43.9	$	2.6	$	1.9	$	0.7
Other		-		52.3		40.9		62.3		3.2		1.0		2.1
Capital leases
Interest element		-		0.8		0.5		-		-		-		-
Other		-		1.9		0.5		-		-		-		-
Total rentals	$	-	$	148.4	$	70.3	$	106.2	$	5.8	$	2.9	$	2.8

Established by OE in 1996, PNBV purchased a portion of the lease obligation bonds issued on behalf of lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. Similarly, CEI and TE established Shippingport in 1997 to purchase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions.

The future minimum capital lease payments as of December 31, 2007 are as follows:

Capital Leases	FES		OE		CEI		TE
	(In millions)
2008	$	0.1	$	0.1	$	1.0	$	-
2009		-		0.2		1.0		0.1
2010		0.1		0.1		1.0		-
2011		-		0.2		1.0		-
2012		-		0.1		0.6		-
Years thereafter		-		-		-		-
Total minimum lease payments		0.2		0.7		4.6		0.1
Executory costs		-		-		-		-
Net minimum lease payments		0.2		0.7		4.6		0.1
Interest portion		-		0.4		0.9		-
Present value of net minimum
lease payments		0.2		0.3		3.7		0.1
Less current portion		0.1		0.1		0.6		-
Noncurrent portion	$	0.1	$	0.2	$	3.1	$	0.1

106

The future minimum operating lease payments as of December 31, 2007 are as follows:

Operating Leases	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
2008	$	172.7	$	147.8	$	5.7	$	64.9	$	8.9	$	4.2	$	5.5
2009		175.9		148.8		6.2		65.0		9.4		4.7		5.8
2010		176.8		149.5		6.1		65.0		8.9		4.6		5.6
2011		171.8		148.5		5.8		64.9		7.9		4.2		5.1
2012		215.0		148.3		5.2		64.8		7.0		3.8		4.5
Years thereafter		2,544.6		615.8		29.6		275.2		64.3		47.1		15.0
Total minimum lease payments	$	3,456.8	$	1,358.7	$	58.6	$	599.8	$	106.4	$	68.6	$	41.5

CEI and TE had recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger between OE and Centerior. The total above-market lease obligation of $722 million associated with Beaver Valley Unit 2 has been amortized on a straight-line basis (approximately $31 million and $6 million per year for CEI and TE, respectively).  Effective December 31, 2007, TE terminated the sale of its 150 MW of Beaver Valley Unit 2 leased capacity entitlement to CEI.  The remaining above-market lease liability for Beaver Valley Unit 2 of $347 million as of December 31, 2007, of which $37 million is classified as current, will be amortized by TE on straight-line basis through the end of the lease term in 2017. The total above-market lease obligation of $755 million associated with the Bruce Mansfield Plant has been amortized on a straight-line basis (approximately $29 million and $19 million per year for CEI and TE, respectively). Effective October 16, 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. The remaining above-market lease liability for the Bruce Mansfield Plant of $399 million as of December 31, 2007, of which $46 million is classified as current, will be amortized by FGCO on straight-line basis through the end of the lease term in 2016.

7. VARIABLE INTEREST ENTITIES

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

Trusts

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

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

Loss Contingencies

FES and the Ohio Companies are exposed to losses under their applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments are made. The following table shows each companys net exposure to loss based upon the casualty value provisions mentioned above:

107

	Maximum Exposure		Discounted Lease Payments, net		Net Exposure
	(In millions)
FES	$	1,338	$	1,198	$	140
OE		837		610		227
CEI		753		85		668
TE		753		449		304

Effective October 16, 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant under their 1987 sale and leaseback transactions to FGCO.  FGCO assumed all of CEIs and TEs obligations arising under those leases.  FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCOs leasehold interests under its July 13, 2007 Bruce Mansfield Unit 1 sale and leaseback transaction discussed above, 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 assignments terminate automatically upon the termination of the underlying leases.

Power Purchase Agreements

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

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

Since JCP&L, Met-Ed and Penelec have no equity or debt interests in the NUG entities, their maximum exposure to loss relates primarily to the above-market costs they incur for power. JCP&L, Met-Ed and Penelec expect any above-market costs they incur to be recovered from customers. Purchased power costs from these entities during the three years ended December 31, 2007 are shown in the following table:

	2007		2006		2005
	(In millions)
JCP&L	$	90	$	81	$	101
Met-Ed		56		60		50
Penelec		30		29		28

108

8.      TAXES

Income Taxes

FES and the Companies record income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and loss carryforwards and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. Details of income taxes for the three years ended December 31, 2007 are shown below:

PROVISION FOR INCOME TAXES	FES			OE			CEI			TE			JCP&L			Met-Ed			Penelec
	(In millions)
2007
Currently payable-
Federal	$	528		$	105		$	166		$	73		$	138		$	26		$	41
State		111			(4	)		20			7			42			7			12
		639			101			186			80			180			33			53
Deferred, net-
Federal		(288	)		-			(23	)		(27	)		(25	)		30			10
State		(42	)		4			2			2			(5	)		6			1
		(330	)		4			(21	)		(25	)		(30	)		36			11
Investment tax credit amortization		(4	)		(4	)		(2	)		(1	)		(1	)		(1	)		-
Total provision for income taxes	$	305		$	101		$	163		$	54		$	149		$	68		$	64
2006
Currently payable-
Federal	$	102		$	162		$	174		$	83		$	79		$	21		$	21
State		18			30			32			14			24			6			7
		120			192			206			97			103			27			28
Deferred, net-
Federal		110			(58	)		(14	)		(35	)		34			40			26
State		11			(7	)		1			(1	)		11			11			3
		121			(65	)		(13	)		(36	)		45			51			29
Investment tax credit amortization		(5	)		(4	)		(4	)		(1	)		(1	)		(1	)		-
Total provision for income taxes	$	236		$	123		$	189		$	60		$	147		$	77		$	57
2005
Currently payable-
Federal	$	29		$	275		$	90		$	62		$	78		$	24		$	7
State		1			74			23			18			22			8			1
		30			349			113			80			100			32			8
Deferred, net-
Federal		94			(60	)		28			(19	)		27			2			11
State		5			37			17			15			10			(3	)		(1	)
		99			(23	)		45			(4	)		37			(1	)		10
Investment tax credit amortization		(5	)		(16	)		(5	)		(2	)		(1	)		(1	)		(1	)
Total provision for income taxes	$	124		$	310		$	153		$	74		$	136		$	30		$	17

FES and the Companies are all party to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, is reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit.

109

The following tables provide a reconciliation of federal income tax expense at FES and the Companies statutory rate to their total provision for income taxes for the three years ended December 31, 2007.

	FES			OE			CEI			TE			JCP&L			Met-Ed			Penelec
	(In millions)
2007
Book income before provision for income taxes	$	833		$	298		$	440		$	145		$	335		$	164		$	157
Federal income tax expense at statutory rate	$	292		$	104		$	154		$	51		$	117		$	57		$	55
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits		(4	)		(4	)		(2	)		(1	)		(1	)		(1	)		-
State income taxes, net of federal tax benefit		45			-			14			6			24			9			8
Manufacturing deduction		(6	)		(2	)		(1	)		-			-			-			-
Other, net		(22	)		3			(2	)		(2	)		9			3			1
Total provision for income taxes	$	305		$	101		$	163		$	54		$	149		$	68		$	64
2006
Book income before provision for income taxes	$	655		$	335		$	495		$	159		$	337		$	(163	)	$	141
Federal income tax expense at statutory rate	$	229		$	117		$	173		$	56		$	118		$	(57	)	$	49
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits		(5	)		(4	)		(4	)		(1	)		(1	)		(1	)		-
State income taxes, net of federal tax benefit		18			15			22			8			23			11			6
Goodwill impairment		-			-			-			-			-			124			-
Other, net		(6	)		(5	)		(2	)		(3	)		7			-			2
Total provision for income taxes	$	236		$	123		$	189		$	60		$	147		$	77		$	57
2005
Book income before provision for income taxes	$	333		$	640		$	384		$	150		$	319		$	76		$	44
Federal income tax expense at statutory rate	$	117		$	224		$	134		$	52		$	112		$	27		$	16
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits		(5	)		(16	)		(5	)		(2	)		(1	)		(1	)		(1	)
State income taxes, net of federal tax benefit		4			72			26			22			21			3			-
Penalties		10			3			-			-			-			-			-
Other, net		(2	)		27			(2	)		2			4			1			2
Total provision for income taxes	$	124		$	310		$	153		$	74		$	136		$	30		$	17

110

Accumulated deferred income taxes as of December 31, 2007 and 2006 are as follows:

ACCUMULATED DEFERRED INCOME TAXES	FES			OE			CEI			TE			JCP&L			Met-Ed			Penelec
	(In millions)
AS OF DECEMBER 31, 2007
Property basis differences	$	281		$	463		$	372		$	154		$	439		$	266		$	319
Regulatory transition charge		-			139			156			116			235			60			-
Customer receivables for future income taxes		-			22			1			-			14			49			62
Deferred customer shopping incentive		-			61			172			29			-			-			-
Deferred sale and leaseback gain		(455	)		(49	)		-			-			(20	)		(11	)		-
Nonutility generation costs		-			-			-			-			-			22			(112	)
Unamortized investment tax credits		(23	)		(6	)		(7	)		(4	)		(2	)		(6	)		(5	)
Other comprehensive income		84			25			(39	)		(8	)		(20	)		(16	)		(2	)
Retirement benefits		(13	)		(14	)		25			(1	)		39			16			(17	)
Lease market valuation liability		(148	)		-			-			(135	)		-			-			-
Oyster Creek securitization (Note 10(C))		-			-			-			-			149			-			-
Asset retirement obligations		34			(2	)		(3	)		7			(48	)		(57	)		(64	)
Deferred gain for asset sales - affiliated companies		-			45			30			10			-			-			-
Allowance for equity funds used during construction		-			21			-			-			-			-			-
PJM transmission costs		-			-			-			-			-			97			13
All other		(37	)		76			19			(65	)		14			19			17
Net deferred income tax liability (asset)	$	(277	)	$	781		$	726		$	103		$	800		$	439		$	211
AS OF DECEMBER 31, 2006
Property basis differences	$	112		$	497		$	534		$	243		$	436		$	277		$	329
Regulatory transition charge		-			(28	)		116			33			254			82			-
Customer receivables for future income taxes		-			31			3			(3	)		4			44			62
Deferred customer shopping incentive		-			68			132			18			-			-			-
Deferred sale and leaseback gain		-			(55	)		-			-			(20	)		(11	)		-
Nonutility generation costs		-			-			-			-			-			1			(123	)
Unamortized investment tax credits		(24	)		(8	)		(9	)		(3	)		(3	)		(7	)		(5	)
Other comprehensive income		60			(15	)		(70	)		(24	)		(44	)		(28	)		(18	)
Retirement benefits		(28	)		30			11			8			36			12			(19	)
Lease market valuation liability		-			-			(235	)		(96	)		-			-			-
Oyster Creek securitization (Note 10(C))		-			-			-			-			162			-			-
Asset retirement obligations		29			10			2			4			(16	)		(42	)		(59	)
Deferred gain for asset sales - affiliated companies		-			47			31			10			-			-			-
Allowance for equity funds used during construction		-			23			-			-			-			-			-
PJM transmission costs		-			-			-			-			-			53			13
All other		(28	)		74			(44	)		(29	)		(5	)		6			14
Net deferred income tax liability	$	121		$	674		$	471		$	161		$	804		$	387		$	194

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

As of January 1, 2007, the total amount of FirstEnergy's unrecognized tax benefits was $268 million (see table below for amounts included for FES and the Companies). FirstEnergy recorded a $2.7 million (OE - $0.6 million, CEI - $0.2 million, FES - $0.5 million and other subsidiaries of FirstEnergy - $1.4 million) cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy's effective tax rate upon recognition. The majority of items that would not have affected the effective tax rate resulted from purchase accounting adjustments that would reduce goodwill upon recognition through December 31, 2008.

111

A reconciliation of the change in the unrecognized tax benefits for the year ended December 31, 2007 is as follows:

	FES			OE			CEI			TE			JCP&L			Met-Ed		Penelec
	(In millions)
Balance as of January 1, 2007	$	14		$	(19	)	$	(15	)	$	(3	)	$	44		$	18	$	20
Increase for tax positions related to the    current year		-			1			-			-			-			-		-
Increase for tax positions related to    prior years		4			10			2			2			-			6		-
Decrease for tax positions of    prior years		(4	)		(4	)		(4	)		-			(6	)		-		(4	)
Balance as of December 31, 2007	$	14		$	(12	)	$	(17	)	$	(1	)	$	38		$	24	$	16

As of December 31, 2007, FES and the Companies expect that $7 million of the unrecognized benefits will be resolved within the next twelve months and are included in the caption Accrued taxes, with the remaining amount included in Other assets and Other non-current liabilities on the Consolidated Balance Sheets as follows:

Balance Sheet Classifications	FES		OE			CEI			TE			JCP&L		Met-Ed		Penelec
	(In millions)
Current-
Accrued taxes	$	3	$	4		$	-		$	-		$	-	$	-	$	-
Non-Current-
Other asset				(16	)		(17	)		(1	)
Other non-current liabilities		11		-			-			-			38		24		16
Net liabilities (assets)	$	14	$	(12	)	$	(17	)	$	(1	)	$	38	$	24	$	16

FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FES and the Companies include net interest and penalties in the provision for income taxes, consistent with their policy prior to implementing FIN 48.

The following table summarizes the net interest expense (income) recognized by FES and the Companies for the three years ended December 31, 2007 and the cumulative net interest payable (receivable) as of December 31, 2007 and 2006:

	Net Interest Expense (Income)									Net Interest Payable
	For the Years Ended									(Receivable)
	December 31,									As of December 31,
	2007			2006			2005			2007			2006
	(In millions)									(In millions)
FES	$	-		$	1		$	-		$	2		$	3
OE		1			1			(8	)		(5	)		(6	)
CEI		(1	)		1			(3	)		(2	)		(3	)
TE		-			1			(1	)		-			-
JCP&L		1			(2	)		5			10			9
Met-Ed		2			-			2			5			3
Penelec		-			(1	)		3			4			4

FES and the Companies have tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2006. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audit for years 2004 and 2005 began in June 2006 and are not expected to close before December 2008. The IRS began auditing the year 2006 in April 2006 and the year 2007 in February 2007 under its Compliance Assurance Process experimental program. Neither audits are expected to close before December 2008. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FES or the Companies financial condition or results of operations.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity (see Note 6). This transaction generated tax capital gains of approximately $742 million, all of which were offset by existing tax capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowance in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 2(E)).

112

FES, Met-Ed and Penelec have pre-tax net operating loss carryforwards for state and local income tax purposes. These losses expire as follows:

Expiration Period	FES		Met-Ed		Penelec
	(In millions)
2008-2012	$	-	$	-	$	-
2013-2017		-		-		-
2018-2022		22		5		229
2023-2027		16		-		14
	$	38	$	5	$	243

General Taxes

Details of general taxes for the three years ended December 31, 2007 are shown below:

GENERAL TAXES	FES		OE			CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
2007
Kilowatt-hour excise	$	1	$	99		$	69	$	29	$	52	$	-	$	-
State gross receipts		18		17			-		-		-		73		66
Real and personal property		53		59			65		19		5		2		2
Social security and unemployment		14		8			6		3		9		5		5
Other		1		(2	)		2		-		-		-		3
Total general taxes	$	87	$	181		$	142	$	51	$	66	$	80	$	76
2006
Kilowatt-hour excise	$	-	$	95		$	68	$	28	$	50	$	-	$	-
State gross receipts		10		19			-		-		-		67		62
Real and personal property		49		55			61		20		5		2		1
Social security and unemployment		13		7			5		2		9		4		5
Other		1		4			1		1		-		4		5
Total general taxes	$	73	$	180		$	135	$	51	$	64	$	77	$	73
2005
Kilowatt-hour excise	$	-	$	94		$	69	$	29	$	52	$	-	$	-
State gross receipts		9		20			-		-		-		63		58
Real and personal property		44		67			78		25		5		2		1
Social security and unemployment		12		8			5		2		8		4		5
Other		2		4			1		1		-		5		5
Total general taxes	$	67	$	193		$	153	$	57	$	65	$	74	$	69

Commercial Activity Tax

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

The increase (decrease) to income taxes associated with the adjustment to net deferred taxes in 2005 is summarized below (in millions):

FES	$ (7	)
OE	$32
CEI	$  4
TE	$18

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Income tax expenses were reduced during 2005 by the initial phase-out of the Ohio income-based franchise tax and phase-in of the CAT tax as summarized below (in millions):

FES	$1
OE	$3
CEI	$5
TE	$1

9.     REGULATORY MATTERS

(A)      RELIABILITY INITIATIVES

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. Canada Power System Outage Task Force) regarding enhancements to regional reliability. 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.

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 consultants 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.

(B)      OHIO

On September 9, 2005, the Ohio Companies filed their RCP with the PUCO. The filing included a stipulation and supplemental stipulation with several parties agreeing to the provisions set forth in the plan. On January 4, 2006, the PUCO issued an order which approved the 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.

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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 Courts 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.

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 (OE - $28 million, CEI - $22 million and TE - $14 million). 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 (OE - $156 million, CEI - $108 million and TE - $68 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 (OE - $57 million to $66 million, CEI - $54 million to $61 million and TE - $50 million to $53 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 (OE - $6 million, CEI - $5 million and TE - $2 million) of interest costs deferred through December 31, 2007. 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 utilitys total load notwithstanding the customers 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.

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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, the Ohio Companies cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on their operations.

(C)      PENNSYLVANIA

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 PPUC's January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-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.

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On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC's determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase.  The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. 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 their results of operations.

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 PPUC's 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 for 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 companys 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, the Pennsylvania Companies are unable to predict what impact, if any, such legislation may have on their operations.

(D)      NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of 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 Jerseys 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, JCP&L cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations.

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, JCP&L cannot predict the outcome of this process nor determine the impact, if any, such regulations may have on its operations.

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(E)       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. FERCs 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 PJMs 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.

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.

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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.

MISOs 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 FERCs 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 MISOs 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.

Duquesnes 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 PJMs forward capacity market.  FirstEnergy believes that Duquesnes filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesnes proposal. Consequently, on December 4, 2007 and January 3, 2008, FirstEnergy submitted responsive filings that, while conceding Duquesnes rights to exit PJM, contested various aspects of Duquesnes proposal.  FirstEnergy particularly focused on Duquesnes proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesnes 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 Duquesnes 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 Duquesnes plans.

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On January 17, 2008, the FERC conditionally approved Duquesnes 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 MISOs 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 Duquesnes 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.

10.   CAPITALIZATION

        (A)      RETAINED EARNINGS (ACCUMULATED DEFICIT)

There are no restrictions on retained earnings for payment of cash dividends on OE's, CEI's, TEs, JCP&L's and FES' common stock. In general, Met-Ed's and Penelec's respective first mortgage indentures restrict the payment of dividends or distributions on or with respect to each of the company's common stock to amounts credited to earned surplus since the date of its indenture. As of December 31, 2007, Penelec had retained earnings available to pay common stock dividends of $48 million, net of amounts restricted under its first mortgage indenture. Met-Ed had an accumulated deficit of $139 million as of December 31, 2007, and is therefore restricted from making cash dividend distributions to FirstEnergy.

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        (B)      PREFERRED AND PREFERENCE STOCK

No preferred shares or preference shares are currently outstanding. The following table details the change in preferred shares outstanding for OE, CEI, TE and JCP&L for the three years ended December 31, 2007.

	Not Subject to						Subject to
	Mandatory Redemption						Mandatory Redemption
				Par or						Par or
	Number			Stated			Number			Stated
	of Shares			Value			of Shares			Value
	(Dollars in thousands)
OE
Balance, January 1, 2005		1,000,699		$	100,070			127,500		$	12,750
Redemptions-
7.750% Series		(250,000	)		(25,000	)
7.625% Series								(127,500	)		(12,750	)
Balance, December 31, 2005		750,699			75,070			-			-
Redemptions-
3.90% Series		(152,510	)		(15,251	)
4.40% Series		(176,280	)		(17,628	)
4.44% Series		(136,560	)		(13,656	)
4.56% Series		(144,300	)		(14,430	)
4.24% Series		(40,000	)		(4,000	)
4.25% Series		(41,049	)		(4,105	)
4.64% Series		(60,000	)		(6,000	)
Balance, December 31, 2006		-			-			-			-
Balance, December 31, 2007		-		$	-			-		$	-
CEI
Balance, January 1, 2005		974,000		$	96,404			40,000		$	4,009
Redemptions-
$7.40 Series A		(500,000	)		(50,000	)
Adjustable Series L		(474,000	)		(46,404	)
$7.35 Series C								(40,000	)		(4,000	)
Amortization of fair market
value adjustments-
$7.35 Series C											(9	)
Balance, December 31, 2005		-			-			-			-
Balance, December 31, 2006		-			-			-			-
Balance, December 31, 2007		-		$	-			-		$	-
TE
Balance, January 1, 2005		4,110,000		$	126,000
Redemptions-
Adjustable Series A		(1,200,000	)		(30,000	)
Balance, December 31, 2005		2,910,000			96,000
Redemptions-
$4.25 Series		(160,000	)		(16,000	)
$4.56 Series		(50,000	)		(5,000	)
$4.25 Series		(100,000	)		(10,000	)
$2.365 Series		(1,400,000	)		(35,000	)
Adjustable Series B		(1,200,000	)		(30,000	)
Balance, December 31, 2006		-			-
Balance, December 31, 2007		-		$	-
JCP&L
Balance, January 1, 2005		125,000		$	12,649
Balance, December 31, 2005		125,000			12,649
Redemptions-
4.00% Series		(125,000	)		(12,649	)
Balance, December 31, 2006		-			-
Balance, December 31, 2007		-		$	-

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The Companies preferred stock and preference stock authorizations are as follows:

	Preferred Stock				Preference Stock
	Shares		Par		Shares		Par
	Authorized		Value		Authorized		Value
OE		6,000,000	$	100		8,000,000	no par
OE		8,000,000	$	25
Penn		1,200,000	$	100
CEI		4,000,000	no par			3,000,000	no par
TE		3,000,000	$	100		5,000,000	$	25
TE		12,000,000	$	25
JCP&L		15,600,000	no par
Met-Ed		10,000,000	no par
Penelec		11,435,000	no par

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

Securitized Transition Bonds

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

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of December 31, 2007, $397 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company's equity and assets, which consists primarily of bondable transition property.

Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate annual servicing fees of up to $628,000 that are payable from TBC collections.

Other Long-term Debt

Each of the Companies, except for JCP&L, has a first mortgage indenture under which it issues FMB secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. 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.

FES and the Companies have various debt covenants under their respective financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt and the maintenance of certain financial ratios. There also exist cross-default provisions among financing arrangements of FirstEnergy, FES and the Companies.

Based on the amount of FMB authenticated by the respective mortgage bond trustees through December 31, 2007, the Companies' annual sinking fund requirement for all FMB issued under the various mortgage indentures amounted to $50 million (Penn - $5 million, JCP&L - $16 million, Met-Ed - $8 million and Penelec - $21 million). Penn expects to deposit funds with its mortgage bond trustee in 2008 that will then be withdrawn upon the surrender for cancellation of a like principal amount of FMB, specifically authenticated for such purposes against unfunded property additions or against previously retired FMB. This method can result in minor increases in the amount of the annual sinking fund requirement. Met-Ed and Penelec could fulfill their sinking fund obligations by providing bondable property additions, previously retired FMB or cash to the respective mortgage bond trustees.

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

Sinking Fund Requirements	FES		OE		CEI		JCP&L		Met-Ed		Penelec
	(In millions)
2008	$	1,441	$	333	$	207	$	27	$	-	$	-
2009		-		2		162		29		-		100
2010		15		65		18		31		100		59
2011		-		1		20		32		-		-
2012		-		1		22		34		-		-

TE has no sinking fund requirements for the next five years.

Included in the table above are amounts for certain variable interest rate pollution control revenue bonds that currently bear interest in an interest rate mode that permits individual debt holders to put the respective debt back to the issuer for purchase prior to maturity. These amounts are $1.7 billion and $15 million in 2008 and 2010, respectively, representing the next time the debt holders may exercise this right. The applicable pollution control revenue bond indentures provide that bonds so tendered for purchase will be remarketed by a designated remarketing agent. These amounts for FES, OE and CEI are shown as follows:

Year	FES		OE		CEI
	(In millions)
2008	$	1,441	$	156	$	82
2010		15		-		-

Obligations to repay certain pollution control revenue bonds are secured by several series of FMB. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank LOCs of $1.6 billion as of December 31, 2007, or noncancelable municipal bond insurance of $593 million as of December 31, 2007, to pay principal of, or interest on, the applicable pollution control revenue bonds. To the extent that drawings are made under the LOCs or the policies, FGCO, NGC and the Companies are entitled to a credit against their obligation to repay those bonds. FGCO, NGC and the Companies pay annual fees of 0.15% to 1.70% of the amounts of the LOCs to the issuing banks and 0.15% to 0.16% of the amounts of the insurance policies to the insurers and are obligated to reimburse the banks or insurers, as the case may be, for any drawings thereunder. Certain of the issuing banks and insurers hold FMB as security for such reimbursement obligations. These amounts and percentages for FES and the Companies are shown as follows:

	FES			OE			CEI		TE		Met-Ed			Penelec
	(In millions)
Amounts
LOCs	$	1,455	*	$	158		$	-	$	-	$	-		$	-
Insurance Policies		456			16			6		4		42			69
Fees
LOCs	0.15% to 0.775 %				1.70	%		-		-		-			-
Insurance Policies		0.15	%		-			-		-		0.16	%		0.16	%
* Includes LOC of $490 million issued for FirstEnergy on behalf of NGC

CEI and TE have unsecured LOCs of approximately $194 million in connection with the sale and leaseback of Beaver Valley Unit 2 for which they are jointly and severally liable. OE has LOCs of $291 million and $134 million in connection with the sale and leaseback of Beaver Valley Unit 2 and Perry Unit 1, respectively. OE entered into a Credit Agreement pursuant to which a standby LOC was issued in support of approximately $236 million of the Beaver Valley Unit 2 LOCs and the issuer of the standby LOC obtained the right to pledge or assign participations in OE's reimbursement obligations under the credit agreement to a trust. The trust then issued and sold trust certificates to institutional investors that were designed to be the credit equivalent of an investment directly in OE.

11.   ASSET RETIREMENT OBLIGATIONS

FES and the Companies have recognized applicable legal obligations under SFAS 143 for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, FES and the Companies have recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47, which was implemented on December 31, 2005.

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The ARO liabilities for FES, OE and TE primarily relate to the nuclear decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities (OE for its leasehold interest in Beaver Valley Unit 2 and Perry and TE for its leasehold interest in Beaver Valley Unit 2). The ARO liabilities for JCP&L, Met-Ed and Penelec primarily relate to the nuclear decommissioning of the TMI-2 nuclear generating facility. FES and the Companies use an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs.

In 2006, FES and OE revised the ARO associated with Perry as a result of revisions to the 2005 decommissioning study. The present value of revisions in the estimated cash flows associated with projected decommissioning costs increased the ARO and corresponding plant asset for Perry by $4 million. The ARO for FES sludge disposal pond located near the Bruce Mansfield Plant was revised in 2006 due to an updated cost study. The present value of revisions in the estimated cash flows associated with projected remediation costs associated with the site decreased the ARO and corresponding plant asset by $6 million. In May 2006, CEI sold its interest in the Ashtabula C plant. As part of the transaction, CEI settled the $6 million ARO that had been established with the adoption of FIN 47.

FES and the Companies maintain nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. The fair value of the decommissioning trust assets as of December 31, 2007 and 2006 were as follows:

	2007		2006
	(In millions)
FES	$	1,333	$	1,238
OE		127		118
TE		67		61
JCP&L		176		164
Met-Ed		287		270
Penelec		138		125

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

Applicable legal obligations as defined under the new standard were identified at FES active and retired generating units and the Companies substation control rooms, service center buildings, line shops and office buildings, identifying asbestos remediation as the primary conditional ARO. As a result of adopting FIN 47 in December 2005, after-tax charges of $8.8 million for FES, $16.3 million for OE, $3.7 million for CEI, $0.3 million for Met-Ed and $0.8 million for Penelec were recorded as the cumulative effect of a change in accounting principle.

The following table describes the changes to the ARO balances during 2007 and 2006.

ARO Reconciliation	FES			OE		CEI			TE		JCP&L		Met-Ed		Penelec
	(In millions)
Balance as of January 1, 2006	$	716		$	83	$	8		$	25	$	80	$	142	$	72
Liabilities incurred		-			-		-			-		-		-		-
Liabilities settled		-			-		(6	)		-		-		-		-
Accretion		46			5		-			2		4		9		5
Revisions in estimated
cashflows		(2	)		-		-			-		-		-		-
Balance as of December 31, 2006		760			88		2			27		84		151		77
Liabilities incurred		-			-		-			-		-		-		-
Liabilities settled		(1	)		-		-			-		-		-		-
Accretion		51			6		-			1		6		10		5
Revisions in estimated
cashflows		-			-		-			-		-		-		-
Balance as of December 31, 2007	$	810		$	94	$	2		$	28	$	90	$	161	$	82

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12.   SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT

FirstEnergy, FES and the Companies are parties 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%

On December 28, 2007, the FERC issued an order authorizing JCP&L, Penn, Met-Ed and Penelec to issue short-term debt securities up to $428 million, $39 million, $300 million and $300 million, respectively, during the period commencing January 1, 2008 through December 31, 2009.

The Companies, with the exception of TE and JCP&L, each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company. The receivables financing borrowing capacity by company are shown in the following table. There were no outstanding borrowings as of December 31, 2007.

Subsidiary Company	Parent Company	Capacity		Annual Facility Fee
		(In millions)
OES Capital, Incorporated	OE	$	170		0.15	%
Centerior Funding Corp.	CEI		200		0.15
Penn Power Funding LLC	Penn		25		0.13
Met-Ed Funding LLC	Met-Ed		80		0.13
Penelec Funding LLC	Penelec		75		0.13
		$	550

The weighted average interest rates on short-term borrowings outstanding as of December 31, 2007 and 2006 were as follows:

	2007			2006
FES		5.23	%		5.62	%
OE		4.80	%		4.04	%
CEI		5.10	%		5.66	%
TE		5.04	%		5.41	%
JCP&L		5.04	%		5.62	%
Met-Ed		5.17	%		5.62	%
Penelec		5.04	%		5.62	%

13.   COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A)      NUCLEAR INSURANCE

The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.8 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. The maximum potential assessment under the industry retrospective rating plan would be $402 million per incident but not more than $60 million in any one year for each incident.

FES and the Companies are also insured under policies for each nuclear plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination costs. FES and the Companies have also obtained approximately $2.0 billion of insurance coverage for replacement power costs. Under these policies, FES and the Companies can be assessed a maximum of approximately $80.9 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.

FES and the Companies intend to maintain insurance against nuclear risks, as described above, as long as it is available. To the extent that replacement power, property damage, decontamination, repair and replacement costs and other such costs arising from a nuclear incident at any of their 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 their insurance policies, or to the extent such insurance becomes unavailable in the future, FES and the Companies would remain at risk for such costs.

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(B)      GUARANTEES AND OTHER ASSURANCES

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1 (see Note 6). FES has unconditionally and irrevocably guaranteed all of FGCOs obligations under each of the leases.  The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trusts undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES lease guaranty.

(C)      ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FES with regard to air and water quality and other environmental matters. The effects of compliance on FES with regard to environmental matters could have a material adverse effect on its 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. FES estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.

FES 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 FES determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

Clean Air Act Compliance

FES 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. FES believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the Clean Air Act. FES has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided 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.

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

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act, alleging violations of air pollution laws at the 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.

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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). FES' Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO2 and 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, FES 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.

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, FGCO, OE and Penn 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.

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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 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.

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

Clean Water Act

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

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

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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, FES and the Companies 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. CEI, TE and JCP&L have recognized liabilities of $1.3 million, $2.5 million and $64.9 million, respectively, as of December 31, 2007.

        (D)      OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages.  JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007.  Proceedings are continuing in the Superior Court. JCP&L is defending this class action but is unable to predict the outcome of this matter.  No liability has been accrued as of December 31, 2007.

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On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. Canada Power System Outage Task Forces final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy's Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energys Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 recommendations to prevent or minimize the scope of future blackouts. Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy's implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

On February 5, 2008, the PUCO entered an order dismissing four separate complaint cases before it relating to the August 14, 2003 power outages. The dismissal was filed by the complainants in accordance with a resolution reached between the FirstEnergy companies and the complainants in those four cases. Two of those cases which were originally filed in Ohio State courts involved individual complainants and were subsequently dismissed for lack of subject matter jurisdiction.  Further appeals were unsuccessful. The other two complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured, seeking reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and AEP, as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003.  (Also relating to the August 14, 2003 power outages, a fifth case, involving another insurance company was voluntarily dismissed by the claimant in April 2007; and a sixth case, involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed by the court.) The order dismissing the PUCO cases, noted above, concludes all pending litigation related to the August 14, 2003 outages and the resolution will not have a material adverse effect on the financial condition, results of operations or cash flows of either FirstEnergy or any of its subsidiaries.

Nuclear Plant Matters

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 NRCs 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 NRCs Office of Enforcement after it completes the key commitments embodied in the NRCs order. FENOCs compliance with these commitments is subject to future NRC review.

Other Legal Matters

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

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

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. 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.

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

14.   FIRSTENERGY INTRA-SYSTEM 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 CEIs and TEs 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 Penns 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 the Company's consolidated results.

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15.   SUPPLEMENTAL GUARANTOR INFORMATION

As discussed in Note 6, on July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO's obligations under each of the leases.  The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trusts undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES lease guaranty.

The consolidating statements of income for the three years ended December 31 2007, consolidating balance sheets as of December 31, 2007  and December 31, 2006 and condensed consolidating statements of cash flows for the three years ended December 31, 2007 for FES (parent), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in the parent’s investment accounts and earnings as if operating lease treatment was achieved (see Note 6). The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING CONDENSED STATEMENTS OF INCOME
For the Year Ended December 31, 2007	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	4,345,790		$	1,982,166		$	1,062,026		$	(3,064,955	)	$	4,325,027
EXPENSES:
Fuel		26,169			942,946			117,895			-			1,087,010
Purchased power from non-affiliates		764,090			-			-			-			764,090
Purchased power from affiliates		3,038,786			186,415			73,844			(3,064,955	)		234,090
Other operating expenses		161,797			352,856			514,389			11,997			1,041,039
Provision for depreciation		2,269			99,741			92,239			(1,337	)		192,912
General taxes		20,953			41,456			24,689			-			87,098
Total expenses		4,014,064			1,623,414			823,056			(3,054,295	)		3,406,239
OPERATING INCOME		331,726			358,752			238,970			(10,660	)		918,788
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		341,978			4,210			14,880			(308,192	)		52,876
Interest expense to affiliates		(1,320	)		(48,536	)		(15,645	)		-			(65,501	)
Interest expense - other		(9,503	)		(59,412	)		(39,458	)		16,174			(92,199	)
Capitalized interest		35			14,369			5,104			-			19,508
Total other income (expense)		331,190			(89,369	)		(35,119	)		(292,018	)		(85,316	)
INCOME BEFORE INCOME TAXES		662,916			269,383			203,851			(302,678	)		833,472
INCOME TAXES		134,052			90,801			77,467			2,288			304,608
NET INCOME	$	528,864		$	178,582		$	126,384		$	(304,966	)	$	528,864

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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING CONDENSED STATEMENTS OF INCOME
For the Year Ended December 31, 2006	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	4,023,752		$	1,767,549		$	1,028,159		$	(2,808,107	)	$	4,011,353
EXPENSES:
Fuel		18,265			983,492			103,900			-			1,105,657
Purchased power from non-affiliates		590,491			-			-			-			590,491
Purchased power from affiliates		2,804,110			180,759			80,239			(2,808,107	)		257,001
Other operating expenses		202,369			271,718			553,477			-			1,027,564
Provision for depreciation		1,779			93,728			83,656			-			179,163
General taxes		12,459			38,781			22,092			-			73,332
Total expenses		3,629,473			1,568,478			843,364			(2,808,107	)		3,233,208
OPERATING INCOME		394,279			199,071			184,795			-			778,145
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		184,267			(596	)		35,571			(164,740	)		54,502
Interest expense to affiliates		(241	)		(117,639	)		(44,793	)		-			(162,673	)
Interest expense - other		(720	)		(9,125	)		(16,623	)		-			(26,468	)
Capitalized interest		1			4,941			6,553			-			11,495
Total other income (expense)		183,307			(122,419	)		(19,292	)		(164,740	)		(123,144	)
INCOME BEFORE INCOME TAXES		577,586			76,652			165,503			(164,740	)		655,001
INCOME TAXES		158,933			17,605			59,810			-			236,348
NET INCOME	$	418,653		$	59,047		$	105,693		$	(164,740	)	$	418,653

135

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING CONDENSED STATEMENTS OF INCOME
For the Year Ended December 31, 2005	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	3,998,410		$	1,567,597		$	671,729		$	(2,270,497	)	$	3,967,239
EXPENSES:
Fuel		37,955			866,583			101,339			-			1,005,877
Purchased power from non-affiliates		957,570			-			-			-			957,570
Purchased power from affiliates		2,516,399			60,207			2,493			(2,270,497	)		308,602
Other operating expenses		276,896			261,646			441,640			-			980,182
Provision for depreciation		1,597			95,237			80,397			-			177,231
General taxes		11,640			37,594			18,068			-			67,302
Total expenses		3,802,057			1,321,267			643,937			(2,270,497	)		3,496,764
OPERATING INCOME		196,353			246,330			27,792			-			470,475
OTHER INCOME (EXPENSE):
Investment income		4,462			6,964			67,361			-			78,787
Miscellaneous income (expense), including
net income from equity investees		79,371			(2,658	)		(28,000	)		(82,856	)		(34,143	)
Interest expense to affiliates		(4,677	)		(102,580	)		(77,060	)		-			(184,317	)
Interest expense - other		(204	)		(2,220	)		(9,614	)		-			(12,038	)
Capitalized interest		82			3,180			11,033			-			14,295
Total other income (expense)		79,034			(97,314	)		(36,280	)		(82,856	)		(137,416	)
INCOME (LOSS) FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES		275,387			149,016			(8,488	)		(82,856	)		333,059
INCOME TAXES (BENEFIT)		75,630			50,739			(1,870	)		-			124,499
INCOME (LOSS) FROM CONTINUING OPERATIONS		199,757			98,277			(6,618	)		(82,856	)		208,560
Discontinued operations (net of income taxes of $3,761,000)		5,410			-			-			-			5,410
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE		205,167			98,277			(6,618	)		(82,856	)		213,970
Cumulative effect of a change in accounting principle (net
of income tax benefit of $5,507,000)		-			(8,803	)		-			-			(8,803	)
NET INCOME (LOSS)	$	205,167		$	89,474		$	(6,618	)	$	(82,856	)	$	205,167

136

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
As of December 31, 2007	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	-	$	-	$	-		$	2
Receivables-
Customers		133,846		-		-		-			133,846
Associated companies		327,715		237,202		98,238		(286,656	)		376,499
Other		2,845		978		-		-			3,823
Notes receivable from associated companies		23,772		-		69,012		-			92,784
Materials and supplies, at average cost		195		215,986		210,834		-			427,015
Prepayments and other		67,981		21,605		2,754		-			92,340
		556,356		475,771		380,838		(286,656	)		1,126,309
PROPERTY, PLANT AND EQUIPMENT:
In service		25,513		5,065,373		3,595,964		(392,082	)		8,294,768
Less - Accumulated provision for depreciation		7,503		2,553,554		1,497,712		(166,756	)		3,892,013
		18,010		2,511,819		2,098,252		(225,326	)		4,402,755
Construction work in progress		1,176		571,672		188,853		-			761,701
		19,186		3,083,491		2,287,105		(225,326	)		5,164,456
INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,332,913		-			1,332,913
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		2,516,838		-		-		(2,516,838	)		-
Other		2,732		37,071		201		-			40,004
		2,519,570		37,071		1,396,014		(2,516,838	)		1,435,817
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		16,978		522,216		-		(262,271	)		276,923
Lease assignment receivable from associated companies		-		215,258		-		-			215,258
Goodwill		24,248		-		-		-			24,248
Property taxes		-		25,007		22,767		-			47,774
Pension asset		3,217		13,506		-		-			16,723
Unamortized sale and leaseback costs		-		27,597		-		43,206			70,803
Other		22,956		52,971		6,159		(38,133	)		43,953
		67,399		856,555		28,926		(257,198	)		695,682
TOTAL ASSETS	$	3,162,511	$	4,452,888	$	4,092,883	$	(3,286,018	)	$	8,422,264
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	-	$	596,827	$	861,265	$	(16,896	)	$	1,441,196
Short-term borrowings-
Associated companies		-		238,786		25,278					264,064
Other		300,000		-		-		-			300,000
Accounts payable-
Associated companies		287,029		175,965		268,926		(286,656	)		445,264
Other		56,194		120,927		-		-			177,121
Accrued taxes		18,831		125,227		28,229		(836	)		171,451
Other		57,705		131,404		11,972		36,725			237,806
		719,759		1,389,136		1,195,670		(267,663	)		3,036,902
CAPITALIZATION:
Common stockholder's equity		2,414,231		951,542		1,562,069		(2,513,611	)		2,414,231
Long-term debt		-		1,597,028		242,400		(1,305,716	)		533,712
		2,414,231		2,548,570		1,804,469		(3,819,327	)		2,947,943
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,060,119			1,060,119
Accumulated deferred income taxes		-		-		259,147		(259,147	)		-
Accumulated deferred investment tax credits		-		36,054		25,062		-			61,116
Asset retirement obligations		-		24,346		785,768		-			810,114
Retirement benefits		8,721		54,415		-		-			63,136
Property taxes		-		25,328		22,767		-			48,095
Lease market valuation liability		-		353,210		-		-			353,210
Other		19,800		21,829		-		-			41,629
		28,521		515,182		1,092,744		800,972			2,437,419
TOTAL LIABILITIES AND CAPITALIZATION	$	3,162,511	$	4,452,888	$	4,092,883	$	(3,286,018	)	$	8,422,264

137

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

138

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2007	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES	$	(18,017	)	$	55,172		$	263,468		$	(6,306	)	$	294,317
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt		-			1,576,629			179,500			(1,328,919	)		427,210
Equity contribution from parent		700,000			700,000			-			(700,000	)		700,000
Short-term borrowings, net		300,000			-			25,278			(325,278	)		-
Redemptions and repayments-
Common stock		(600,000	)		-			-			-			(600,000	)
Long-term debt		-			(1,052,121	)		(495,795	)		6,306			(1,541,610	)
Short-term borrowings, net		-			(783,599	)		-			325,278			(458,321	)
Common stock dividend payments		(117,000	)		-			-			-			(117,000	)
Net cash provided from (used for) financing activities		283,000			440,909			(291,017	)		(2,022,613	)		(1,589,721	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(10,603	)		(502,311	)		(225,795	)		-			(738,709	)
Proceeds from asset sales		-			12,990			-			-			12,990
Proceeds from sale and leaseback transaction		-			-			-			1,328,919			1,328,919
Sales of investment securities held in trusts		-			-			655,541			-			655,541
Purchases of investment securities held in trusts		-			-			(697,763	)		-			(697,763	)
Loans to associated companies		441,966			-			292,896			-			734,862
Investment in subsidiary		(700,000	)		-			-			700,000			-
		3,654			(6,760	)		2,670			-			(436	)
Net cash provided from (used for) investing activities		(264,983	)		(496,081	)		27,549			2,028,919			1,295,404
Net change in cash and cash equivalents		-			-			-			-			-
Cash and cash equivalents at beginning of year		2			-			-			-			2
Cash and cash equivalents at end of year	$	2		$	-		$	-		$	-		$	2

139

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2006	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
NET CASH PROVIDED FROM OPERATING ACTIVITIES	$	250,518		$	150,510		$	470,578		$	(12,765	)	$	858,841
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt		-			565,326			591,515			-			1,156,841
Short-term borrowings, net		-			46,402			-			-			46,402
Redemptions and repayments-
Long-term debt		-			(543,064	)		(594,676	)		-			(1,137,740	)
Dividend payments
Common stock		(8,454	)		-			(12,765	)		12,765			(8,454	)
Net cash provided from (used for) financing activities		(8,454	)		68,664			(15,926	)		12,765			57,049
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(948	)		(212,867	)		(363,472	)		-			(577,287	)
Proceeds from asset sales		-			34,215			-			-			34,215
Sales of investment securities held in trusts		-			-			1,066,271			-			1,066,271
Purchases of investment securities held in trusts		-			-			(1,066,271	)		-			(1,066,271	)
Loans to associated companies		(242,597	)		-			(90,433	)		-			(333,030	)
Other		1,481			(40,522	)		(747	)		-			(39,788	)
Net cash used for investing activities		(242,064	)		(219,174	)		(454,652	)		-			(915,890	)
Net change in cash and cash equivalents		-			-			-			-			-
Cash and cash equivalents at beginning of year		2			-			-			-			2
Cash and cash equivalents at end of year	$	2		$	-		$	-		$	-		$	2

140

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2005	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES	$	475,191		$	243,683		$	(71,526	)	$	-		$	647,348
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Short-term borrowings, net		-			130,876			-			(130,876	)		-
Equity contribution from parent		262,200			-			459,498			(459,498	)		262,200
Redemptions and repayments-
Short-term borrowings, net		(245,215	)		-			-			130,876			(114,339	)
Return of capital to parent		-			(197,298	)					197,298			-
Net cash provided from (used for) financing activities		16,985			(66,422	)		459,498			(262,200	)		147,861
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(1,340	)		(186,176	)		(224,044	)		-			(411,560	)
Proceeds from asset sales		15,000			43,087			-			-			58,087
Sales of investment securities held in trusts		-			-			1,097,276			-			1,097,276
Purchases of investment securities held in trusts		-			-			(1,186,381	)		-			(1,186,381	)
Loans to associated companies		(217,426	)		-			(74,200	)		-			(291,626	)
Return of capital from subsidiary		197,298			-			-			(197,298	)		-
Investment in subsidiary		(459,498	)		-			-			459,498			-
Other		(26,211	)		(34,199	)		(623	)		-			(61,033	)
Net cash used for investing activities		(492,177	)		(177,288	)		(387,972	)		262,200			(795,237	)
Net change in cash and cash equivalents		(1	)		(27	)		-			-			(28	)
Cash and cash equivalents at beginning of year		3			27			-			-			30
Cash and cash equivalents at end of year	$	2		$	-		$	-		$	-		$	2

141

16.   NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 157 - "Fair Value Measurements"

In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value, which focuses on an exit price rather than entry price; (2) the methods used to measure fair value, such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement and its related FSPs are effective for fiscal years beginning after November 15, 2007, and interim periods within those years. Under FSP FAS 157-2, FES and the Companies have elected to defer the election of SFAS 157 for financial assets and financial liabilities measured at fair value on a non-recurring basis for one year.  FES and the Companies have evaluated the impact of this Statement and its FSPs, FAS 157-2 and FSP FAS 157-1, which excludes SFAS 13, Accounting for Leases, and its related pronouncements from the scope of SFAS 157, and are not expecting there to be a material effect on their financial statements. The majority of the FES and the Companies fair value measurements will be disclosed as level 1 or level 2 in the fair value hierarchy.

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

In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and financial liabilities at fair value. This Statement attempts to provide additional information that will help investors and other users of financial statements to more easily understand the effect of a company's choice to use fair value on its earnings. The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157 and SFAS 107. This Statement is effective for fiscal years beginning after November 15, 2007, and interim periods within those years. FES and the Companies have analyzed their financial assets and financial liabilities within the scope of this Statement and no fair value elections were made as of January 1, 2008.

SFAS 141(R) - "Business Combinations"

In December 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will impact business combinations entered into by FES and the Companies that close after January 1, 2009 and is not expected to have a material impact on FES and the Companies financial statements.

SFAS 160 - "Noncontrolling Interests in Consolidated Financial Statements an Amendment of ARB No. 51"

In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FES and the Companies financial statements.

FSP FIN 39-1 - "Amendment of FASB Interpretation No. 39"

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

142

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

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

143

17.   SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)

The following summarizes certain consolidated operating results by quarter for 2007 and 2006.

						Income (Loss)
						From Continuing
				Operating		Operations
				Income		Before		Income		Net
Three Months Ended		Revenues		(Loss)		Income Taxes		Taxes		Income
		(In millions)
FES
	March 31, 2007	$	1018.2	$	188.7	$	164.9	$	62.4	$	102.5
	March 31, 2006		956.5		89.7		56.6		19.4		37.2
	June 30, 2007		1068.7		263.8		239.1		87.7		151.4
	June 30, 2006		994.0		192.2		157.6		59.0		98.6
	September 30,2007		1170.1		272.1		248.4		93.7		154.8
	September 30,2006		1109.6		301.6		282.4		106.2		176.2
	December 31, 2007		1068.0		194.2		181.1		60.8		120.2
	December 31, 2006		951.2		194.6		158.4		51.7		106.7
OE
	March 31, 2007	$	625.6	$	65.4	$	71.5	$	17.4	$	54.0
	March 31, 2006		586.2		86.8		102.1		38.3		63.8
	June 30, 2007		596.8		70.8		73.2		27.6		45.7
	June 30, 2006		573.1		79.3		94.2		35.0		59.2
	September 30,2007		668.8		82.0		82.3		34.1		48.2
	September 30,2006		673.7		50.8		61.4		17.9		43.5
	December 31, 2007		600.3		73.1		71.4		22.2		49.3
	December 31, 2006		594.5		74.2		77.2		32.1		45.1
CEI
	March 31, 2007	$	440.8	$	115.5	$	98.3	$	34.8	$	63.5
	March 31, 2006		407.8		124.3		116.9		44.5		72.4
	June 30, 2007		449.5		128.6		111.0		42.1		68.9
	June 30, 2006		432.4		152.3		148.8		57.7		91.1
	September 30,2007		529.1		154.4		133.3		54.6		78.7
	September 30,2006		515.9		140.3		131.9		48.5		83.4
	December 31, 2007		403.5		113.7		97.2		31.9		65.3
	December 31, 2006		413.6		109.7		97.1		38.0		59.1
TE
	March 31, 2007	$	240.5	$	40.3	$	37.0	$	11.1	$	25.9
	March 31, 2006		218.0		43.2		46.2		17.2		29.0
	June 30, 2007		240.3		40.8		37.3		15.4		21.9
	June 30, 2006		225.6		49.3		52.3		19.9		32.4
	September 30,2007		269.7		47.5		43.5		18.4		25.1
	September 30,2006		262.8		43.7		46.8		17.7		29.1
	December 31, 2007		213.4		28.8		27.2		8.8		18.3
	December 31, 2006		221.6		14.3		13.9		5.1		8.8

144

							Income (Loss)
							From Continuing
				Operating			Operations					Net
				Income			Before			Income		Income
Three Months Ended		Revenues		(Loss)			Income Taxes			Taxes		(Loss)
		(In millions)
Met-Ed
	March 31, 2007	$	370.3	$	57.9		$	55.2		$	23.6	$	31.6
	March 31, 2006		311.2		28.7			29.1			11.2		17.9
	June 30, 2007		361.7		38.0			34.3			14.8		19.5
	June 30, 2006		282.2		70.6			69.6			29.5		40.1
	September 30,2007		410.6		43.8			39.4			14.7		24.7
	September 30,2006		356.2		42.0			39.6			14.6		25.0
	December 31, 2007		367.9		45.3			34.8			15.2		19.7
	December 31, 2006 *		293.5		(300.2	)		(301.2	)		22.0		(323.2	)
Penelec
	March 31, 2007	$	355.9	$	65.7		$	56.0		$	24.3	$	31.7
	March 31, 2006		291.8		45.0			37.1			14.0		23.1
	June 30, 2007		331.4		44.5			33.8			14.4		19.5
	June 30, 2006		265.0		39.6			30.0			14.5		15.5
	September 30,2007		353.4		45.8			33.4			10.4		23.0
	September 30,2006		303.4		38.1			28.8			10.7		18.1
	December 31, 2007		361.3		48.4			33.8			14.9		18.7
	December 31, 2006		288.3		53.1			44.8			17.3		27.5
JCP&L
	March 31, 2007	$	683.7	$	89.9		$	71.0		$	32.7	$	38.3
	March 31, 2006		575.8		73.5			57.3			23.6		33.7
	June 30, 2007		780.0		110.2			89.5			39.7		49.8
	June 30, 2006		611.5		95.7			78.9			38.6		40.3
	September 30,2007		1033.2		143.3			122.1			46.3		75.8
	September 30,2006		911.1		156.0			137.7			58.3		79.4
	December 31, 2007		746.9		76.4			52.6			30.4		22.2
	December 31, 2006		569.3		78.4			63.4			26.2		37.2
*	Met-Ed recognized a $355 million non-cash goodwill impairment charge in the fourth quarter of 2006.

145

EX-12.2

											EXHIBIT 12.2
FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
		Year Ended December 31,
			2003		2004		2005		2006		2007
		(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	152,387	$	322,239	$	208,560	$	418,653	$	528,864
Interest and other charges, before reduction for amounts capitalized
	and deferred		170,107		181,620		196,355		189,141		157,700
Provision for income taxes			100,759		229,575		124,499		236,348		304,608
Interest element of rentals charged to income (a)			1,060		1,056		1,434		1,797		24,669
	Earnings as defined	$	424,313	$	734,490	$	530,848	$	845,939	$	1,015,841
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred		$	170,107	$	181,620	$	196,355	$	189,141	$	157,700
Interest element of rentals charged to income (a)			1,060		1,056		1,434		1,797		24,669
	Fixed charges as defined	$	171,167	$	182,676	$	197,789	$	190,938	$	182,369
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES			2.48		4.02		2.68		4.43		5.57
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

EX-3.1

AMENDED AND RESTATED

ARTICLES OF INCORPORATION

OF

OHIO EDISON COMPANY

Charter Number 260438

(effective December 18, 2007)

FIRST: The name of the corporation is OHIO EDISON COMPANY (hereinafter referred to as the “Corporation”).

SECOND: The place in the State of Ohio where the principal office is located is in the City of Akron, Summit County.

THIRD: The purposes of the Corporation are as follows:

A. To generate, produce, acquire, transmit, distribute, furnish, sell, and supply electricity to public and private consumers; and

B. To engage in any other lawful act or activity for which a corporation may be formed under the Ohio General Corporation Law, Chapter 1701 of the Ohio Revised Code.

FOURTH: The aggregate number of shares which the Corporation is authorized to issue shall be one hundred ninety-seven million (197,000,000) shares, classified as follows:

A. Common Stock, one hundred seventy-five million (175,000,000) shares, with no par value;

B. Preferred Stock, six million (6,000,000) shares, with a par value of $100 per share;

C. Class A Preferred Stock, eight million (8,000,000) shares, with a par value of Twenty-five Dollars ($25) per share; and

D. Preference Stock, eight million (8,000,000) shares, with no par value.

FIFTH: The Board of Directors may adopt an amendment to these Articles of Incorporation determining, in whole or in part, the express terms, within the limits set forth in these Articles of Incorporation or the Ohio General Corporation Law, of any class of shares before the issuance of any shares of that class, or of one or more series within a class before the issuance of shares of that series; including, without limitation, division of shares into classes or into series within any class or classes, determination of the designation and the number of shares of any class or series, and the determination of the relative voting rights, preferences, limitations, rights to dividends, conversion rights, redemption rights, stated value, and other special rights of the shares of any class or series.

SIXTH: The Corporation may wind up its affairs and dissolve pursuant to a resolution adopted, at a meeting of shareholders called for such purpose, by the affirmative vote of the holders of record of shares entitling them to exercise the majority of the voting power of the Corporation.

SEVENTH: The Corporation may purchase its shares, regardless of class, from time to time, to such extent, in such manner, and upon such terms as its Board of Directors shall determine; provided, however, that the Corporation shall not purchase any of its shares if, after such purchase, its assets would be less than its liabilities plus stated capital.

EIGHTH: The shareholders shall have no right to vote cumulatively in the election of Directors.

NINTH: Sections 1701.70(B)(6) through (10) of the Ohio Revised Code shall apply to the Corporation. Thus, as provided in ORC §§ 1701.70(B)(6) through (10) and subject to the terms thereof, the Board of Directors may adopt amendments to these Articles of Incorporation:  (a) changing the name of the Corporation; (b) changing the location of the principal office of the Corporation; (c) increasing proportionately the authorized number of shares of a class of shares for the purpose of a dividend or distribution to be paid in shares of that class; (d) changing shares of a class of shares into a greater number of shares of that class and increasing proportionately the authorized number of shares of that class for the purpose of a stock split; or (e) decreasing the par value of shares of a class of shares to the extent necessary to prevent an increase in the aggregate par value of the shares of that class in the event of and concurrently with the adoption of an amendment as described in clauses (c) and (d) above for the purpose of a share dividend or stock split. [Ohio Rev. Code §1701.70(D)]

TENTH: These Amended and Restated Articles of Incorporation take the place of and supersede the existing articles of incorporation as previously amended.

EX-3.2

AMENDED AND RESTATED

CODE OF REGULATIONS

OF

OHIO EDISON COMPANY

December 14, 2007

MEETINGS OF SHAREHOLDERS

Section 1.    Annual Meetings.

The annual meeting of shareholders shall be held on such date and at such time as the Board of Directors may determine each year.  Such meetings may be held within or without the State of Ohio at such time and place as the Directors may determine.  The Directors may determine that the meeting shall not be held at any physical place, but instead may be held solely by means of communications equipment as authorized by Section 9 below.

Section 2.    Special Meetings.

Special meetings of the shareholders may be called at any time by (i) the Chairman of the Board, (ii) the President, (iii) the Directors, by action at a meeting or a majority of the Directors acting without a meeting, or (iv) the holders of 25% or more of the outstanding shares entitled to vote thereat.  Such meetings may be held within or without the State of Ohio at such time and place as may be specified in the notice thereof.

Section 3.    Notice of Meetings.

Written notice stating the time, place, if any, and purposes of a meeting of the shareholders, and the means, if any, by which shareholders can be present and vote at the meeting through the use of communications equipment shall be given by personal delivery, or by mail, facsimile transmission, overnight delivery service, or any other means of communication authorized by the shareholder to whom the notice is given, not less than seven nor more than sixty days before the date of the meeting.  Such notice may be given by or at the direction of the Chairman of the Board, the President or the Corporate Secretary.  Notices sent by mail shall be sent postage prepaid and shall be addressed to each shareholder at his address as it appears upon the records of the Corporation.  Notice by mail shall be deemed to be given at the time when the notice is deposited in the mail, notice by personal delivery or by overnight delivery service shall be deemed to be given when received, and notice by facsimile, or other electronic communications shall be deemed to be given at the time when confirmation of successful transmission is received.  Any shareholder may waive in writing notice of any meeting, either before or after the holding of such meeting, and by attending any meeting without protesting the lack of proper notice, shall be deemed to have waived notice thereof.

Section 4.    Business Transacted at Meetings.

Business transacted at any meeting of shareholders shall be for the purposes stated in the notice.

Section 5.    Quorum and Adjournments.

The holders of a majority of the stock issued and outstanding and entitled to vote thereat, present in person or represented by proxy, shall constitute a quorum at all meetings of the shareholders for the transaction of business except as otherwise provided by statute or by the Articles of Incorporation.  If, however, such quorum shall not be present or represented at any meeting of the shareholders, the shareholders entitled to vote thereat, present in person or represented by proxy, shall have power to adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum shall be present or represented.  At such adjourned meeting at which a quorum shall be present or represented, any business may be transacted which might have been transacted at the meeting as originally notified.

Section 6.    Required Vote; Inspectors.

(a)            When a quorum is present or represented at any meeting, the vote of the holders of a majority of the stock having voting power present in person or represented by proxy shall decide any question brought before such meeting, unless the question is one upon which by express provision of the statutes or of the Articles of Incorporation a different vote is required in which case such express provision shall govern and control the decision of such question.

(b)            Inspectors of election may be appointed to act at any meeting of shareholders in accordance with Ohio law.

Section 7.    Voting Power of Shareholders.

Every shareholder of record of the Corporation shall be entitled at each meeting of shareholders to one vote for each share of stock held by such shareholder according to the books of the Corporation as of the date of such vote or, if a record date is set by the Board of Directors, as of such record date.

Section 8.    Voting by Proxy.

At any meeting of the shareholders, any shareholder may be represented and vote by a proxy or proxies appointed by an instrument in writing or by any other form of verifiable communication, including any form of electronic or other communications, to the full extent legally permitted (now or hereafter).  In the event that any such instrument shall designate two or more persons to act as proxies, a majority of such persons present at the meeting, or, if only one shall be present, then that one shall have and may exercise all of the powers conferred by such instrument upon all of the persons so designated unless the instrument shall otherwise provide.  No such proxy shall be valid after the expiration of eleven (11) months from the date of its execution, unless coupled with an interest, or unless the person executing it specifies therein the length of time for which it is to continue in force.  Subject to the above, any proxy duly executed is not revoked and continues in full force and effect until an instrument or verifiable communication revoking it or a duly executed proxy bearing a later date is filed with the Corporate Secretary of the Corporation.

2

Section 9.      Participation by Shareholders Through Communications Equipment.

If authorized by the Directors, the shareholders and proxyholders who are not physically present at a meeting of shareholders may attend a meeting of shareholders by use of communications equipment that enables the shareholder or proxyholder an opportunity to participate in the meeting and to vote on matters submitted to the shareholders, including an opportunity to read or hear the proceedings of the meeting and to speak or otherwise participate in the proceedings contemporaneously with those physically present.

Section 10.   Action by Shareholders Without a Meeting.

Any action which may be taken by the vote of the shareholders at a meeting may be taken without a meeting if authorized by a writing or writings signed by all of the holders of shares who would be entitled to notice of a meeting for such purpose.  Such written consent shall be filed with or entered upon the records of the Corporation.

DIRECTORS

Section 11.   Authority of Directors.

The business of the Corporation shall be managed by its Board of Directors, which may exercise all such powers of the Corporation and do all such lawful acts and things as are not by statute, the Articles of Incorporation, or these Regulations directed or required to be exercised or done by the shareholders.

Section 12.   Number; Qualifications.

The number of Directors shall be not less than three (3) and not more than five (5) (plus any Directors separately elected by the holders of any class of stock other than the Common Stock as provided in the Articles of Incorporation as amended from time to time).  The number of Directors may be determined (a) by the vote of the holders of a majority of the shares entitled to vote thereon at any annual meeting or special meeting called for the purpose of electing Directors or (b) by action of the Board of Directors at a meeting by the vote of a majority of the Directors in office at the time or in a writing signed by all the Directors in office at the time.  When so fixed, such number shall continue to be the authorized number of Directors until changed by the shareholders or Directors in the manner described above.  Any increase in the number of Directors shall be deemed to create a vacancy or vacancies which may be filled as provided in Section 15.  A reduction in the number of Directors shall not be applied to remove any Director from office prior to the expiration of his term.  Directors need not be shareholders of the Corporation.

3

Section 13.   Election of Directors.

At each meeting of the shareholders for the election of Directors, the persons receiving the greatest number of votes shall be the Directors.  Such elections shall be by ballot whenever requested by any person entitled to vote at such meeting; but unless so requested, such election may be conducted in any way approved at such meeting.

Section 14.   Term of Office; Removal; Resignations.

(a)            Directors shall hold office until the annual meeting of the shareholders next following their election and until their respective successors are elected, or until their earlier resignation, death or removal from office.

(b)            Any Director or the entire Board of Directors may be removed upon the affirmative vote of the holders of a majority of the voting power of the Corporation.

(c)            Any Director may resign at any time by giving written notice of his resignation to the President or Corporate Secretary. Any resignation will be effective upon actual receipt by such person or, if later, as of the date and time specified in such written notice.

Section 15.   Vacancies.

Vacancies, including those caused by an increase in the number of Directors, may be filled by a majority of the remaining Directors though less than a quorum.  When one or more Directors shall give notice of his or their resignation to the Board, effective at a future date, the Board shall have the power to fill such vacancy or vacancies to take effect when such resignation or resignations shall become effective, each Director so appointed to hold office during the remainder of the term of office of the resigning Director or Directors.  Whenever any vacancy shall occur among the Directors, the remaining Directors shall constitute the Directors of the Corporation until such vacancy is filled or until the number of Directors is changed as in Section 12 hereof.

MEETINGS OF THE BOARD OF DIRECTORS

Section 16.   Organizational Meeting.

Immediately after each annual meeting of the shareholders at which Directors are elected, or each special meeting held in lieu thereof, the newly elected Directors, if a quorum thereof is present, shall hold an organizational meeting at the same place or at such other time and place as may be fixed by the shareholders at such meeting, for the purpose of electing officers and transacting any other business.  Notice of such meeting need not be given.  If for any reason such organizational meeting is not held at such time, a special meeting of the Directors for such purpose shall be held as soon thereafter as practicable.

4

Section 17.   Special Meetings.

Special meetings of the Directors may be held at any time within or without the State of Ohio upon call by the Chairman of the Board, the President, or the Corporate Secretary upon the written request of two Directors.

Notice of the place, if any, and time of each meeting of the Directors shall be given to each Director either by personal delivery or by mail, facsimile transmission, overnight delivery service, or any other means of communication authorized by the Director, at least two days before the meeting. The notice need not specify the purposes of the meeting.  Notices sent by mail shall be sent postage prepaid and shall be addressed to each Director at his address as it appears upon the records of the Corporation.  Notice by mail shall be deemed to be given at the time when the notice is deposited in the mail, notice by personal delivery or by overnight delivery service shall be deemed to be given when received, and notice by facsimile, or other electronic communications shall be deemed to be given at the time when confirmation of successful transmission is received.  Such notice may be waived in writing by Directors either before or after the meeting, and such written waivers shall be filed with or entered upon the records of the meeting.  The attendance of any Director at any such meeting without protesting the lack of proper notice, prior to or at the commencement of the meeting, shall be deemed to be a waiver by the Director of notice of the meeting.  Unless otherwise limited in the notice thereof, any business may be transacted at any organizational, regular or special meeting.

Section 18.   Quorum and Adjournments; Participation by Communications Equipment.

(a)            A majority of the Directors, at a meeting duly called and held, shall be necessary to constitute a quorum for the transaction of business and the act of a majority of the Directors present at any meeting at which a quorum is present shall be the act of the Board of Directors, except as may be otherwise specifically provided by statute or by the Articles of Incorporation. Any action required or permitted to be taken at a meeting of the Directors may be taken without a meeting if a consent in writing, setting forth the action so taken, shall be signed by all of the Directors entitled to vote with respect to the subject matter thereof. Any meeting duly called, whether or not a quorum is present, may, by vote of a majority of the Directors present, be adjourned from time to time and place to place within or without the State of Ohio, in which case no further notice of the adjourned meeting need be given.

(b)            Meetings of the Board of Directors or of any committee of the Board of Directors may be held through any means of communications equipment if all persons participating can hear each other, and such participation will constitute presence in person at such meeting.

Section 19.   Committees.

The Board of Directors may, by resolution passed by a majority of the Directors, designate one or more committees, each committee to consist of one or more of the Directors of the Corporation, which, to the extent provided in the resolution, shall have and may exercise the powers of the Board of Directors in the management of the business and affairs of the Corporation.  Such committee or committees shall have such name or names as may be determined from time to time by resolution adopted by the Board of Directors.  The committees shall keep regular minutes of their proceedings and report the same to the Board when required.

5

Section 20.   Compensation.

The Directors may be paid their expenses, if any, for attendance at each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors.  The sums may be different for different Directors, and the sum shall be established by resolution of the Board of Directors and may be changed from time to time by resolution.  No such payment shall preclude any Director from serving the Corporation in any other capacity and receiving compensation therefor.  Members of special or standing committees may be allowed like compensation for attending committee meetings.

Section 21.   Action by Directors Without a Meeting.

Any action required or permitted to be taken at a meeting of the Board of Directors or any committee of the Board of Directors may be taken without a meeting if, prior or subsequent to such action, all members of the Board of Directors or of such committee, as the case may be, consent thereto in writing and such written consents are filed with the Corporate Secretary of the Corporation.

EXECUTIVE COMMITTEE

Section 22.   Executive Committee.

The Board of Directors at any time may elect from its members an Executive Committee which shall consist of not less than three (3) members.  Each member of such Committee shall hold office during the pleasure of the Board and may be removed by a majority vote of the whole Board at any time with or without cause.  Vacancies occurring in the Committee may be filled by the Board.  The Committee shall prescribe its own rules for calling and holding meetings, and for transacting business, subject, however, to any rules prescribed by the Board of Directors, and the Committee shall keep minutes of its actions.  Action by the Committee may be taken at meetings thereof attended by not less than a majority thereof, or without a meeting by instrument in writing signed by not less than a majority of the members.  Except as the Committee’s powers and duties may be limited or otherwise prescribed by the Board of Directors, the Committee, during the intervals between the meetings of the Board, shall possess and may exercise all of the powers and authority of the Board of Directors, however conferred, provided, however, that the Committee shall not be empowered to elect the officers (other than Assistant Secretaries and Assistant Treasurers) or to fill vacancies in the Board of Directors or in the Executive Committee.  Subject to such exceptions, persons dealing with the Corporation shall be entitled to rely upon any action of the Committee with the same force and effect as though such action had been taken by the Board of Directors.

6

OFFICERS

Section 23.   Generally.

The Corporation may have a Chairman, elected by the Directors from among their number, and shall have a President, a Corporate Secretary and a Treasurer.   The Corporation may also have one or more Vice Chairmen, Vice Presidents, Senior Vice Presidents and such other officers and assistant officers as the Board of Directors may deem appropriate.  If the Board of Directors so desires, it may elect a Chief Executive Officer to manage the affairs of the Corporation, subject to the direction and control of the Board of Directors.  All of the officers shall be elected by the Board of Directors.  Notwithstanding the foregoing, by specific action, the Board of Directors may authorize the Chairman or the President to appoint any person to any office other than Chairman, President, Corporate Secretary, or Treasurer.  Any number of offices may be held by the same person, and no two offices must be held by the same person.  Any of the offices may be left vacant from time to time as the Board of Directors may determine.  In case of the absence or disability of any officer of the Corporation or for any other reason deemed sufficient by a majority of the Board of Directors, the Board of Directors may delegate the absent or disabled officer's powers or duties to any other officer or to any Director.

Section 24.   Authority and Duties of Officers.  

The officers of the Corporation shall have such authority and shall perform such duties as are customarily incident to their respective offices, or as may be specified from time to time by the Board of Directors, the Chairman or the President regardless of whether such authority and duties are customarily incident to such office.

Section 25.    Compensation.  

The compensation of all officers and agents of the Corporation who are also members of the Board of Directors of the Corporation will be fixed by the Board of Directors or by a committee of the Board of Directors.  The Board of Directors may fix, or delegate the power to fix, the compensation of the other officers and agents of the Corporation to the Chief Executive Officer or any other officer of the Corporation.

Section 26.   Succession.  

The officers of the Corporation will hold office until their successors are elected.  Any officer may be removed at any time by the affirmative vote of a majority of the whole Board.  Any vacancy occurring in any office of the Corporation may be filled by the Board of Directors or by the Chairman or President as provided in Section 23.

7

Section 27.   Delegation of Duties.

The Directors are authorized to delegate the duties of any officers to any other officer and generally to control the action of the officers and to require the performance of duties in addition to those mentioned herein.

SHARES CERTIFICATES

Section 28.   Transfer and Registration of Certificates

The Board of Directors shall have authority to make such rules and regulations, not inconsistent with law, the Articles, or these Regulations, as it deems expedient concerning the issuance, transfer, and registration of certificates for shares and the shares represented thereby and may appoint transfer agents and registrars thereof.  The Directors may provide by resolution that some or all of any or all classes and series of shares shall be uncertificated shares, subject to any disclosure obligations therefore under Section 1701.24 of the Ohio Revised Code, and provided that any then-outstanding shares of that class or series represented by a certificate shall not become uncertificated shares until the certificate is surrendered to the Corporation.

Section 29.   Substituted Certificates

Any person claiming that a certificate for shares has been lost, stolen, or destroyed shall make an affidavit or affirmation of that fact and, if required, shall give the Corporation (and its registrar or registrars and its transfer agent or agents, if any) a bond of indemnity, in such form and with one (1) or more sureties satisfactory to the Board, and if required by the Board of Directors, shall advertise the same in such manner as the Board of Directors may require, whereupon a new certificate may be executed and delivered of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, or destroyed.

8

RECORD DATES AND CLOSING OF TRANSFER BOOKS

Section 30.   Record Dates and Closing of Transfer Books.

The Board of Directors may fix a time not exceeding sixty (60) days preceding the date of any meeting of shareholders or the date fixed for the payment of any dividend or distribution or the date for the allotment of rights as the record date for the determination of the shareholders entitled to notice of or to vote at any such meeting or entitled to receive payment of any such dividend, distribution or allotment of rights, and in such case only shareholders of record on the date so fixed shall be entitled to notice of or to vote at such meeting or to receive payment of such dividend, distribution or allotment of rights, as the case may be, notwithstanding any transfer of any shares on the books of the Corporation after any record date so fixed.  The Board of Directors may close the books of the Corporation against transfers of shares during the whole or any part of the period between such record date and the date of the event in respect for which such record date was fixed.

REGISTERED SHAREHOLDERS

Section 31.   Recognition of Record Ownership.

The Corporation shall be entitled to recognize the exclusive right of a person registered on its books as the owner of shares to receive dividends, and to vote as such owner, and to hold liable for calls and assessments a person registered on its books as the owner of shares, and shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of Ohio.

GENERAL PROVISIONS

DIVIDENDS

Section 32.   Payment of Dividends.

The Board of Directors may declare dividends upon the capital stock of the Corporation, subject to the provisions of the Articles of Incorporation, if any, at any regular or special meeting pursuant to law.  Dividends may be paid in cash, in property or in shares of the capital stock, subject to the provisions of the Articles of Incorporation.  Before payment of any dividend, there may be set aside out of any funds of the Corporation available for dividends such sum or sums as the Directors from time to time, in their absolute discretion, think proper as a reserve or reserves to meet contingencies, or for equalizing dividends, or for repairing or maintaining any property of the Corporation, or for such other purpose as the Directors shall think conducive to the interest of the Corporation and the Directors may modify or abolish any such reserves in the manner in which it was created.

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FISCAL YEAR

Section 33.   Fiscal Year.

The fiscal year of the Corporation shall be fixed by resolution of the Board of Directors.

SEAL

Section 34.   Corporate Seal.

The Directors may adopt a corporate seal of the Corporation which shall be of such design, and shall contain such words, as may be prescribed by the Directors.  Failure to affix any such corporate seal shall not affect the validity of any instrument.

TRANSFER AGENT AND REGISTRAR

Section 35.   Transfer Agent; Registrar.

The Corporation may open transfer books in any state of the United States or in any foreign country for the purpose of transferring securities issued by it, and it may employ an agent or agents to keep the records of its securities to transfer or to register securities or both, in Ohio or in other states or in a foreign country, or both, and the acts of such agents shall be binding on the Corporation.  The duties and liabilities of such agent or agents shall be such as may be agreed to by the Corporation.  If no such transfer agent is appointed to act in Ohio in respect to its shares, the Corporation shall keep an office in Ohio at which shares shall be transferable, and at which it shall keep books in which shall be recorded the names and addresses of all shareholders and all transfers of shares.

PROVISIONS IN ARTICLES OF INCORPORATION

Section 36.   Governance By Articles of Incorporation.

These Regulations are at all times subject to the provisions of the Articles of Incorporation of the Corporation (including in such term whenever used in these Regulations, amendments thereto), and in case of any conflict between any provision herein and in the Articles of Incorporation, the provisions in the Articles of Incorporation shall be deemed to govern.

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AMENDMENTS

Section 37.   Procedure for Amendments.

These Regulations may be altered, amended, or repealed in any respect or superseded by new Regulations in whole or in part, (a) by the affirmative vote of the holders of record of shares entitling them to exercise a majority of the voting power of the Corporation at an annual or special meeting called for such purpose, or by their unanimous written consent; or (b) by the Board of Directors at an annual or special meeting called for such purpose, or by their unanimous written consent, as provided in Ohio Rev. Code Section 1701.11.

INDEMNIFICATION AND INSURANCE

Section 38.   Indemnification.

The Corporation shall indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he or she is or was a director, officer, employee, or agent of the Corporation, or is or was serving at the request of the Corporation as a director, trustee, officer, employee, member, manager, or agent of another corporation, limited liability company, partnership, joint venture, trust or other enterprise, against expenses, including attorney’s fees, judgments, fines and amounts paid in settlement, actually and reasonably incurred by him or her in connection with such action, suit, or proceeding, if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation, and with respect to any criminal action or proceeding, if he or she had no reasonable cause to believe his or her conduct was unlawful, to the full extent and according to the procedures and requirements set forth in the Ohio General Corporation Law as now in effect or as amended from time to time.  The Corporation shall pay, to the full extent then permitted by law, expenses, including attorney’s fees, incurred by a member of the Board of Directors in defending any such action, suit or proceeding as they are incurred, in advance of the final disposition thereof, and may pay, in the same manner and to the full extent then permitted by law, such expenses incurred by any other person.

The indemnification and payment of expenses provided hereby shall not be exclusive of, and shall be in addition to, any other rights granted to those seeking indemnification under any law, the Articles of Incorporation, any agreement, vote of shareholders or disinterested members of the Board of Directors, or otherwise, both as to action in official capacities and as to action in another capacity while he or she is a member of the Board of Directors, or an officer, employee or agent of the Corporation, and shall continue as to a person who has ceased to be a member of the Board of Directors, officer, employee or agent and shall inure to the benefit of the heirs, executors and administrators of such a person.

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Section 39.    Insurance.

The Corporation may, to the full extent then permitted by law and authorized by the Board of Directors, purchase and maintain insurance or furnish similar protection, including but not limited to trust funds, letters of credit or self-insurance, on behalf of or for any persons described in Section 38 against any liability asserted against and incurred by any such person in any such capacity, or arising out of his status as such, whether or not the Corporation would have the power to indemnify such person against such liability.  Insurance may be purchased from or maintained with a person in which the Corporation has a financial interest.

EMERGENCY REGULATIONS

Section 40.   Emergency Regulations.

The Board of Directors may adopt, at any meeting, either before or during “an emergency” as that term is defined in Section 1701.01 of the Ohio Revised Code, emergency regulations to be operative during, but only during, an emergency.  The emergency regulations may contain any provisions which may be made by emergency regulations as provided in Section 1701.111 of the Ohio Revised Code.

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EX-12.3

											EXHIBIT 12.3
											Page 1
OHIO EDISON COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
		Year Ended December 31,
			2003		2004		2005		2006		2007
		(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	292,925	$	342,766	$	330,398	$	211,639	$	197,166
Interest and other charges, before reduction for amounts capitalized
	and deferred		116,868		74,051		77,077		90,952		83,343
Provision for income taxes			241,173		278,303		309,995		123,343		101,273
Interest element of rentals charged to income (a)			107,611		104,239		101,862		89,354		79,954
	Earnings as defined	$	758,577	$	799,359	$	819,332	$	515,288	$	461,736
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred		$	113,137	$	71,491	$	75,388	$	90,356	$	83,343
Subsidiaries’ preferred stock dividend requirements			3,731		2,560		1,689		597		-
Adjustments to subsidiaries’ preferred stock dividends
	to state on a pre-income tax basis		3,014		1,975		1,351		651		-
Interest element of rentals charged to income (a)			107,611		104,239		101,862		89,354		79,954
	Fixed charges as defined	$	227,493	$	180,265	$	180,290	$	180,958	$	163,297
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES			3.33		4.43		4.54		2.85		2.83
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

											EXHIBIT 12.3
											Page 2
OHIO EDISON COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS
PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)
		Year Ended December 31,
			2003		2004		2005		2006		2007
		(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	292,925	$	342,766	$	330,398	$	211,639	$	197,166
Interest and other charges, before reduction for amounts capitalized
	and deferred		116,868		74,051		77,077		90,952		83,343
Provision for income taxes			241,173		278,303		309,995		123,343		101,273
Interest element of rentals charged to income (a)			107,611		104,239		101,862		89,354		79,954
	Earnings as defined	$	758,577	$	799,359	$	819,332	$	515,288	$	461,736
FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS
	PREFERRED STOCK DIVIDEND REQUIREMENTS
	(PRE-INCOME TAX BASIS):
Interest before reduction for amounts capitalized and deferred		$	113,137	$	71,491	$	75,388	$	90,356	$	83,343
Preferred stock dividend requirements			6,463		5,062		4,324		5,149		-
Adjustments to preferred stock dividends
	to state on a pre-income tax basis		5,264		4,072		3,758		3,263		-
Interest element of rentals charged to income (a)			107,611		104,239		101,862		89,354		79,954
Fixed charges as defined plus preferred stock
	dividend requirements (pre-income tax basis)	$	232,475	$	184,864	$	185,332	$	188,122	$	163,297
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS
	(PRE-INCOME TAX BASIS)		3.26		4.32		4.42		2.74		2.83
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

EX-23.2

EXHIBIT 23.2

OHIO EDISON COMPANY

CONSENT OF INDEPENDENT REGISTERED PUBILC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-133117) of Ohio Edison Company of our report dated February 28, 2008 relating to the financial statements, which appears in the Annual Report to Stockholders, which is incorporated in this Annual Report on Form 10-K. We also consent to the incorporation by reference of our report dated February 28, 2008 relating to the financial statement schedules, which appears in this Form 10-K.

PricewaterhouseCoopers LLP

Cleveland, OH

February 28, 2008

EX-3.3

AMENDED AND RESTATED

ARTICLES OF INCORPORATION

OF

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

Charter Number 260438

(effective December 21, 2007)

FIRST: The name of the corporation is THE CLEVELAND ELECTRIC ILLUMINATING COMPANY (hereinafter referred to as the “Corporation”).

SECOND: The place in the State of Ohio where the principal office is located is in the City of Akron, Summit County.

THIRD: The purposes of the Corporation are as follows:

A. To generate, produce, acquire, transmit, distribute, furnish, sell, and supply electricity to public and private consumers; and

B. To engage in any other lawful act or activity for which a corporation may be formed under the Ohio General Corporation Law, Chapter 1701 of the Ohio Revised Code.

FOURTH: The aggregate number of shares which the Corporation is authorized to issue shall be one hundred twelve million (112,000,000) shares, classified as follows:

A. Common Stock, one hundred five million (105,000,000) shares, with no par value;

B. SerialPreferred Stock, four million (4,000,000) shares, without par value;

C. Preference Stock, three million (3,000,000) shares, without par value.

FIFTH: The Board of Directors may adopt an amendment to these Articles of Incorporation determining, in whole or in part, the express terms, within the limits set forth in these Articles of Incorporation or the Ohio General Corporation Law, of any class of shares before the issuance of any shares of that class, or of one or more series within a class before the issuance of shares of that series; including, without limitation, division of shares into classes or into series within any class or classes, determination of the designation and the number of shares of any class or series, and the determination of the relative voting rights, preferences, limitations, rights to dividends, conversion rights, redemption rights, stated value, and other special rights of the shares of any class or series.

SIXTH: The Corporation may wind up its affairs and dissolve pursuant to a resolution adopted, at a meeting of shareholders called for such purpose, by the affirmative vote of the holders of record of shares entitling them to exercise the majority of the voting power of the Corporation.

SEVENTH: The Corporation may purchase its shares, regardless of class, from time to time, to such extent, in such manner, and upon such terms as its Board of Directors shall determine; provided, however, that the Corporation shall not purchase any of its shares if, after such purchase, its assets would be less than its liabilities plus stated capital.

EIGHTH: The shareholders shall have no right to vote cumulatively in the election of Directors.

NINTH: Sections 1701.70(B)(6) through (10) of the Ohio Revised Code shall apply to the Corporation. Thus, as provided in ORC §§ 1701.70(B)(6) through (10) and subject to the terms thereof, the Board of Directors may adopt amendments to these Articles of Incorporation:  (a) changing the name of the Corporation; (b) changing the location of the principal office of the Corporation; (c) increasing proportionately the authorized number of shares of a class of shares for the purpose of a dividend or distribution to be paid in shares of that class; (d) changing shares of a class of shares into a greater number of shares of that class and increasing proportionately the authorized number of shares of that class for the purpose of a stock split; or (e) decreasing the par value of shares of a class of shares to the extent necessary to prevent an increase in the aggregate par value of the shares of that class in the event of and concurrently with the adoption of an amendment as described in clauses (c) and (d) above for the purpose of a share dividend or stock split. [Ohio Rev. Code §1701.70(D)]

TENTH: These Amended and Restated Articles of Incorporation take the place of and supersede the existing articles of incorporation as previously amended.

EX-3.4

AMENDED AND RESTATED

CODE OF REGULATIONS

OF

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

December 14, 2007

MEETINGS OF SHAREHOLDERS

Section 1.   Annual Meetings.

The annual meeting of shareholders shall be held on such date and at such time as the Board of Directors may determine each year.  Such meetings may be held within or without the State of Ohio at such time and place as the Directors may determine.  The Directors may determine that the meeting shall not be held at any physical place, but instead may be held solely by means of communications equipment as authorized by Section 9 below.

Section 2.   Special Meetings.

Special meetings of the shareholders may be called at any time by (i) the Chairman of the Board, (ii) the President, (iii) the Directors, by action at a meeting or a majority of the Directors acting without a meeting, or (iv) the holders of 25% or more of the outstanding shares entitled to vote thereat.  Such meetings may be held within or without the State of Ohio at such time and place as may be specified in the notice thereof.

Section 3.   Notice of Meetings.

Written notice stating the time, place, if any, and purposes of a meeting of the shareholders, and the means, if any, by which shareholders can be present and vote at the meeting through the use of communications equipment shall be given by personal delivery, or by mail, facsimile transmission, overnight delivery service, or any other means of communication authorized by the shareholder to whom the notice is given, not less than seven nor more than sixty days before the date of the meeting.  Such notice may be given by or at the direction of the Chairman of the Board, the President or the Corporate Secretary.  Notices sent by mail shall be sent postage prepaid and shall be addressed to each shareholder at his address as it appears upon the records of the Corporation.  Notice by mail shall be deemed to be given at the time when the notice is deposited in the mail, notice by personal delivery or by overnight delivery service shall be deemed to be given when received, and notice by facsimile, or other electronic communications shall be deemed to be given at the time when confirmation of successful transmission is received.  Any shareholder may waive in writing notice of any meeting, either before or after the holding of such meeting, and by attending any meeting without protesting the lack of proper notice, shall be deemed to have waived notice thereof.

Section 4.   Business Transacted at Meetings.

Business transacted at any meeting of shareholders shall be for the purposes stated in the notice.

Section 5.   Quorum and Adjournments.

The holders of a majority of the stock issued and outstanding and entitled to vote thereat, present in person or represented by proxy, shall constitute a quorum at all meetings of the shareholders for the transaction of business except as otherwise provided by statute or by the Articles of Incorporation.  If, however, such quorum shall not be present or represented at any meeting of the shareholders, the shareholders entitled to vote thereat, present in person or represented by proxy, shall have power to adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum shall be present or represented.  At such adjourned meeting at which a quorum shall be present or represented, any business may be transacted which might have been transacted at the meeting as originally notified.

Section 6.   Required Vote; Inspectors.

(a)            When a quorum is present or represented at any meeting, the vote of the holders of a majority of the stock having voting power present in person or represented by proxy shall decide any question brought before such meeting, unless the question is one upon which by express provision of the statutes or of the Articles of Incorporation a different vote is required in which case such express provision shall govern and control the decision of such question.

(b)            Inspectors of election may be appointed to act at any meeting of shareholders in accordance with Ohio law.

Section 7.   Voting Power of Shareholders.

Every shareholder of record of the Corporation shall be entitled at each meeting of shareholders to one vote for each share of stock held by such shareholder according to the books of the Corporation as of the date of such vote or, if a record date is set by the Board of Directors, as of such record date.

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Section 8.   Voting by Proxy.

At any meeting of the shareholders, any shareholder may be represented and vote by a proxy or proxies appointed by an instrument in writing or by any other form of verifiable communication, including any form of electronic or other communications, to the full extent legally permitted (now or hereafter).  In the event that any such instrument shall designate two or more persons to act as proxies, a majority of such persons present at the meeting, or, if only one shall be present, then that one shall have and may exercise all of the powers conferred by such instrument upon all of the persons so designated unless the instrument shall otherwise provide.  No such proxy shall be valid after the expiration of eleven (11) months from the date of its execution, unless coupled with an interest, or unless the person executing it specifies therein the length of time for which it is to continue in force.  Subject to the above, any proxy duly executed is not revoked and continues in full force and effect until an instrument or verifiable communication revoking it or a duly executed proxy bearing a later date is filed with the Corporate Secretary of the Corporation.

Section 9.   Participation by Shareholders Through Communications Equipment.

If authorized by the Directors, the shareholders and proxyholders who are not physically present at a meeting of shareholders may attend a meeting of shareholders by use of communications equipment that enables the shareholder or proxyholder an opportunity to participate in the meeting and to vote on matters submitted to the shareholders, including an opportunity to read or hear the proceedings of the meeting and to speak or otherwise participate in the proceedings contemporaneously with those physically present.

Section 10.   Action by Shareholders Without a Meeting.

Any action which may be taken by the vote of the shareholders at a meeting may be taken without a meeting if authorized by a writing or writings signed by all of the holders of shares who would be entitled to notice of a meeting for such purpose.  Such written consent shall be filed with or entered upon the records of the Corporation.

DIRECTORS

Section 11.   Authority of Directors.

The business of the Corporation shall be managed by its Board of Directors, which may exercise all such powers of the Corporation and do all such lawful acts and things as are not by statute, the Articles of Incorporation, or these Regulations directed or required to be exercised or done by the shareholders.

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Section 12.   Number; Qualifications.

The number of Directors shall be not less than three (3) and not more than five (5) (plus any Directors separately elected by the holders of any class of stock other than the Common Stock as provided in the Articles of Incorporation as amended from time to time).  The number of Directors may be determined (a) by the vote of the holders of a majority of the shares entitled to vote thereon at any annual meeting or special meeting called for the purpose of electing Directors or (b) by action of the Board of Directors at a meeting by the vote of a majority of the Directors in office at the time or in a writing signed by all the Directors in office at the time.  When so fixed, such number shall continue to be the authorized number of Directors until changed by the shareholders or Directors in the manner described above.  Any increase in the number of Directors shall be deemed to create a vacancy or vacancies which may be filled as provided in Section 15.  A reduction in the number of Directors shall not be applied to remove any Director from office prior to the expiration of his term.  Directors need not be shareholders of the Corporation.

Section 13.   Election of Directors.

At each meeting of the shareholders for the election of Directors, the persons receiving the greatest number of votes shall be the Directors.  Such elections shall be by ballot whenever requested by any person entitled to vote at such meeting; but unless so requested, such election may be conducted in any way approved at such meeting.

Section 14.   Term of Office; Removal; Resignations.

(a)            Directors shall hold office until the annual meeting of the shareholders next following their election and until their respective successors are elected, or until their earlier resignation, death or removal from office.

(b)            Any Director or the entire Board of Directors may be removed upon the affirmative vote of the holders of a majority of the voting power of the Corporation.

(c)            Any Director may resign at any time by giving written notice of his resignation to the President or Corporate Secretary. Any resignation will be effective upon actual receipt by such person or, if later, as of the date and time specified in such written notice.

Section 15.   Vacancies.

Vacancies, including those caused by an increase in the number of Directors, may be filled by a majority of the remaining Directors though less than a quorum.  When one or more Directors shall give notice of his or their resignation to the Board, effective at a future date, the Board shall have the power to fill such vacancy or vacancies to take effect when such resignation or resignations shall become effective, each Director so appointed to hold office during the remainder of the term of office of the resigning Director or Directors.  Whenever any vacancy shall occur among the Directors, the remaining Directors shall constitute the Directors of the Corporation until such vacancy is filled or until the number of Directors is changed as in Section 12 hereof.

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MEETINGS OF THE BOARD OF DIRECTORS

Section 16.   Organizational Meeting.

Immediately after each annual meeting of the shareholders at which Directors are elected, or each special meeting held in lieu thereof, the newly elected Directors, if a quorum thereof is present, shall hold an organizational meeting at the same place or at such other time and place as may be fixed by the shareholders at such meeting, for the purpose of electing officers and transacting any other business.  Notice of such meeting need not be given.  If for any reason such organizational meeting is not held at such time, a special meeting of the Directors for such purpose shall be held as soon thereafter as practicable.

Section 17.   Special Meetings.

Special meetings of the Directors may be held at any time within or without the State of Ohio upon call by the Chairman of the Board, the President, or the Corporate Secretary upon the written request of two Directors.

Notice of the place, if any, and time of each meeting of the Directors shall be given to each Director either by personal delivery or by mail, facsimile transmission, overnight delivery service, or any other means of communication authorized by the Director, at least two days before the meeting. The notice need not specify the purposes of the meeting.  Notices sent by mail shall be sent postage prepaid and shall be addressed to each Director at his address as it appears upon the records of the Corporation.  Notice by mail shall be deemed to be given at the time when the notice is deposited in the mail, notice by personal delivery or by overnight delivery service shall be deemed to be given when received, and notice by facsimile, or other electronic communications shall be deemed to be given at the time when confirmation of successful transmission is received.  Such notice may be waived in writing by Directors either before or after the meeting, and such written waivers shall be filed with or entered upon the records of the meeting.  The attendance of any Director at any such meeting without protesting the lack of proper notice, prior to or at the commencement of the meeting, shall be deemed to be a waiver by the Director of notice of the meeting.  Unless otherwise limited in the notice thereof, any business may be transacted at any organizational, regular or special meeting.

Section 18.   Quorum and Adjournments; Participation by Communications Equipment.

(a)            A majority of the Directors, at a meeting duly called and held, shall be necessary to constitute a quorum for the transaction of business and the act of a majority of the Directors present at any meeting at which a quorum is present shall be the act of the Board of Directors, except as may be otherwise specifically provided by statute or by the Articles of Incorporation. Any action required or permitted to be taken at a meeting of the Directors may be taken without a meeting if a consent in writing, setting forth the action so taken, shall be signed by all of the Directors entitled to vote with respect to the subject matter thereof. Any meeting duly called, whether or not a quorum is present, may, by vote of a majority of the Directors present, be adjourned from time to time and place to place within or without the State of Ohio, in which case no further notice of the adjourned meeting need be given.

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(b)            Meetings of the Board of Directors or of any committee of the Board of Directors may be held through any means of communications equipment if all persons participating can hear each other, and such participation will constitute presence in person at such meeting.

Section 19.   Committees.

The Board of Directors may, by resolution passed by a majority of the Directors, designate one or more committees, each committee to consist of one or more of the Directors of the Corporation, which, to the extent provided in the resolution, shall have and may exercise the powers of the Board of Directors in the management of the business and affairs of the Corporation.  Such committee or committees shall have such name or names as may be determined from time to time by resolution adopted by the Board of Directors.  The committees shall keep regular minutes of their proceedings and report the same to the Board when required.

Section 20.   Compensation.

The Directors may be paid their expenses, if any, for attendance at each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors.  The sums may be different for different Directors, and the sum shall be established by resolution of the Board of Directors and may be changed from time to time by resolution.  No such payment shall preclude any Director from serving the Corporation in any other capacity and receiving compensation therefor.  Members of special or standing committees may be allowed like compensation for attending committee meetings.

Section 21.   Action by Directors Without a Meeting.

Any action required or permitted to be taken at a meeting of the Board of Directors or any committee of the Board of Directors may be taken without a meeting if, prior or subsequent to such action, all members of the Board of Directors or of such committee, as the case may be, consent thereto in writing and such written consents are filed with the Corporate Secretary of the Corporation.

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EXECUTIVE COMMITTEE

Section 22.   Executive Committee.

The Board of Directors at any time may elect from its members an Executive Committee which shall consist of not less than three (3) members.  Each member of such Committee shall hold office during the pleasure of the Board and may be removed by a majority vote of the whole Board at any time with or without cause.  Vacancies occurring in the Committee may be filled by the Board.  The Committee shall prescribe its own rules for calling and holding meetings, and for transacting business, subject, however, to any rules prescribed by the Board of Directors, and the Committee shall keep minutes of its actions.  Action by the Committee may be taken at meetings thereof attended by not less than a majority thereof, or without a meeting by instrument in writing signed by not less than a majority of the members.  Except as the Committee’s powers and duties may be limited or otherwise prescribed by the Board of Directors, the Committee, during the intervals between the meetings of the Board, shall possess and may exercise all of the powers and authority of the Board of Directors, however conferred, provided, however, that the Committee shall not be empowered to elect the officers (other than Assistant Secretaries and Assistant Treasurers) or to fill vacancies in the Board of Directors or in the Executive Committee.  Subject to such exceptions, persons dealing with the Corporation shall be entitled to rely upon any action of the Committee with the same force and effect as though such action had been taken by the Board of Directors.

OFFICERS

Section 23.   Generally.

The Corporation may have a Chairman, elected by the Directors from among their number, and shall have a President, a Corporate Secretary and a Treasurer.   The Corporation may also have one or more Vice Chairmen, Vice Presidents, Senior Vice Presidents and such other officers and assistant officers as the Board of Directors may deem appropriate.  If the Board of Directors so desires, it may elect a Chief Executive Officer to manage the affairs of the Corporation, subject to the direction and control of the Board of Directors.  All of the officers shall be elected by the Board of Directors.  Notwithstanding the foregoing, by specific action, the Board of Directors may authorize the Chairman or the President to appoint any person to any office other than Chairman, President, Corporate Secretary, or Treasurer.  Any number of offices may be held by the same person, and no two offices must be held by the same person.  Any of the offices may be left vacant from time to time as the Board of Directors may determine.  In case of the absence or disability of any officer of the Corporation or for any other reason deemed sufficient by a majority of the Board of Directors, the Board of Directors may delegate the absent or disabled officer's powers or duties to any other officer or to any Director.

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Section 24.  Authority and Duties of Officers.  

The officers of the Corporation shall have such authority and shall perform such duties as are customarily incident to their respective offices, or as may be specified from time to time by the Board of Directors, the Chairman or the President regardless of whether such authority and duties are customarily incident to such office.

Section 25.Compensation.  

The compensation of all officers and agents of the Corporation who are also members of the Board of Directors of the Corporation will be fixed by the Board of Directors or by a committee of the Board of Directors.  The Board of Directors may fix, or delegate the power to fix, the compensation of the other officers and agents of the Corporation to the Chief Executive Officer or any other officer of the Corporation.

Section 26.   Succession.  

The officers of the Corporation will hold office until their successors are elected.  Any officer may be removed at any time by the affirmative vote of a majority of the whole Board.  Any vacancy occurring in any office of the Corporation may be filled by the Board of Directors or by the Chairman or President as provided in Section 23.

Section 27.   Delegation of Duties.

The Directors are authorized to delegate the duties of any officers to any other officer and generally to control the action of the officers and to require the performance of duties in addition to those mentioned herein.

SHARES CERTIFICATES

Section 28.   Transfer and Registration of Certificates

The Board of Directors shall have authority to make such rules and regulations, not inconsistent with law, the Articles, or these Regulations, as it deems expedient concerning the issuance, transfer, and registration of certificates for shares and the shares represented thereby and may appoint transfer agents and registrars thereof.  The Directors may provide by resolution that some or all of any or all classes and series of shares shall be uncertificated shares, subject to any disclosure obligations therefore under Section 1701.24 of the Ohio Revised Code, and provided that any then-outstanding shares of that class or series represented by a certificate shall not become uncertificated shares until the certificate is surrendered to the Corporation.

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Section 29.   Substituted Certificates

Any person claiming that a certificate for shares has been lost, stolen, or destroyed shall make an affidavit or affirmation of that fact and, if required, shall give the Corporation (and its registrar or registrars and its transfer agent or agents, if any) a bond of indemnity, in such form and with one (1) or more sureties satisfactory to the Board, and, if required by the Board of Directors, shall advertise the same in such manner as the Board of Directors may require, whereupon a new certificate may be executed and delivered of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, or destroyed.

RECORD DATES AND CLOSING OF TRANSFER BOOKS

Section 30.   Record Dates and Closing of Transfer Books.

The Board of Directors may fix a time not exceeding sixty (60) days preceding the date of any meeting of shareholders or the date fixed for the payment of any dividend or distribution or the date for the allotment of rights as the record date for the determination of the shareholders entitled to notice of or to vote at any such meeting or entitled to receive payment of any such dividend, distribution or allotment of rights, and in such case only shareholders of record on the date so fixed shall be entitled to notice of or to vote at such meeting or to receive payment of such dividend, distribution or allotment of rights, as the case may be, notwithstanding any transfer of any shares on the books of the Corporation after any record date so fixed.  The Board of Directors may close the books of the Corporation against transfers of shares during the whole or any part of the period between such record date and the date of the event in respect for which such record date was fixed.

REGISTERED SHAREHOLDERS

Section 31.   Recognition of Record Ownership.

The Corporation shall be entitled to recognize the exclusive right of a person registered on its books as the owner of shares to receive dividends, and to vote as such owner, and to hold liable for calls and assessments a person registered on its books as the owner of shares, and shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of Ohio.

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GENERAL PROVISIONS

DIVIDENDS

Section 32.   Payment of Dividends.

The Board of Directors may declare dividends upon the capital stock of the Corporation, subject to the provisions of the Articles of Incorporation, if any, at any regular or special meeting pursuant to law.  Dividends may be paid in cash, in property or in shares of the capital stock, subject to the provisions of the Articles of Incorporation.  Before payment of any dividend, there may be set aside out of any funds of the Corporation available for dividends such sum or sums as the Directors from time to time, in their absolute discretion, think proper as a reserve or reserves to meet contingencies, or for equalizing dividends, or for repairing or maintaining any property of the Corporation, or for such other purpose as the Directors shall think conducive to the interest of the Corporation and the Directors may modify or abolish any such reserves in the manner in which it was created.

FISCAL YEAR

Section 33.   Fiscal Year.

The fiscal year of the Corporation shall be fixed by resolution of the Board of Directors.

SEAL

Section 34.   Corporate Seal.

The Directors may adopt a corporate seal of the Corporation which shall be of such design, and shall contain such words, as may be prescribed by the Directors.  Failure to affix any such corporate seal shall not affect the validity of any instrument.

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TRANSFER AGENT AND REGISTRAR

Section 35.   Transfer Agent; Registrar.

The Corporation may open transfer books in any state of the United States or in any foreign country for the purpose of transferring securities issued by it, and it may employ an agent or agents to keep the records of its securities to transfer or to register securities or both, in Ohio or in other states or in a foreign country, or both, and the acts of such agents shall be binding on the Corporation.  The duties and liabilities of such agent or agents shall be such as may be agreed to by the Corporation.  If no such transfer agent is appointed to act in Ohio in respect to its shares, the Corporation shall keep an office in Ohio at which shares shall be transferable, and at which it shall keep books in which shall be recorded the names and addresses of all shareholders and all transfers of shares.

PROVISIONS IN ARTICLES OF INCORPORATION

Section 36.   Governance By Articles of Incorporation.

These Regulations are at all times subject to the provisions of the Articles of Incorporation of the Corporation (including in such term whenever used in these Regulations, amendments thereto), and in case of any conflict between any provision herein and in the Articles of Incorporation, the provisions in the Articles of Incorporation shall be deemed to govern.

AMENDMENTS

Section 37.  Procedure for Amendments.

These Regulations may be altered, amended, or repealed in any respect or superseded by new Regulations in whole or in part, (a) by the affirmative vote of the holders of record of shares entitling them to exercise a majority of the voting power of the Corporation at an annual or special meeting called for such purpose, or by their unanimous written consent; or (b) by the Board of Directors at an annual or special meeting called for such purpose, or by their unanimous written consent, as provided in Ohio Rev. Code Section 1701.11.

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INDEMNIFICATION AND INSURANCE

Section 38.   Indemnification.

The Corporation shall indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he or she is or was a director, officer, employee, or agent of the Corporation, or is or was serving at the request of the Corporation as a director, trustee, officer, employee, member, manager, or agent of another corporation, limited liability company, partnership, joint venture, trust or other enterprise, against expenses, including attorney’s fees, judgments, fines and amounts paid in settlement, actually and reasonably incurred by him or her in connection with such action, suit, or proceeding, if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, if he or she had no reasonable cause to believe his or her conduct was unlawful, to the full extent and according to the procedures and requirements set forth in the Ohio General Corporation Law as now in effect or as amended from time to time.  The Corporation shall pay, to the full extent then permitted by law, expenses, including attorney’s fees, incurred by a member of the Board of Directors in defending any such action, suit or proceeding as they are incurred, in advance of the final disposition thereof, and may pay, in the same manner and to the full extent then permitted by law, such expenses incurred by any other person.

The indemnification and payment of expenses provided hereby shall not be exclusive of, and shall be in addition to, any other rights granted to those seeking indemnification under any law, the Articles of Incorporation, any agreement, vote of shareholders or disinterested members of the Board of Directors, or otherwise, both as to action in official capacities and as to action in another capacity while he or she is a member of the Board of Directors, or an officer, employee or agent of the Corporation, and shall continue as to a person who has ceased to be a member of the Board of Directors, officer, employee or agent and shall inure to the benefit of the heirs, executors and administrators of such a person.

Section 39.   Insurance.

The Corporation may, to the full extent then permitted by law and authorized by the Board of Directors, purchase and maintain insurance or furnish similar protection, including but not limited to trust funds, letters of credit or self-insurance, on behalf of or for any persons described in Section 38 against any liability asserted against and incurred by any such person in any such capacity, or arising out of his status as such, whether or not the Corporation would have the power to indemnify such person against such liability.  Insurance may be purchased from or maintained with a person in which the Corporation has a financial interest.

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EMERGENCY REGULATIONS

Section 40.   Emergency Regulations.

The Board of Directors may adopt, at any meeting, either before or during “an emergency” as that term is defined in Section 1701.01 of the Ohio Revised Code, emergency regulations to be operative during, but only during, an emergency.  The emergency regulations may contain any provisions which may be made by emergency regulations as provided in Section 1701.111 of the Ohio Revised Code.

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EX-12.4

											EXHIBIT 12.4
											Page 1
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
		Year Ended December 31,
			2003		2004		2005		2006		2007
		(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	197,033	$	236,531	$	231,058	$	306,051	$	276,412
Interest and other charges, before reduction for amounts capitalized
	and deferred		164,132		138,678		132,226		141,710		138,977
Provision for income taxes			131,285		138,856		153,014		188,662		163,363
Interest element of rentals charged to income (a)			49,761		49,375		47,643		45,955		29,829
	Earnings as defined	$	542,211	$	563,440	$	563,941	$	682,378	$	608,581
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred		$	159,632	$	138,678	$	132,226	$	141,710	$	138,977
Subsidiary's preferred stock dividend requirements			4,500		-		-		-		-
Interest element of rentals charged to income (a)			49,761		49,375		47,643		45,955		29,829
	Fixed charges as defined	$	213,893	$	188,053	$	179,869	$	187,665	$	168,806
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES			2.53		3.00		3.14		3.64		3.61
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

											EXHIBIT 12.4
											Page 2
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS
PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)
			2003		2004		2005		2006		2007
			(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	197,033	$	236,531	$	231,058	$	306,051	$	276,412
Interest and other charges, before reduction for amounts capitalized
	and deferred		164,132		138,678		132,226		141,710		138,977
Provision for income taxes			131,285		138,856		153,014		188,662		163,363
Interest element of rentals charged to income (a)			49,761		49,375		47,643		45,955		29,829
	Earnings as defined	$	542,211	$	563,440	$	563,941	$	682,378	$	608,581
FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS
	PREFERRED STOCK DIVIDEND REQUIREMENTS
	(PRE-INCOME TAX BASIS):
Interest before reduction for amounts capitalized and deferred		$	159,632	$	138,678	$	132,226	$	141,710	$	138,977
Preferred stock dividend requirements			12,026		7,008		2,918		-		-
Adjustments to preferred stock dividends
	to state on a pre-income tax basis		5,137		4,113		1,932		-		-
Interest element of rentals charged to income (a)			49,761		49,375		47,643		45,955		29,829
Fixed charges as defined plus preferred stock
	dividend requirements (pre-income tax basis)	$	226,556	$	199,174	$	184,719	$	187,665	$	168,806
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS
	(PRE-INCOME TAX BASIS)		2.39		2.83		3.05		3.64		3.61
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

EX-3.5

AMENDED AND RESTATED

ARTICLES OF INCORPORATION

OF

THE TOLEDO EDISON COMPANY

Charter Number 015974

(effective December 18, 2007)

FIRST: The name of the corporation is THE TOLEDO EDISON COMPANY (hereinafter referred to as the “Corporation”).

SECOND: The place in the State of Ohio where the principal office is located is in the City of Akron, Summit County.

THIRD: The purposes of the Corporation are as follows:

A. To generate, produce, acquire, transmit, distribute, furnish, sell, and supply electricity to public and private consumers; and

B. To engage in any other lawful act or activity for which a corporation may be formed under the Ohio General Corporation Law, Chapter 1701 of the Ohio Revised Code.

FOURTH: The aggregate number of shares which the Corporation is authorized to issue shall be eighty million (80,000,000) shares, classified as follows:

A. Common Stock, sixty million (60,000,000) shares, with a par value of five dollars ($5) per share;

B. CumulativePreferred Stock, three million (3,000,000) shares, with a par value of one hundred dollars ($100) per share;

C. CumulativePreferred Stock, twelve million (12,000,000) shares, with a par value of twenty-five dollars ($25) per share; and

D. Preference Stock, five million (5,000,000) shares, with a par value of twenty-five dollars ($25) per share.

FIFTH: The Board of Directors may adopt an amendment to these Articles of Incorporation determining, in whole or in part, the express terms, within the limits set forth in these Articles of Incorporation or the Ohio General Corporation Law, of any class of shares before the issuance of any shares of that class, or of one or more series within a class before the issuance of shares of that series; including, without limitation, division of shares into classes or into series within any class or classes, determination of the designation and the number of shares of any class or series, and the determination of the relative voting rights, preferences, limitations, rights to dividends, conversion rights, redemption rights, stated value, and other special rights of the shares of any class or series.

SIXTH: The Corporation may wind up its affairs and dissolve pursuant to a resolution adopted, at a meeting of shareholders called for such purpose, by the affirmative vote of the holders of record of shares entitling them to exercise the majority of the voting power of the Corporation.

SEVENTH: The Corporation may purchase its shares, regardless of class, from time to time, to such extent, in such manner, and upon such terms as its Board of Directors shall determine; provided, however, that the Corporation shall not purchase any of its shares if, after such purchase, its assets would be less than its liabilities plus stated capital.

EIGHTH: The shareholders shall have no right to vote cumulatively in the election of Directors.

NINTH: Sections 1701.70(B)(6) through (10) of the Ohio Revised Code shall apply to the Corporation. Thus, as provided in ORC §§ 1701.70(B)(6) through (10) and subject to the terms thereof, the Board of Directors may adopt amendments to these Articles of Incorporation:  (a) changing the name of the Corporation; (b) changing the location of the principal office of the Corporation; (c) increasing proportionately the authorized number of shares of a class of shares for the purpose of a dividend or distribution to be paid in shares of that class; (d) changing shares of a class of shares into a greater number of shares of that class and increasing proportionately the authorized number of shares of that class for the purpose of a stock split; or (e) decreasing the par value of shares of a class of shares to the extent necessary to prevent an increase in the aggregate par value of the shares of that class in the event of and concurrently with the adoption of an amendment as described in clauses (c) and (d) above for the purpose of a share dividend or stock split. [Ohio Rev. Code §1701.70(D)]

TENTH: These Amended and Restated Articles of Incorporation take the place of and supersede the existing articles of incorporation as previously amended.

EX-3.6

AMENDED AND RESTATED

CODE OF REGULATIONS

OF

THE TOLEDO EDISON COMPANY

December 14, 2007

MEETINGS OF SHAREHOLDERS

Section 1.   Annual Meetings.

The annual meeting of shareholders shall be held on such date and at such time as the Board of Directors may determine each year.  Such meetings may be held within or without the State of Ohio at such time and place as the Directors may determine.  The Directors may determine that the meeting shall not be held at any physical place, but instead may be held solely by means of communications equipment as authorized by Section 9 below.

Section 2.   Special Meetings.

Special meetings of the shareholders may be called at any time by (i) the Chairman of the Board, (ii) the President, (iii) the Directors, by action at a meeting or a majority of the Directors acting without a meeting, or (iv) the holders of 25% or more of the outstanding shares entitled to vote thereat.  Such meetings may be held within or without the State of Ohio at such time and place as may be specified in the notice thereof.

Section 3.   Notice of Meetings.

Written notice stating the time, place, if any, and purposes of a meeting of the shareholders, and the means, if any, by which shareholders can be present and vote at the meeting through the use of communications equipment shall be given by personal delivery, or by mail, facsimile transmission, overnight delivery service, or any other means of communication authorized by the shareholder to whom the notice is given, not less than seven nor more than sixty days before the date of the meeting.  Such notice may be given by or at the direction of the Chairman of the Board, the President or the Corporate Secretary.  Notices sent by mail shall be sent postage prepaid and shall be addressed to each shareholder at his address as it appears upon the records of the Corporation.  Notice by mail shall be deemed to be given at the time when the notice is deposited in the mail, notice by personal delivery or by overnight delivery service shall be deemed to be given when received, and notice by facsimile, or other electronic communications shall be deemed to be given at the time when confirmation of successful transmission is received.  Any shareholder may waive in writing notice of any meeting, either before or after the holding of such meeting, and, by attending any meeting without protesting the lack of proper notice, shall be deemed to have waived notice thereof.

Section 4.   Business Transacted at Meetings.

Business transacted at any meeting of shareholders shall be for the purposes stated in the notice.

Section 5.   Quorum and Adjournments.

The holders of a majority of the stock issued and outstanding and entitled to vote thereat, present in person or represented by proxy, shall constitute a quorum at all meetings of the shareholders for the transaction of business except as otherwise provided by statute or by the Articles of Incorporation.  If, however, such quorum shall not be present or represented at any meeting of the shareholders, the shareholders entitled to vote thereat, present in person or represented by proxy, shall have power to adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum shall be present or represented.  At such adjourned meeting at which a quorum shall be present or represented, any business may be transacted which might have been transacted at the meeting as originally notified.

Section 6.   Required Vote; Inspectors.

(a)            When a quorum is present or represented at any meeting, the vote of the holders of a majority of the stock having voting power present in person or represented by proxy shall decide any question brought before such meeting, unless the question is one upon which by express provision of the statutes or of the Articles of Incorporation a different vote is required in which case such express provision shall govern and control the decision of such question.

(b)            Inspectors of election may be appointed to act at any meeting of shareholders in accordance with Ohio law.

Section 7.   Voting Power of Shareholders.

Every shareholder of record of the Corporation shall be entitled at each meeting of shareholders to one vote for each share of stock held by such shareholder according to the books of the Corporation as of the date of such vote or, if a record date is set by the Board of Directors, as of such record date.

Section 8.   Voting by Proxy.

At any meeting of the shareholders, any shareholder may be represented and vote by a proxy or proxies appointed by an instrument in writing or by any other form of verifiable communication, including any form of electronic or other communications, to the full extent legally permitted (now or hereafter).  In the event that any such instrument shall designate two or more persons to act as proxies, a majority of such persons present at the meeting, or, if only one shall be present, then that one shall have and may exercise all of the powers conferred by such instrument upon all of the persons so designated unless the instrument shall otherwise provide.  No such proxy shall be valid after the expiration of eleven (11) months from the date of its execution, unless coupled with an interest, or unless the person executing it specifies therein the length of time for which it is to continue in force.  Subject to the above, any proxy duly executed is not revoked and continues in full force and effect until an instrument or verifiable communication revoking it or a duly executed proxy bearing a later date is filed with the Corporate Secretary of the Corporation.

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Section 9.   Participation by Shareholders Through Communications Equipment.

If authorized by the Directors, the shareholders and proxyholders who are not physically present at a meeting of shareholders may attend a meeting of shareholders by use of communications equipment that enables the shareholder or proxyholder an opportunity to participate in the meeting and to vote on matters submitted to the shareholders, including an opportunity to read or hear the proceedings of the meeting and to speak or otherwise participate in the proceedings contemporaneously with those physically present.

Section 10.   Action by Shareholders Without a Meeting.

Any action which may be taken by the vote of the shareholders at a meeting may be taken without a meeting if authorized by a writing or writings signed by all of the holders of shares who would be entitled to notice of a meeting for such purpose.  Such written consent shall be filed with or entered upon the records of the Corporation.

DIRECTORS

Section 11.   Authority of Directors.

The business of the Corporation shall be managed by its Board of Directors, which may exercise all such powers of the Corporation and do all such lawful acts and things as are not by statute, the Articles of Incorporation, or these Regulations directed or required to be exercised or done by the shareholders.

Section 12.   Number; Qualifications.

The number of Directors shall be not less than three (3) and not more than five (5) (plus any Directors separately elected by the holders of any class of stock other than the Common Stock as provided in the Articles of Incorporation as amended from time to time).  The number of Directors may be determined (a) by the vote of the holders of a majority of the shares entitled to vote thereon at any annual meeting or special meeting called for the purpose of electing Directors or (b) by action of the Board of Directors at a meeting by the vote of a majority of the Directors in office at the time or in a writing signed by all the Directors in office at the time.  When so fixed, such number shall continue to be the authorized number of Directors until changed by the shareholders or Directors in the manner described above.  Any increase in the number of Directors shall be deemed to create a vacancy or vacancies which may be filled as provided in Section 15.  A reduction in the number of Directors shall not be applied to remove any Director from office prior to the expiration of his term.  Directors need not be shareholders of the Corporation.

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Section 13.    Election of Directors.

At each meeting of the shareholders for the election of Directors, the persons receiving the greatest number of votes shall be the Directors.  Such elections shall be by ballot whenever requested by any person entitled to vote at such meeting; but unless so requested, such election may be conducted in any way approved at such meeting.

Section 14.   Term of Office; Removal; Resignations.

(a)            Directors shall hold office until the annual meeting of the shareholders next following their election and until their respective successors are elected, or until their earlier resignation, death or removal from office.

(b)            Any Director or the entire Board of Directors may be removed upon the affirmative vote of the holders of a majority of the voting power of the Corporation.

(c)            Any Director may resign at any time by giving written notice of his resignation to the President or Corporate Secretary. Any resignation will be effective upon actual receipt by such person or, if later, as of the date and time specified in such written notice.

Section 15.   Vacancies.

Vacancies, including those caused by an increase in the number of Directors, may be filled by a majority of the remaining Directors though less than a quorum.  When one or more Directors shall give notice of his or their resignation to the Board, effective at a future date, the Board shall have the power to fill such vacancy or vacancies to take effect when such resignation or resignations shall become effective, each Director so appointed to hold office during the remainder of the term of office of the resigning Director or Directors.  Whenever any vacancy shall occur among the Directors, the remaining Directors shall constitute the Directors of the Corporation until such vacancy is filled or until the number of Directors is changed as in Section 12 hereof.

MEETINGS OF THE BOARD OF DIRECTORS

Section 16.   Organizational Meeting.

Immediately after each annual meeting of the shareholders at which Directors are elected, or each special meeting held in lieu thereof, the newly elected Directors, if a quorum thereof is present, shall hold an organizational meeting at the same place or at such other time and place as may be fixed by the shareholders at such meeting, for the purpose of electing officers and transacting any other business.  Notice of such meeting need not be given.  If for any reason such organizational meeting is not held at such time, a special meeting of the Directors for such purpose shall be held as soon thereafter as practicable.

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Section 17.   Special Meetings.

Special meetings of the Directors may be held at any time within or without the State of Ohio upon call by the Chairman of the Board, the President, or the Corporate Secretary upon the written request of two Directors.

Notice of the place, if any, and time of each meeting of the Directors shall be given to each Director either by personal delivery or by mail, facsimile transmission, overnight delivery service, or any other means of communication authorized by the Director, at least two days before the meeting. The notice need not specify the purposes of the meeting.  Notices sent by mail shall be sent postage prepaid and shall be addressed to each Director at his address as it appears upon the records of the Corporation.  Notice by mail shall be deemed to be given at the time when the notice is deposited in the mail, notice by personal delivery or by overnight delivery service shall be deemed to be given when received, and notice by facsimile, or other electronic communications shall be deemed to be given at the time when confirmation of successful transmission is received.  Such notice may be waived in writing by Directors either before or after the meeting, and such written waivers shall be filed with or entered upon the records of the meeting.  The attendance of any Director at any such meeting without protesting the lack of proper notice, prior to or at the commencement of the meeting, shall be deemed to be a waiver by the Director of notice of the meeting.  Unless otherwise limited in the notice thereof, any business may be transacted at any organizational, regular or special meeting.

Section 18.   Quorum and Adjournments; Participation by Communications Equipment.

(a)            A majority of the Directors, at a meeting duly called and held, shall be necessary to constitute a quorum for the transaction of business and the act of a majority of the Directors present at any meeting at which a quorum is present shall be the act of the Board of Directors, except as may be otherwise specifically provided by statute or by the Articles of Incorporation. Any action required or permitted to be taken at a meeting of the Directors may be taken without a meeting if a consent in writing, setting forth the action so taken, shall be signed by all of the Directors entitled to vote with respect to the subject matter thereof. Any meeting duly called, whether or not a quorum is present, may, by vote of a majority of the Directors present, be adjourned from time to time and place to place within or without the State of Ohio, in which case no further notice of the adjourned meeting need be given.

(b)            Meetings of the Board of Directors or of any committee of the Board of Directors may be held through any means of communications equipment if all persons participating can hear each other, and such participation will constitute presence in person at such meeting.

Section 19.   Committees.

The Board of Directors may, by resolution passed by a majority of the Directors, designate one or more committees, each committee to consist of one or more of the Directors of the Corporation, which, to the extent provided in the resolution, shall have and may exercise the powers of the Board of Directors in the management of the business and affairs of the Corporation.  Such committee or committees shall have such name or names as may be determined from time to time by resolution adopted by the Board of Directors.  The committees shall keep regular minutes of their proceedings and report the same to the Board when required.

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Section 20.   Compensation.

The Directors may be paid their expenses, if any, for attendance at each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors.  The sums may be different for different Directors, and the sum shall be established by resolution of the Board of Directors and may be changed from time to time by resolution.  No such payment shall preclude any Director from serving the Corporation in any other capacity and receiving compensation therefor.  Members of special or standing committees may be allowed like compensation for attending committee meetings.

Section 21.   Action by Directors Without a Meeting.

Any action required or permitted to be taken at a meeting of the Board of Directors or any committee of the Board of Directors may be taken without a meeting if, prior or subsequent to such action, all members of the Board of Directors or of such committee, as the case may be, consent thereto in writing and such written consents are filed with the Corporate Secretary of the Corporation.

EXECUTIVE COMMITTEE

Section 22.   Executive Committee.

The Board of Directors at any time may elect from its members an Executive Committee which shall consist of not less than three (3) members.  Each member of such Committee shall hold office during the pleasure of the Board and may be removed by a majority vote of the whole Board at any time with or without cause.  Vacancies occurring in the Committee may be filled by the Board.  The Committee shall prescribe its own rules for calling and holding meetings, and for transacting business, subject, however, to any rules prescribed by the Board of Directors, and the Committee shall keep minutes of its actions.  Action by the Committee may be taken at meetings thereof attended by not less than a majority thereof, or without a meeting by instrument in writing signed by not less than a majority of the members.  Except as the Committee’s powers and duties may be limited or otherwise prescribed by the Board of Directors, the Committee, during the intervals between the meetings of the Board, shall possess and may exercise all of the powers and authority of the Board of Directors, however conferred, provided, however, that the Committee shall not be empowered to elect the officers (other than Assistant Secretaries and Assistant Treasurers) or to fill vacancies in the Board of Directors or in the Executive Committee.  Subject to such exceptions, persons dealing with the Corporation shall be entitled to rely upon any action of the Committee with the same force and effect as though such action had been taken by the Board of Directors.

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OFFICERS

Section 23.   Generally.

The Corporation may have a Chairman, elected by the Directors from among their number, and shall have a President, a Corporate Secretary and a Treasurer.   The Corporation may also have one or more Vice Chairmen, Vice Presidents, Senior Vice Presidents and such other officers and assistant officers as the Board of Directors may deem appropriate.  If the Board of Directors so desires, it may elect a Chief Executive Officer to manage the affairs of the Corporation, subject to the direction and control of the Board of Directors.  All of the officers shall be elected by the Board of Directors.  Notwithstanding the foregoing, by specific action, the Board of Directors may authorize the Chairman or the President to appoint any person to any office other than Chairman, President, Corporate Secretary, or Treasurer.  Any number of offices may be held by the same person, and no two offices must be held by the same person.  Any of the offices may be left vacant from time to time as the Board of Directors may determine.  In case of the absence or disability of any officer of the Corporation or for any other reason deemed sufficient by a majority of the Board of Directors, the Board of Directors may delegate the absent or disabled officer's powers or duties to any other officer or to any Director.

Section 24.  Authority and Duties of Officers.  

The officers of the Corporation shall have such authority and shall perform such duties as are customarily incident to their respective offices, or as may be specified from time to time by the Board of Directors, the Chairman or the President regardless of whether such authority and duties are customarily incident to such office.

Section 25.   Compensation.  

The compensation of all officers and agents of the Corporation who are also members of the Board of Directors of the Corporation will be fixed by the Board of Directors or by a committee of the Board of Directors.  The Board of Directors may fix, or delegate the power to fix, the compensation of the other officers and agents of the Corporation to the Chief Executive Officer or any other officer of the Corporation.

Section 26.   Succession.  

The officers of the Corporation will hold office until their successors are elected.  Any officer may be removed at any time by the affirmative vote of a majority of the whole Board.  Any vacancy occurring in any office of the Corporation may be filled by the Board of Directors or by the Chairman or President as provided in Section 23.

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Section 27.   Delegation of Duties.

The Directors are authorized to delegate the duties of any officers to any other officer and generally to control the action of the officers and to require the performance of duties in addition to those mentioned herein.

SHARES CERTIFICATES

Section 28.   Transfer and Registration of Certificates

The Board of Directors shall have authority to make such rules and regulations, not inconsistent with law, the Articles, or these Regulations, as it deems expedient concerning the issuance, transfer, and registration of certificates for shares and the shares represented thereby and may appoint transfer agents and registrars thereof.  The Directors may provide by resolution that some or all of any or all classes and series of shares shall be uncertificated shares, subject to any disclosure obligations therefore under Section 1701.24 of the Ohio Revised Code, and provided that any then-outstanding shares of that class or series represented by a certificate shall not become uncertificated shares until the certificate is surrendered to the Corporation.

Section 29.   Substituted Certificates

Any person claiming that a certificate for shares has been lost, stolen, or destroyed shall make an affidavit or affirmation of that fact and, if required, shall give the Corporation (and its registrar or registrars and its transfer agent or agents, if any) a bond of indemnity, in such form and with one (1) or more sureties satisfactory to the Board, and, if required by the Board of Directors, shall advertise the same in such manner as the Board of Directors may require, whereupon a new certificate may be executed and delivered of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, or destroyed.

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RECORD DATES AND CLOSING OF TRANSFER BOOKS

Section 30.   Record Dates and Closing of Transfer Books.

The Board of Directors may fix a time not exceeding sixty (60) days preceding the date of any meeting of shareholders or the date fixed for the payment of any dividend or distribution or the date for the allotment of rights as the record date for the determination of the shareholders entitled to notice of or to vote at any such meeting or entitled to receive payment of any such dividend, distribution or allotment of rights, and in such case only shareholders of record on the date so fixed shall be entitled to notice of or to vote at such meeting or to receive payment of such dividend, distribution or allotment of rights, as the case may be, notwithstanding any transfer of any shares on the books of the Corporation after any record date so fixed.  The Board of Directors may close the books of the Corporation against transfers of shares during the whole or any part of the period between such record date and the date of the event in respect for which such record date was fixed.

REGISTERED SHAREHOLDERS

Section 31.   Recognition of Record Ownership.

The Corporation shall be entitled to recognize the exclusive right of a person registered on its books as the owner of shares to receive dividends, and to vote as such owner, and to hold liable for calls and assessments a person registered on its books as the owner of shares, and shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of Ohio.

GENERAL PROVISIONS

DIVIDENDS

Section 32.   Payment of Dividends.

The Board of Directors may declare dividends upon the capital stock of the Corporation, subject to the provisions of the Articles of Incorporation, if any, at any regular or special meeting pursuant to law.  Dividends may be paid in cash, in property or in shares of the capital stock, subject to the provisions of the Articles of Incorporation.  Before payment of any dividend, there may be set aside out of any funds of the Corporation available for dividends such sum or sums as the Directors from time to time, in their absolute discretion, think proper as a reserve or reserves to meet contingencies, or for equalizing dividends, or for repairing or maintaining any property of the Corporation, or for such other purpose as the Directors shall think conducive to the interest of the Corporation and the Directors may modify or abolish any such reserves in the manner in which it was created.

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FISCAL YEAR

Section 33.   Fiscal Year.

The fiscal year of the Corporation shall be fixed by resolution of the Board of Directors.

SEAL

Section 34.   Corporate Seal.

The Directors may adopt a corporate seal of the Corporation which shall be of such design, and shall contain such words, as may be prescribed by the Directors.  Failure to affix any such corporate seal shall not affect the validity of any instrument.

TRANSFER AGENT AND REGISTRAR

Section 35.   Transfer Agent; Registrar.

The Corporation may open transfer books in any state of the United States or in any foreign country for the purpose of transferring securities issued by it, and it may employ an agent or agents to keep the records of its securities to transfer or to register securities or both, in Ohio or in other states or in a foreign country, or both, and the acts of such agents shall be binding on the Corporation.  The duties and liabilities of such agent or agents shall be such as may be agreed to by the Corporation.  If no such transfer agent is appointed to act in Ohio in respect to its shares, the Corporation shall keep an office in Ohio at which shares shall be transferable, and at which it shall keep books in which shall be recorded the names and addresses of all shareholders and all transfers of shares.

PROVISIONS IN ARTICLES OF INCORPORATION

Section 36.   Governance By Articles of Incorporation.

These Regulations are at all times subject to the provisions of the Articles of Incorporation of the Corporation (including in such term whenever used in these Regulations, amendments thereto), and in case of any conflict between any provision herein and in the Articles of Incorporation, the provisions in the Articles of Incorporation shall be deemed to govern.

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AMENDMENTS

Section 37.   Procedure for Amendments.

These Regulations may be altered, amended, or repealed in any respect or superseded by new Regulations in whole or in part, (a) by the affirmative vote of the holders of record of shares entitling them to exercise a majority of the voting power of the Corporation at an annual or special meeting called for such purpose, or by their unanimous written consent; or (b) by the Board of Directors at an annual or special meeting called for such purpose, or by their unanimous written consent, as provided in Ohio Rev. Code Section 1701.11.

INDEMNIFICATION AND INSURANCE

Section 38.   Indemnification.

The Corporation shall indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he or she is or was a director, officer, employee, or agent of the Corporation, or is or was serving at the request of the Corporation as a director, trustee, officer, employee, member, manager, or agent of another corporation, limited liability company, partnership, joint venture, trust or other enterprise, against expenses, including attorney’s fees, judgments, fines and amounts paid in settlement, actually and reasonably incurred by him or her in connection with such action, suit, or proceeding, if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation, and with respect to any criminal action or proceeding, if he or she had no reasonable cause to believe his or her conduct was unlawful, to the full extent and according to the procedures and requirements set forth in the Ohio General Corporation Law as now in effect or as amended from time to time.  The Corporation shall pay, to the full extent then permitted by law, expenses, including attorney’s fees, incurred by a member of the Board of Directors in defending any such action, suit or proceeding as they are incurred, in advance of the final disposition thereof, and may pay, in the same manner and to the full extent then permitted by law, such expenses incurred by any other person.

The indemnification and payment of expenses provided hereby shall not be exclusive of, and shall be in addition to, any other rights granted to those seeking indemnification under any law, the Articles of Incorporation, any agreement, vote of shareholders or disinterested members of the Board of Directors, or otherwise, both as to action in official capacities and as to action in another capacity while he or she is a member of the Board of Directors, or an officer, employee or agent of the Corporation, and shall continue as to a person who has ceased to be a member of the Board of Directors, officer, employee or agent and shall inure to the benefit of the heirs, executors and administrators of such a person.

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Section 39.   Insurance.

The Corporation may, to the full extent then permitted by law and authorized by the Board of Directors, purchase and maintain insurance or furnish similar protection, including but not limited to trust funds, letters of credit or self-insurance, on behalf of or for any persons described in Section 38 against any liability asserted against and incurred by any such person in any such capacity, or arising out of his status as such, whether or not the Corporation would have the power to indemnify such person against such liability.  Insurance may be purchased from or maintained with a person in which the Corporation has a financial interest.

EMERGENCY REGULATIONS

Section 40.   Emergency Regulations.

The Board of Directors may adopt, at any meeting, either before or during “an emergency” as that term is defined in Section 1701.01 of the Ohio Revised Code, emergency regulations to be operative during, but only during, an emergency.  The emergency regulations may contain any provisions which may be made by emergency regulations as provided in Section 1701.111 of the Ohio Revised Code.

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EX-12.5

											EXHIBIT 12.5
											Page 1
THE TOLEDO EDISON COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
		Year Ended December 31,
			2003		2004		2005		2006		2007
		(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	19,930	$	86,283	$	76,164	$	99,404	$	91,239
Interest and other charges, before reduction for amounts capitalized
	and deferred		42,126		33,439		21,489		23,179		34,135
Provision for income taxes			5,394		52,350		73,931		59,869		53,736
Interest element of rentals charged to income (a)			84,894		82,879		80,042		77,158		57,393
	Earnings as defined	$	152,344	$	254,951	$	251,626	$	259,610	$	236,503
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred		$	42,126	$	33,439	$	21,489	$	23,179	$	34,135
Interest element of rentals charged to income (a)			84,894		82,879		80,042		77,158		57,393
	Fixed charges as defined	$	127,020	$	116,318	$	101,531	$	100,337	$	91,528
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES			1.20		2.19		2.48		2.59		2.58
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

											EXHIBIT 12.5
											Page 2
THE TOLEDO EDISON COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS
PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)
		Year Ended December 31,
			2003		2004		2005		2006		2007
		(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	19,930	$	86,283	$	76,164	$	99,404	$	91,239
Interest and other charges, before reduction for amounts capitalized
	and deferred		42,126		33,439		21,489		23,179		34,135
Provision for income taxes			5,394		52,350		73,931		59,869		53,736
Interest element of rentals charged to income (a)			84,894		82,879		80,042		77,158		57,393
	Earnings as defined	$	152,344	$	254,951	$	251,626	$	259,610	$	236,503
FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS
	PREFERRED STOCK DIVIDEND REQUIREMENTS
	(PRE-INCOME TAX BASIS):
Interest before reduction for amounts capitalized and deferred		$	42,126	$	33,439	$	21,489	$	23,179	$	34,135
Preferred stock dividend requirements			8,838		8,844		7,795		9,409		-
Adjustments to preferred stock dividends
	to state on a pre-income tax basis		2,158		5,366		7,561		5,667		-
Interest element of rentals charged to income (a)			84,894		82,879		80,042		77,158		57,393
Fixed charges as defined plus preferred stock
	dividend requirements (pre-income tax basis)	$	138,016	$	130,528	$	116,887	$	115,413	$	91,528
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS
	(PRE-INCOME TAX BASIS)		1.10		1.95		2.15		2.25		2.58
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

EX-3.7

AMENDED AND RESTATED

CERTIFICATE OF INCORPORATION

OF

JERSEY CENTRAL POWER & LIGHT COMPANY

Charter Number 0002020200

Filed:  February 14, 2008

Pursuant to Section 14A:9-5 of the New Jersey Business Corporation Act, Jersey Central Power & Light Company (hereinafter referred to as the “Corporation”) amends, restates, and integrates its Certificate of Incorporation, as heretofore amended and restated, to read as follows:

ARTICLE I

The name of the Corporation is JERSEY CENTRAL POWER & LIGHT COMPANY.

ARTICLE II

The address of the Corporation’s current registered office is:

Jersey Central Power & Light Company

c/o The Corporation Trust Company

820 Bear Tavern Road

West Trenton, New Jersey  08628

The name of the Corporation’s current registered agent at such address is:  The Corporation Trust Company.

ARTICLE III

The purpose or purposes for which the Corporation is organized is as follows:

A.           To generate, produce, acquire, transmit, distribute, furnish, sell, and supply electricity to public and private consumers; and

B.           To engage in any other activity within the purposes for which corporations may be organized under the New Jersey Business Corporation Act, Title 14A New Jersey Statutes.

ARTICLE IV

The aggregate number of shares which the Corporation is authorized to issue shall be thirty-one million six hundred thousand (31,600,000) shares, classified as follows:

A.           Common Stock, sixteen million (16,000,000) shares, with a par value of ten dollars ($10) each; and

B.           Cumulative Preferred Stock, fifteen million six hundred thousand (15,600,000) shares, with no par value, and with such stated value as may be determined by the Board of Directors.

ARTICLE V

The Board of Directors may adopt an amendment to this Certificate of Incorporation determining, in whole or in part, the express terms, within the limits set forth in this Certificate of Incorporation or the New Jersey Business Corporation Act, of any class of shares before the issuance of any shares of that class, or of one or more series within a class before the issuance of shares of that series; including, without limitation, division of shares into classes or into series within any class or classes, determination of the designation and the number of shares of any class or series, and the determination of the relative voting rights, preferences, limitations, rights to dividends, conversion rights, redemption rights, stated value, and other special rights of the shares of any class or series.

ARTICLE VI

A director or officer of the Corporation shall not be personally liable to the Corporation or its shareholders for damages for breach of any duty owed to the Corporation or its shareholders; except that this Article shall not relieve a director or officer from liability for any breach of duty based upon an act or omission (a) in breach of such person's duty of loyalty to the Corporation or its shareholders, (b) not in good faith or involving a knowing violation of law or (c) resulting in receipt by such person of an improper personal benefit.  As used herein, an act or omission in breach of a person's duty of loyalty means an act or omission which that person knows or believes to be contrary to the best interests of the Corporation or its shareholders in connection with a matter in which he has a material conflict of interest.  [NJ Stat. 14A:2-7(3)]

ARTICLE VII

The Corporation may wind up its affairs and dissolve pursuant to a resolution adopted, at a meeting of shareholders called for such purpose, by the affirmative vote of the holders of record of shares entitling them to exercise the majority of the voting power of the Corporation.

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ARTICLE VIII

The Corporation may purchase its shares, regardless of class, from time to time, to such extent, in such manner, and upon such terms as its Board of Directors shall determine; provided, however, that the Corporation shall not purchase any of its shares if, after such purchase, either (a) the Corporation would be unable to pay its debts as they become due or (b) the Corporation's total assets would be less than its total liabilities.

ARTICLE IX

The shareholders shall have no right to vote cumulatively in the election of Directors.

ARTICLE X

The shareholders shall have no preemptive rights to subscribe for or to purchase from the Corporation any of the shares of any class of the Corporation hereafter issued or sold.

ARTICLE XI

The number of Directors constituting the current Board of Directors is six, and their names and addresses are as follows:

Bradley S. Ewing 300 Madison Avenue Morristown, NJ 07962-1911	Mark A. Julian 300 Madison Avenue Morristown, NJ 07962-1911
Stephen E. Morgan 300 Madison Avenue Morristown, NJ 07962-1911	Gelorma E. Persson 300 Madison Avenue Morristown, NJ 07962-1911
Donald R. Schneider 300 Madison Avenue Morristown, NJ 07962-1911	Jesse T. Williams, Sr 300 Madison Avenue Morristown, NJ 07962-1911

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EX-3.8

AMENDED AND RESTATED

BYLAWS

OF

JERSEY CENTRAL POWER & LIGHT COMPANY

January 9, 2008

MEETINGS OF SHAREHOLDERS

Section 1.   Annual Meetings.

The annual meeting of shareholders shall be held on such date and at such time as the Board of Directors may determine each year.  Such meetings may be held within or without the State of New Jersey at such time and place as the Directors may determine.  The Directors may determine that the meeting shall not be held at any physical place, but instead may be held solely by means of communications equipment as authorized by Section 9 below.

Section 2.   Special Meetings.

Special meetings of the shareholders may be called at any time by (i) the Chairman of the Board, (ii) the President, (iii) the Directors, by action at a meeting or a majority of the Directors acting without a meeting, or (iv) the holders of 25% or more of the outstanding shares entitled to vote thereat.  Such meetings may be held within or without the State of New Jersey at such time and place as may be specified in the notice thereof.

Section 3.   Notice of Meetings.

Written notice stating the time, place, if any, and purposes of a meeting of the shareholders, and the means, if any, by which shareholders can be present and vote at the meeting through the use of communications equipment shall be given by personal delivery, or by mail, facsimile transmission, overnight delivery service, or any other means of communication authorized by the shareholder to whom the notice is given, not less than ten nor more than sixty days before the date of the meeting.  Such notice may be given by or at the direction of the Chairman of the Board, the President or the Corporate Secretary.  Notices sent by mail shall be sent postage prepaid and shall be addressed to each shareholder at his address as it appears upon the records of the Corporation.  Notice by mail shall be deemed to be given at the time when the notice is deposited in the mail, notice by personal delivery or by overnight delivery service shall be deemed to be given when received, and notice by facsimile, or other electronic communications shall be deemed to be given at the time when confirmation of successful transmission is received.  Any shareholder may waive in writing notice of any meeting, either before or after the holding of such meeting, and by attending any meeting without protesting the lack of proper notice, shall be deemed to have waived notice thereof.

Section 4.   Business Transacted at Meetings.

Business transacted at any meeting of shareholders shall be for the purposes stated in the notice.

Section 5.   Quorum and Adjournments.

The holders of a majority of the stock issued and outstanding and entitled to vote thereat, present in person or represented by proxy, shall constitute a quorum at all meetings of the shareholders for the transaction of business except as otherwise provided by statute or by the Certificate of Incorporation.  If, however, such quorum shall not be present or represented at any meeting of the shareholders, the shareholders entitled to vote thereat, present in person or represented by proxy, shall have power to adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum shall be present or represented.  At such adjourned meeting at which a quorum shall be present or represented, any business may be transacted which might have been transacted at the meeting as originally notified.

Section 6.   Required Vote; Inspectors.

(a)           When a quorum is present or represented at any meeting, the vote of the holders of a majority of the stock having voting power present in person or represented by proxy shall decide any question brought before such meeting, unless the question is one upon which by express provision of the statutes or of the Certificate of Incorporation a different vote is required in which case such express provision shall govern and control the decision of such question.

(b)           Inspectors of election may be appointed to act at any meeting of shareholders in accordance with New Jersey law.

Section 7.   Voting Power of Shareholders.

Every shareholder of record of the Corporation shall be entitled at each meeting of shareholders to one vote for each share of stock held by such shareholder according to the books of the Corporation as of the date of such vote or, if a record date is set by the Board of Directors, as of such record date.

Section 8.   Voting by Proxy.

At any meeting of the shareholders, any shareholder may be represented and vote by a proxy or proxies appointed by an instrument in writing or by any other form of verifiable communication, including any form of electronic or other communications, to the full extent legally permitted (now or hereafter).  In the event that any such instrument shall designate two or more persons to act as proxies, a majority of such persons present at the meeting, or, if only one shall be present, then that one shall have and may exercise all of the powers conferred by such instrument upon all of the persons so designated unless the instrument shall otherwise provide.  No such proxy shall be valid after the expiration of eleven (11) months from the date of its execution, unless coupled with an interest, or unless the person executing it specifies therein the length of time for which it is to continue in force.  Subject to the above, any proxy duly executed is not revoked and continues in full force and effect until an instrument or verifiable communication revoking it or a duly executed proxy bearing a later date is filed with the Corporate Secretary of the Corporation.

Section 9.   Participation by Shareholders Through Communications Equipment.

If authorized by the Directors, the shareholders and proxyholders who are not physically present at a meeting of shareholders may attend a meeting of shareholders by use of communications equipment that enables the shareholder or proxyholder an opportunity to participate in the meeting and to vote on matters submitted to the shareholders, including an opportunity to read or hear the proceedings of the meeting and to speak or otherwise participate in the proceedings contemporaneously with those physically present.

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Section 10.   Action by Shareholders Without a Meeting.

Any action which may be taken by the vote of the shareholders at a meeting may be taken without a meeting if authorized by a writing or writings signed by all of the holders of shares who would be entitled to notice of a meeting for such purpose.  Such written consent shall be filed with or entered upon the records of the Corporation.

DIRECTORS

Section 11.   Authority of Directors.

The business of the Corporation shall be managed by its Board of Directors, which may exercise all such powers of the Corporation and do all such lawful acts and things as are not by statute, the Certificate of Incorporation, or these By-laws directed or required to be exercised or done by the shareholders.

Section 12.   Number; Qualifications.

The number of Directors shall be not less than five (5) and not more than eleven (11) (plus any Directors separately elected by the holders of any class of stock other than the Common Stock as provided in the Certificate of Incorporation as amended from time to time).  The number of Directors may be determined (a) by the vote of the holders of a majority of the shares entitled to vote thereon at any annual meeting or special meeting called for the purpose of electing Directors or (b) by action of the Board of Directors at a meeting by the vote of a majority of the Directors in office at the time or in a writing signed by all the Directors in office at the time.  When so fixed, such number shall continue to be the authorized number of Directors until changed by the shareholders or Directors in the manner described above.  Any increase in the number of Directors shall be deemed to create a vacancy or vacancies which may be filled as provided in Section 15.  A reduction in the number of Directors shall not be applied to remove any Director from office prior to the expiration of his term.  Directors need not be shareholders of the Corporation.

Section 13.   Election of Directors.

At each meeting of the shareholders for the election of Directors, the persons receiving the greatest number of votes shall be the Directors.  Such elections shall be by ballot whenever requested by any person entitled to vote at such meeting; but unless so requested, such election may be conducted in any way approved at such meeting.

Section 14.   Term of Office; Removal; Resignations.

(a)           Directors shall hold office until the annual meeting of the shareholders next following their election and until their respective successors are elected, or until their earlier resignation, death or removal from office.

(b)           Any Director or the entire Board of Directors may be removed upon the affirmative vote of the holders of a majority of the voting power of the Corporation.

(c)           Any Director may resign at any time by giving written notice of his resignation to the President or Corporate Secretary.  Any resignation will be effective upon actual receipt by such person or, if later, as of the date and time specified in such written notice.

 -

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Section 15.   Vacancies.

Vacancies, including those caused by an increase in the number of Directors, may be filled by a majority of the remaining Directors though less than a quorum.  When one or more Directors shall give notice of his or their resignation to the Board, effective at a future date, the Board shall have the power to fill such vacancy or vacancies to take effect when such resignation or resignations shall become effective, each Director so appointed to hold office during the remainder of the term of office of the resigning Director or Directors.  Whenever any vacancy shall occur among the Directors, the remaining Directors shall constitute the Directors of the Corporation until such vacancy is filled or until the number of Directors is changed as in Section 12 hereof.

MEETINGS OF THE BOARD OF DIRECTORS

Section 16.   Organizational Meeting.

Immediately after each annual meeting of the shareholders at which Directors are elected, or each special meeting held in lieu thereof, the newly elected Directors, if a quorum thereof is present, shall hold an organizational meeting at the same place or at such other time and place as may be fixed by the shareholders at such meeting, for the purpose of electing officers and transacting any other business.  Notice of such meeting need not be given.  If for any reason such organizational meeting is not held at such time, a special meeting of the Directors for such purpose shall be held as soon thereafter as practicable.

Section 17.   Special Meetings.

Special meetings of the Directors may be held at any time within or without the State of New Jersey upon call by the Chairman of the Board, the President, or the Corporate Secretary upon the written request of two Directors.

Notice of the place, if any, and time of each meeting of the Directors shall be given to each Director either by personal delivery or by mail, facsimile transmission, overnight delivery service, or any other means of communication authorized by the Director, at least twenty-four hours before the meeting. The notice need not specify the purposes of the meeting.  Notices sent by mail shall be sent postage prepaid and shall be addressed to each Director at his address as it appears upon the records of the Corporation.  Notice by mail shall be deemed to be given at the time when the notice is deposited in the mail, notice by personal delivery or by overnight delivery service shall be deemed to be given when received, and notice by facsimile, or other electronic communications shall be deemed to be given at the time when confirmation of successful transmission is received.  Such notice may be waived in writing by Directors either before or after the meeting, and such written waivers shall be filed with or entered upon the records of the meeting.  The attendance of any Director at any such meeting without protesting the lack of proper notice, prior to or at the commencement of the meeting, shall be deemed to be a waiver by the Director of notice of the meeting.  Unless otherwise limited in the notice thereof, any business may be transacted at any organizational, regular or special meeting.

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Section 18.   Quorum and Adjournments; Participation by Communications Equipment.

(a)           A majority of the Directors, at a meeting duly called and held, shall be necessary to constitute a quorum for the transaction of business and the act of a majority of the Directors present at any meeting at which a quorum is present shall be the act of the Board of Directors, except as may be otherwise specifically provided by statute or by the Certificate of Incorporation.  Any action required or permitted to be taken at a meeting of the Directors may be taken without a meeting if a consent in writing, setting forth the action so taken, shall be signed by all of the Directors entitled to vote with respect to the subject matter thereof.  Any meeting duly called, whether or not a quorum is present, may, by vote of a majority of the Directors present, be adjourned from time to time and place to place within or without the State of New Jersey, in which case no further notice of the adjourned meeting need be given.

(b)           Meetings of the Board of Directors or of any committee of the Board of Directors may be held through any means of communications equipment if all persons participating can hear each other, and such participation will constitute presence in person at such meeting.

Section 19.   Committees.

The Board of Directors may, by resolution passed by a majority of the Directors, designate one or more committees, each committee to consist of one or more of the Directors of the Corporation, which, to the extent provided in the resolution, shall have and may exercise the powers of the Board of Directors in the management of the business and affairs of the Corporation except that no such committee shall a) make, alter or repeal any by-law of the corporation; b) elect or appoint any Director, or remove any officer or Director; c) submit to shareholders any action that requires shareholders’ approval; or d) amend or repeal any resolution theretofore adopted by the board which by its terms is amendable or repealable only by the board. Such committee or committees shall have such name or names as may be determined from time to time by resolution adopted by the Board of Directors.  The committees shall keep regular minutes of their proceedings and report the same to the Board when required.

Section 20.   Compensation.

The Directors may be paid their expenses, if any, for attendance at each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors.  The sums may be different for different Directors, and the sum shall be established by resolution of the Board of Directors and may be changed from time to time by resolution.  No such payment shall preclude any Director from serving the Corporation in any other capacity and receiving compensation therefor.  Members of special or standing committees may be allowed like compensation for attending committee meetings.

Section 21.   Action by Directors Without a Meeting.

Any action required or permitted to be taken at a meeting of the Board of Directors or any committee of the Board of Directors may be taken without a meeting if, prior or subsequent to such action, all members of the Board of Directors or of such committee, as the case may be, consent thereto in writing and such written consents are filed with the Corporate Secretary of the Corporation.

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EXECUTIVE COMMITTEE

Section 22.   Executive Committee.

The Board of Directors at any time may elect from its members an Executive Committee which shall consist of not less than three (3) members.  Each member of such Committee shall hold office during the pleasure of the Board and may be removed by a majority vote of the whole Board at any time with or without cause.  Vacancies occurring in the Committee may be filled by the Board.  The Committee shall prescribe its own rules for calling and holding meetings, and for transacting business, subject, however, to any rules prescribed by the Board of Directors, and the Committee shall keep minutes of its actions.  Action by the Committee may be taken at meetings thereof attended by not less than a majority thereof, or without a meeting by instrument in writing signed by not less than a majority of the members.  Except as the Committee’s powers and duties may be limited or otherwise prescribed by the Board of Directors, the Committee, during the intervals between the meetings of the Board, shall possess and may exercise all of the powers and authority of the Board of Directors, however conferred, provided, however, that the Committee shall not be empowered to elect the officers (other than Assistant Secretaries and Assistant Treasurers) or to fill vacancies in the Board of Directors or in the Executive Committee.  Subject to such exceptions, persons dealing with the Corporation shall be entitled to rely upon any action of the Committee with the same force and effect as though such action had been taken by the Board of Directors.

OFFICERS

Section 23.   Generally.

The Corporation may have a Chairman, elected by the Directors from among their number, and shall have a President, a Corporate Secretary and a Treasurer.   The Corporation may also have one or more Vice Chairmen, Vice Presidents, Senior Vice Presidents and such other officers and assistant officers as the Board of Directors may deem appropriate.  If the Board of Directors so desires, it may elect a Chief Executive Officer to manage the affairs of the Corporation, subject to the direction and control of the Board of Directors.  All of the officers shall be elected by the Board of Directors.  Notwithstanding the foregoing, by specific action, the Board of Directors may authorize the Chairman or the President to appoint any person to any office other than Chairman, President, Corporate Secretary, or Treasurer.  Any number of offices may be held by the same person, and no two offices must be held by the same person.  Any of the offices may be left vacant from time to time as the Board of Directors may determine.  In case of the absence or disability of any officer of the Corporation or for any other reason deemed sufficient by a majority of the Board of Directors, the Board of Directors may delegate the absent or disabled officer's powers or duties to any other officer or to any Director.

Section 24.  Authority and Duties of Officers.  

The officers of the Corporation shall have such authority and shall perform such duties as are customarily incident to their respective offices, or as may be specified from time to time by the Board of Directors, the Chairman or the President regardless of whether such authority and duties are customarily incident to such office.

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Section 25.Compensation.  

The compensation of all officers and agents of the Corporation who are also members of the Board of Directors of the Corporation will be fixed by the Board of Directors or by a committee of the Board of Directors.  The Board of Directors may fix, or delegate the power to fix, the compensation of the other officers and agents of the Corporation to the Chief Executive Officer or any other officer of the Corporation.

Section 26.    Succession.  

The officers of the Corporation will hold office until their successors are elected.  Any officer may be removed at any time by the affirmative vote of a majority of the whole Board.  Any vacancy occurring in any office of the Corporation may be filled by the Board of Directors or by the Chairman or President as provided in Section 23.

Section 27.   Delegation of Duties.

The Directors are authorized to delegate the duties of any officers to any other officer and generally to control the action of the officers and to require the performance of duties in addition to those mentioned herein.

SHARES CERTIFICATES

Section 28.   Transfer and Registration of Certificates

The Board of Directors shall have authority to make such rules and regulations, not inconsistent with law, the Certificate of Incorporation, or these By-laws, as it deems expedient concerning the issuance, transfer, and registration of certificates for shares and the shares represented thereby and may appoint transfer agents and registrars thereof.  The Directors may provide by resolution that some or all of any or all classes and series of shares shall be uncertificated shares, subject to any disclosure obligations therefor under section 14A:7-11 of the New Jersey Statutes, and provided that any then-outstanding shares of that class or series represented by a certificate shall not become uncertificated shares until the certificate is surrendered to the Corporation.

Section 29.   Substituted Certificates

Any person claiming that a certificate for shares has been lost, stolen, or destroyed shall make an affidavit or affirmation of that fact and, if required, shall give the Corporation (and its registrar or registrars and its transfer agent or agents, if any) a bond of indemnity, in such form and with one (1) or more sureties satisfactory to the Board, and, if required by the Board of Directors, shall advertise the same in such manner as the Board of Directors may require, whereupon a new certificate may be executed and delivered of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, or destroyed.

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RECORD DATES AND CLOSING OF TRANSFER BOOKS

Section 30.   Record Dates and Closing of Transfer Books.

The Board of Directors may fix a time not less than ten (10) and not exceeding sixty (60) days preceding the date of any meeting of shareholders or the date fixed for the payment of any dividend or distribution or the date for the allotment of rights as the record date for the determination of the shareholders entitled to notice of or to vote at any such meeting or entitled to receive payment of any such dividend, distribution or allotment of rights, and in such case only shareholders of record on the date so fixed shall be entitled to notice of or to vote at such meeting or to receive payment of such dividend, distribution or allotment of rights, as the case may be, notwithstanding any transfer of any shares on the books of the Corporation after any record date so fixed.  The Board of Directors may close the books of the Corporation against transfers of shares during the whole or any part of the period between such record date and the date of the event in respect for which such record date was fixed.

REGISTERED SHAREHOLDERS

Section 31.   Recognition of Record Ownership.

The Corporation shall be entitled to recognize the exclusive right of a person registered on its books as the owner of shares to receive dividends, and to vote as such owner, and to hold liable for calls and assessments a person registered on its books as the owner of shares, and shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of New Jersey.

GENERAL PROVISIONS

DIVIDENDS

Section 32.   Payment of Dividends.

The Board of Directors may declare dividends upon the capital stock of the Corporation, subject to the provisions of the Certificate of Incorporation, if any, at any regular or special meeting pursuant to law.  Dividends may be paid in cash, in property or in shares of the capital stock, subject to the provisions of the Certificate of Incorporation.  Before payment of any dividend, there may be set aside out of any funds of the Corporation available for dividends such sum or sums as the Directors from time to time, in their absolute discretion, think proper as a reserve or reserves to meet contingencies, or for equalizing dividends, or for repairing or maintaining any property of the Corporation, or for such other purpose as the Directors shall think conducive to the interest of the Corporation and the Directors may modify or abolish any such reserves in the manner in which it was created.

FISCAL YEAR

Section 33.   Fiscal Year.

The fiscal year of the Corporation shall be fixed by resolution of the Board of Directors.

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8

SEAL

Section 34.   Corporate Seal.

The Directors may adopt a corporate seal of the Corporation which shall be of such design, and shall contain such words, as may be prescribed by the Directors.  Failure to affix any such corporate seal shall not affect the validity of any instrument.

TRANSFER AGENT AND REGISTRAR

Section 35.   Transfer Agent; Registrar.

The Corporation may open transfer books in any state of the United States or in any foreign country for the purpose of transferring securities issued by it, and it may employ an agent or agents to keep the records of its securities to transfer or to register securities or both, in New Jersey or in other states or in a foreign country, or both, and the acts of such agents shall be binding on the Corporation.  The duties and liabilities of such agent or agents shall be such as may be agreed to by the Corporation.  If no such transfer agent is appointed to act in New Jersey in respect to its shares, the Corporation shall keep an office in New Jersey at which shares shall be transferable, and at which it shall keep books in which shall be recorded the names and addresses of all shareholders and all transfers of shares.

PROVISIONS IN CERTIFICATE OF INCORPORATION

Section 36.   Governance By Certificate of Incorporation.

These By-laws are at all times subject to the provisions of the Certificate of Incorporation of the Corporation (including in such term whenever used in these By-laws, amendments thereto), and in case of any conflict between any provision herein and in the Certificate of Incorporation, the provisions in the Certificate of Incorporation shall be deemed to govern.

AMENDMENTS

Section 37.  Procedure for Amendments.

These By-laws may be altered, amended, or repealed in any respect or superseded by new By-laws in whole or in part, (a) by the affirmative vote of the holders of record of shares entitling them to exercise a majority of the voting power of the Corporation at an annual or special meeting called for such purpose, or by their unanimous written consent; or (b) by the Board of Directors at an annual or special meeting called for such purpose, or by their unanimous written consent.

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INDEMNIFICATION AND INSURANCE

Section 38.   Indemnification.

The Corporation shall indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he or she is or was a director, officer, employee, or agent of the Corporation, or is or was serving at the request of the Corporation as a director, trustee, officer, employee, member, manager, or agent of another corporation, limited liability company, partnership, joint venture, trust or other enterprise, against expenses, including attorney’s fees, judgments, fines and amounts paid in settlement, actually and reasonably incurred by him or her in connection with such action, suit, or proceeding, if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, if he or she had no reasonable cause to believe his or her conduct was unlawful, to the full extent and according to the procedures and requirements set forth in the New Jersey General Corporation Law as now in effect or as amended from time to time.  The Corporation shall pay, to the full extent then permitted by law, expenses, including attorney’s fees, incurred by a member of the Board of Directors in defending any such action, suit or proceeding as they are incurred, in advance of the final disposition thereof, and may pay, in the same manner and to the full extent then permitted by law, such expenses incurred by any other person.

The indemnification and payment of expenses provided hereby shall not be exclusive of, and shall be in addition to, any other rights granted to those seeking indemnification under any law, the Certificate of Incorporation, any agreement, vote of shareholders or disinterested members of the Board of Directors, or otherwise, both as to action in official capacities and as to action in another capacity while he or she is a member of the Board of Directors, or an officer, employee or agent of the Corporation, and shall continue as to a person who has ceased to be a member of the Board of Directors, officer, employee or agent and shall inure to the benefit of the heirs, executors and administrators of such a person.

Section 39.   Insurance.

The Corporation may, to the full extent then permitted by law and authorized by the Board of Directors, purchase and maintain insurance or furnish similar protection, including but not limited to trust funds, letters of credit or self-insurance, on behalf of or for any persons described in Section 38 against any liability asserted against and incurred by any such person in any such capacity, or arising out of his status as such, whether or not the Corporation would have the power to indemnify such person against such liability.  Insurance may be purchased from or maintained with a person in which the Corporation has a financial interest.

EMERGENCY BY-LAWS

Section 40.   Emergency By-laws.

The Board of Directors may adopt, at any meeting, emergency by-laws to be operative during, but only during, an emergency.  The emergency by-laws may contain any provisions which may be made by emergency by-laws as provided in Section 14A:2-10 of the New Jersey Statutes.

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EX-12.6

											EXHIBIT 12.6
											Page 1
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
		Year Ended December 31,
			2003		2004		2005		2006		2007
		(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	64,277	$	107,626	$	182,927	$	190,607	$	186,108
Interest and other charges, before reduction for amounts capitalized
	and deferred		96,290		86,111		85,519		94,035		107,232
Provision for income taxes			48,609		97,205		135,846		146,731		149,056
Interest element of rentals charged to income (a)			5,374		7,589		7,091		8,838		7,976
	Earnings as defined	$	214,550	$	298,531	$	411,383	$	440,211	$	450,372
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred		$	90,943	$	86,111	$	85,519	$	94,035	$	107,232
Subsidiary's preferred stock dividend requirements			5,347		-		-		-		-
Interest element of rentals charged to income (a)			5,374		7,589		7,091		8,838		7,976
	Fixed charges as defined	$	101,664	$	93,700	$	92,610	$	102,873	$	115,208
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES			2.11		3.19		4.44		4.28		3.91
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

											EXHIBIT 12.6
											Page 2
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS
PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)
		Year Ended December 31,
			2003		2004		2005		2006		2007
		(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	64,277	$	107,626	$	182,927	$	190,607	$	186,108
Interest and other charges, before reduction for amounts capitalized
	and deferred		96,290		86,111		85,519		94,035		107,232
Provision for income taxes			48,609		97,205		135,846		146,731		149,056
Interest element of rentals charged to income (a)			5,374		7,589		7,091		8,838		7,976
	Earnings as defined	$	214,550	$	298,531	$	411,383	$	440,211	$	450,372
FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS
	PREFERRED STOCK DIVIDEND REQUIREMENTS
	(PRE-INCOME TAX BASIS):
Interest before reduction for amounts capitalized and deferred		$	90,943	$	86,111	$	85,519	$	94,035	$	107,232
Preferred stock dividend requirements			5,235		500		500		1,018		-
Adjustments to preferred stock dividends
	to state on a pre-income tax basis		(85)		452		371		784		-
Interest element of rentals charged to income (a)			5,374		7,589		7,091		8,838		7,976
Fixed charges as defined plus preferred stock
	dividend requirements (pre-income tax basis)	$	101,467	$	94,652	$	93,481	$	104,675	$	115,208
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS
	(PRE-INCOME TAX BASIS)		2.11		3.15		4.40		4.21		3.91
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

EX-3.9

AMENDED AND RESTATED

ARTICLES OF INCORPORATION

OF

METROPOLITAN EDISON COMPANY

Charter Number 229978

(effective December 19, 2007)

ARTICLE I

The name of the corporation is METROPOLITAN EDISON COMPANY (hereinafter referred to as the “Corporation”).

ARTICLE II

The place in the Commonwealth of Pennsylvania where the registered office of the Corporation is located is:

      2800 Pottsville Pike

                                                           Muhlenberg Township

                                                           Berks County, Pennsylvania  19605

ARTICLE III

The purpose or purposes for which the Corporation is incorporated is as follows:

A.            To generate, produce, acquire, transmit, distribute, furnish, sell, and supply electricity to public and private consumers; and

B.            To engage in any other lawful business for which corporations may be incorporated under the Pennsylvania Business Corporation Law of 1988, as amended.

ARTICLE IV

The aggregate number of shares which the Corporation is authorized to issue shall be ten million nine hundred thousand (10,900,000) shares, classified as follows:

A.            Common Stock, nine hundred thousand (900,000) shares, without par value;

B.            Preferred Stock, ten million (10,000,000) shares, without par value, and having a maximum aggregate stated value of $250,000,000.

ARTICLE V

The Board of Directors may adopt an amendment to these Articles of Incorporation determining, in whole or in part, the express terms, within the limits set forth in these Articles of Incorporation or the Pennsylvania Business Corporation Law, of any class of shares before the issuance of any shares of that class, or of one or more series within a class before the issuance of shares of that series; including, without limitation, division of shares into classes or into series within any class or classes, determination of the designation and the number of shares of any class or series, and the determination of the relative voting rights, preferences, limitations, rights to dividends, conversion rights, redemption rights, stated value, and other special rights of the shares of any class or series.  The Board of Directors may provide by resolution that any or all classes and series of shares, or any part thereof, may be uncertificated shares, provided that any then-outstanding shares of that class or series represented by a certificate shall not become uncertificated shares until the certificate is surrendered to the Corporation. [15 Pa.C.S. 1528]

ARTICLE VI

A director shall not be personally liable, as such, for monetary damages for any action taken unless: (A) the director has breached or failed to perform the duties of his office under the Articles of Incorporation or the Bylaws of the Corporation, or the Pennsylvania Business Corporation Law; and (B) the breach or failure to perform constitutes self-dealing, willful misconduct or recklessness. This Article shall not apply to: (i) the responsibility or liability of a director pursuant to any criminal statute; or (ii) the liability of a director for the payment of taxes pursuant to Federal, State or local law. [15 Pa.C.S. §1713]

ARTICLE VII

The Corporation may purchase its shares, regardless of class, from time to time, to such extent, in such manner, and upon such terms as its Board of Directors shall determine. [15 Pa.C.S. §1551]

ARTICLE VIII

The shareholders shall have no right to vote cumulatively in the election of Directors.

ARTICLE IX

The Corporation was incorporated on July 24, 1922 under the Corporation Act of 1874, as amended and supplemented.

ARTICLE X

These Amended and Restated Articles of Incorporation take the place of and supersede the original articles of incorporation and all amendments thereto.

EX-3.10

AMENDED AND RESTATED

BYLAWS

OF

METROPOLITAN EDISON COMPANY

December 14, 2007

MEETINGS OF SHAREHOLDERS

Section 1.   Annual Meetings.

The annual meeting of shareholders shall be held on such date and at such time as the Board of Directors may determine each year.  Such meetings may be held within or without the Commonwealth of Pennsylvania at such time and place as the Directors may determine.  The Directors may determine that the meeting shall not be held at any physical place, but instead may be held solely by means of communications equipment as authorized by Section 9 below.

Section 2.   Special Meetings.

Special meetings of the shareholders may be called at any time by (i) the Chairman of the Board, (ii) the President, (iii) the Directors, by action at a meeting or a majority of the Directors acting without a meeting, or (iv) the holders of 20% or more of the outstanding shares entitled to vote thereat.  Such meetings may be held within or without the Commonwealth of Pennsylvania at such time and place as may be specified in the notice thereof.

Section 3.   Notice of Meetings.

Written notice stating the time, place, if any, and purposes of a meeting of the shareholders, and the means, if any, by which shareholders can be present and vote at the meeting through the use of communications equipment shall be given by personal delivery, or by mail, facsimile transmission, overnight delivery service, or any other means of communication authorized by the shareholder to whom the notice is given, not less than five days before the date of the meeting, unless the meeting will consider a fundamental change as described in The Pennsylvania Consolidated Statutes at Chapter 19 in which case not less than ten days notice is required.  Such notice may be given by or at the direction of the Chairman of the Board, the President or the Corporate Secretary.  Notices sent by mail shall be sent postage prepaid and shall be addressed to each shareholder at his address as it appears upon the records of the Corporation.  Notice by mail shall be deemed to be given at the time when the notice is deposited in the mail, notice by personal delivery or by overnight delivery service shall be deemed to be given when deposited, and notice by facsimile, or other electronic communications shall be deemed to be given at the time when confirmation of successful transmission is received.  Any shareholder may waive in writing notice of any meeting, either before or after the holding of such meeting, and by attending any meeting without protesting the lack of proper notice, shall be deemed to have waived notice thereof.

Section 4.   Business Transacted at Meetings.

Business transacted at any meeting of shareholders shall be for the purposes stated in the notice.

Section 5.   Quorum and Adjournments.

The holders of a majority of the stock issued and outstanding and entitled to vote thereat, present in person or represented by proxy, shall constitute a quorum at all meetings of the shareholders for the transaction of business except as otherwise provided by statute or by the Articles of Incorporation.  If, however, such quorum shall not be present or represented at any meeting of the shareholders, the shareholders entitled to vote thereat, present in person or represented by proxy, shall have power to adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum shall be present or represented.  At such adjourned meeting at which a quorum shall be present or represented, any business may be transacted which might have been transacted at the meeting as originally notified.

Section 6.   Required Vote; Judges.

(a)            When a quorum is present or represented at any meeting, the vote of the holders of a majority of the stock having voting power present in person or represented by proxy shall decide any question brought before such meeting, unless the question is one upon which by express provision of the statutes or of the Articles of Incorporation a different vote is required in which case such express provision shall govern and control the decision of such question.

(b)            Judges of election may be appointed to act at any meeting of shareholders in accordance with Pennsylvania law.

Section 7.   Voting Power of Shareholders.

Every shareholder of record of the Corporation shall be entitled at each meeting of shareholders to one vote for each share of stock held by such shareholder according to the books of the Corporation as of the date of such vote or, if a record date is set by the Board of Directors, as of such record date.

Section 8.   Voting by Proxy.

                 At any meeting of the shareholders, any shareholder may be represented and vote by a proxy or proxies appointed by an instrument in writing or by any other form of verifiable communication, including any form of electronic or other communications, to the full extent legally permitted (now or hereafter).  In the event that any such instrument shall designate two or more persons to act as proxies, a majority of such persons present at the meeting, or, if only one shall be present, then that one shall have and may exercise all of the powers conferred by such instrument upon all of the persons so designated unless the instrument shall otherwise provide.  No such proxy shall be valid after the expiration of three (3) years from the date of its execution, unless coupled with an interest, or unless the person executing it specifies therein the length of time for which it is to continue in force.  Subject to the above, any proxy duly executed is not revoked and continues in full force and effect until an instrument or verifiable communication revoking it or a duly executed proxy bearing a later date is filed with the Corporate Secretary of the Corporation.

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Section 9.   Participation by Shareholders Through Communications Equipment.

                 If authorized by the Directors, the shareholders and proxyholders who are not physically present at a meeting of shareholders may attend a meeting of shareholders by use of communications equipment that enables the shareholder or proxyholder an opportunity to participate in the meeting and to vote on matters submitted to the shareholders, including an opportunity to read or hear the proceedings of the meeting and to speak or otherwise participate in the proceedings contemporaneously with those physically present.

Section 10.   Action by Shareholders Without a Meeting.

Any action which may be taken by the vote of the shareholders at a meeting may be taken without a meeting if authorized by a writing or writings signed by all of the holders of shares who would be entitled to notice of a meeting for such purpose.  Such written consent shall be filed with or entered upon the records of the Corporation.

DIRECTORS

Section 11.   Authority of Directors.

The business of the Corporation shall be managed by its Board of Directors, which may exercise all such powers of the Corporation and do all such lawful acts and things as are not by statute, the Articles of Incorporation, or these Bylaws directed or required to be exercised or done by the shareholders.

Section 12.   Number; Qualifications.

The number of Directors shall be not less than three (3) and not more than ten (10) (plus any Directors separately elected by the holders of any class of stock other than the Common Stock as provided in the Articles of Incorporation as amended from time to time).  The number of Directors may be determined (a) by the vote of the holders of a majority of the shares entitled to vote thereon at any annual meeting or special meeting called for the purpose of electing Directors or (b) by action of the Board of Directors at a meeting by the vote of a majority of the Directors in office at the time or in a writing signed by all the Directors in office at the time.  When so fixed, such number shall continue to be the authorized number of Directors until changed by the shareholders or Directors in the manner described above.  Any increase in the number of Directors shall be deemed to create a vacancy or vacancies which may be filled as provided in Section 15.  A reduction in the number of Directors shall not be applied to remove any Director from office prior to the expiration of his term.  Directors need not be shareholders of the Corporation.

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Section 13.   Election of Directors.

At each meeting of the shareholders for the election of Directors, the persons receiving the greatest number of votes shall be the Directors.  Such elections shall be by ballot whenever requested by any person entitled to vote at such meeting; but unless so requested, such election may be conducted in any way approved at such meeting.

Section 14.   Term of Office; Removal; Resignations.

(a)            Directors shall hold office until the annual meeting of the shareholders next following their election and until their respective successors are elected, or until their earlier resignation, death or removal from office.

(b)            Any Director or the entire Board of Directors may be removed upon the affirmative vote of the holders of a majority of the voting power of the Corporation.

(c)            Any Director may resign at any time by giving written notice of his resignation to the President or Corporate Secretary. Any resignation will be effective upon actual receipt by such person or, if later, as of the date and time specified in such written notice.

Section 15.   Vacancies.

Vacancies, including those caused by an increase in the number of Directors, may be filled by a majority of the remaining Directors though less than a quorum.  When one or more Directors shall give notice of his or their resignation to the Board, effective at a future date, the Board shall have the power to fill such vacancy or vacancies to take effect when such resignation or resignations shall become effective, each Director so appointed to hold office during the remainder of the term of office of the resigning Director or Directors.  Whenever any vacancy shall occur among the Directors, the remaining Directors shall constitute the Directors of the Corporation until such vacancy is filled or until the number of Directors is changed as in Section 12 hereof.

MEETINGS OF THE BOARD OF DIRECTORS

Section 16.   Organizational Meeting.

Immediately after each annual meeting of the shareholders at which Directors are elected, or each special meeting held in lieu thereof, the newly elected Directors, if a quorum thereof is present, shall hold an organizational meeting at the same place or at such other time and place as may be fixed by the shareholders at such meeting, for the purpose of electing officers and transacting any other business.  Notice of such meeting need not be given.  If for any reason such organizational meeting is not held at such time, a special meeting of the Directors for such purpose shall be held as soon thereafter as practicable.

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Section 17.   Special Meetings.

Special meetings of the Directors may be held at any time within or without the Commonwealth of Pennsylvania upon call by the Chairman of the Board, the President, or the Corporate Secretary upon the written request of two Directors.

Notice of the place, if any, and time of each meeting of the Directors shall be given to each Director either by personal delivery or by mail, facsimile transmission, overnight delivery service, or any other means of communication authorized by the Director, at least two days before the meeting. The notice need not specify the purposes of the meeting.  Notices sent by mail shall be sent postage prepaid and shall be addressed to each Director at his address as it appears upon the records of the Corporation.  Notice by mail shall be deemed to be given at the time when the notice is deposited in the mail, notice by personal delivery or by overnight delivery service shall be deemed to be given when received, and notice by facsimile, or other electronic communications shall be deemed to be given at the time when confirmation of successful transmission is received.  Such notice may be waived in writing by Directors either before or after the meeting, and such written waivers shall be filed with or entered upon the records of the meeting.  The attendance of any Director at any such meeting without protesting the lack of proper notice, prior to or at the commencement of the meeting, shall be deemed to be a waiver by the Director of notice of the meeting.  Unless otherwise limited in the notice thereof, any business may be transacted at any organizational, regular or special meeting.

Section 18.   Quorum and Adjournments; Participation by Communications Equipment.

(a)            A majority of the Directors, at a meeting duly called and held, shall be necessary to constitute a quorum for the transaction of business and the act of a majority of the Directors present at any meeting at which a quorum is present shall be the act of the Board of Directors, except as may be otherwise specifically provided by statute or by the Articles of Incorporation. Any action required or permitted to be taken at a meeting of the Directors may be taken without a meeting if a consent in writing, setting forth the action so taken, shall be signed by all of the Directors entitled to vote with respect to the subject matter thereof. Any meeting duly called, whether or not a quorum is present, may, by vote of a majority of the Directors present, be adjourned from time to time and place to place within or without the Commonwealth of Pennsylvania, in which case no further notice of the adjourned meeting need be given.

(b)            Meetings of the Board of Directors or of any committee of the Board of Directors may be held through any means of communications equipment if all persons participating can hear each other, and such participation will constitute presence in person at such meeting.

Section 19.   Committees.

The Board of Directors may, by resolution passed by a majority of the Directors, designate one or more committees, each committee to consist of one or more of the Directors of the Corporation, which, to the extent provided in the resolution, shall have and may exercise the powers of the Board of Directors in the management of the business and affairs of the Corporation.  Such committee or committees shall have such name or names as may be determined from time to time by resolution adopted by the Board of Directors.  The committees shall keep regular minutes of their proceedings and report the same to the Board when required.

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Section 20.   Compensation.

The Directors may be paid their expenses, if any, for attendance at each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors.  The sums may be different for different Directors, and the sum shall be established by resolution of the Board of Directors and may be changed from time to time by resolution.  No such payment shall preclude any Director from serving the Corporation in any other capacity and receiving compensation therefor.  Members of special or standing committees may be allowed like compensation for attending committee meetings.

Section 21.   Action by Directors Without a Meeting.

Any action required or permitted to be taken at a meeting of the Board of Directors or any committee of the Board of Directors may be taken without a meeting if, prior or subsequent to such action, all members of the Board of Directors or of such committee, as the case may be, consent thereto in writing and such written consents are filed with the Corporate Secretary of the Corporation.

EXECUTIVE COMMITTEE

Section 22.   Executive Committee.

The Board of Directors at any time may elect from its members an Executive Committee which shall consist of not less than three (3) members.  Each member of such Committee shall hold office during the pleasure of the Board and may be removed by a majority vote of the whole Board at any time with or without cause.  Vacancies occurring in the Committee may be filled by the Board.  The Committee shall prescribe its own rules for calling and holding meetings, and for transacting business, subject, however, to any rules prescribed by the Board of Directors, and the Committee shall keep minutes of its actions.  Action by the Committee may be taken at meetings thereof attended by not less than a majority thereof, or without a meeting by instrument in writing signed by not less than a majority of the members.  Except as the Committee’s powers and duties may be limited or otherwise prescribed by the Board of Directors, the Committee, during the intervals between the meetings of the Board, shall possess and may exercise all of the powers and authority of the Board of Directors, however conferred, provided, however, that the Committee shall not be empowered to elect the officers (other than Assistant Secretaries and Assistant Treasurers) or to fill vacancies in the Board of Directors or in the Executive Committee.  Subject to such exceptions, persons dealing with the Corporation shall be entitled to rely upon any action of the Committee with the same force and effect as though such action had been taken by the Board of Directors.

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OFFICERS

Section 23.   Generally.

The Corporation may have a Chairman, elected by the Directors from among their number, and shall have a President, a Corporate Secretary and a Treasurer.   The Corporation may also have one or more Vice Chairmen, Vice Presidents, Senior Vice Presidents and such other officers and assistant officers as the Board of Directors may deem appropriate.  If the Board of Directors so desires, it may elect a Chief Executive Officer to manage the affairs of the Corporation, subject to the direction and control of the Board of Directors.  All of the officers shall be elected by the Board of Directors.  Notwithstanding the foregoing, by specific action, the Board of Directors may authorize the Chairman or the President to appoint any person to any office other than Chairman, President, Corporate Secretary, or Treasurer.  Any number of offices may be held by the same person, and no two offices must be held by the same person.  Any of the offices may be left vacant from time to time as the Board of Directors may determine.  In case of the absence or disability of any officer of the Corporation or for any other reason deemed sufficient by a majority of the Board of Directors, the Board of Directors may delegate the absent or disabled officer's powers or duties to any other officer or to any Director.

Section 24.  Authority and Duties of Officers.  

The officers of the Corporation shall have such authority and shall perform such duties as are customarily incident to their respective offices, or as may be specified from time to time by the Board of Directors, the Chairman or the President regardless of whether such authority and duties are customarily incident to such office.

Section 25.    Compensation.  

The compensation of all officers and agents of the Corporation who are also members of the Board of Directors of the Corporation will be fixed by the Board of Directors or by a committee of the Board of Directors.  The Board of Directors may fix, or delegate the power to fix, the compensation of the other officers and agents of the Corporation to the Chief Executive Officer or any other officer of the Corporation.

Section 26.   Succession.  

The officers of the Corporation will hold office until their successors are elected.  Any officer may be removed at any time by the affirmative vote of a majority of the whole Board.  Any vacancy occurring in any office of the Corporation may be filled by the Board of Directors or by the Chairman or President as provided in Section 23.

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Section 27.   Delegation of Duties.

The Directors are authorized to delegate the duties of any officers to any other officer and generally to control the action of the officers and to require the performance of duties in addition to those mentioned herein.

SHARES CERTIFICATES

Section 28.   Transfer and Registration of Certificates

The Board of Directors shall have authority to make such rules and regulations, not inconsistent with law, the Articles, or these Bylaws, as it deems expedient concerning the issuance, transfer, and registration of certificates for shares and the shares represented thereby and may appoint transfer agents and registrars thereof.  The Directors may provide by resolution that some or all of any or all classes and series of shares shall be uncertificated shares, provided that any then-outstanding shares of that class or series represented by a certificate shall not become uncertificated shares until the certificate is surrendered to the Corporation.

Section 29.   Substituted Certificates

Any person claiming that a certificate for shares has been lost, stolen, or destroyed shall make an affidavit or affirmation of that fact and, if required, shall give the Corporation (and its registrar or registrars and its transfer agent or agents, if any) a bond of indemnity, in such form and with one (1) or more sureties satisfactory to the Board, and if required by the Board of Directors, shall advertise the same in such manner as the Board of Directors may require, whereupon a new certificate may be executed and delivered of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, or destroyed.

RECORD DATES AND CLOSING OF TRANSFER BOOKS

Section 30.   Record Dates and Closing of Transfer Books.

The Board of Directors may fix a time not exceeding sixty (60) days preceding the date of any meeting of shareholders or the date fixed for the payment of any dividend or distribution or the date for the allotment of rights as the record date for the determination of the shareholders entitled to notice of or to vote at any such meeting or entitled to receive payment of any such dividend, distribution or allotment of rights, and in such case only shareholders of record on the date so fixed shall be entitled to notice of or to vote at such meeting or to receive payment of such dividend, distribution or allotment of rights, as the case may be, notwithstanding any transfer of any shares on the books of the Corporation after any record date so fixed.  The Board of Directors may close the books of the Corporation against transfers of shares during the whole or any part of the period between such record date and the date of the event in respect for which such record date was fixed.

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REGISTERED SHAREHOLDERS

Section 31.   Recognition of Record Ownership.

The Corporation shall be entitled to recognize the exclusive right of a person registered on its books as the owner of shares to receive dividends, and to vote as such owner, and to hold liable for calls and assessments a person registered on its books as the owner of shares, and shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of Pennsylvania.

GENERAL PROVISIONS

DIVIDENDS

Section 32.   Payment of Dividends.

The Board of Directors may declare dividends upon the capital stock of the Corporation, subject to the provisions of the Articles of Incorporation, if any, at any regular or special meeting pursuant to law.  Dividends may be paid in cash, in property or in shares of the capital stock, subject to the provisions of the Articles of Incorporation.  Before payment of any dividend, there may be set aside out of any funds of the Corporation available for dividends such sum or sums as the Directors from time to time, in their absolute discretion, think proper as a reserve or reserves to meet contingencies, or for equalizing dividends, or for repairing or maintaining any property of the Corporation, or for such other purpose as the Directors shall think conducive to the interest of the Corporation and the Directors may modify or abolish any such reserves in the manner in which it was created.

FISCAL YEAR

Section 33.   Fiscal Year.

The fiscal year of the Corporation shall be fixed by resolution of the Board of Directors.

SEAL

Section 34.   Corporate Seal.

The Directors may adopt a corporate seal of the Corporation which shall be of such design, and shall contain such words, as may be prescribed by the Directors.  Failure to affix any such corporate seal shall not affect the validity of any instrument.

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TRANSFER AGENT AND REGISTRAR

Section 35.   Transfer Agent; Registrar.

The Corporation may open transfer books in any state of the United States or in any foreign country for the purpose of transferring securities issued by it, and it may employ an agent or agents to keep the records of its securities to transfer or to register securities or both, in Pennsylvania or in other states or in a foreign country, or both, and the acts of such agents shall be binding on the Corporation.  The duties and liabilities of such agent or agents shall be such as may be agreed to by the Corporation.  If no such transfer agent is appointed to act in Pennsylvania in respect to its shares, the Corporation shall keep an office in Pennsylvania at which shares shall be transferable, and at which it shall keep books in which shall be recorded the names and addresses of all shareholders and all transfers of shares.

PROVISIONS IN ARTICLES OF INCORPORATION

Section 36.   Governance By Articles of Incorporation.

These Bylaws are at all times subject to the provisions of the Articles of Incorporation of the Corporation (including in such term whenever used in these Bylaws, amendments thereto), and in case of any conflict between any provision herein and in the Articles of Incorporation, the provisions in the Articles of Incorporation shall be deemed to govern.

AMENDMENTS

Section 37.  Procedure for Amendments.

These Bylaws may be altered, amended, or repealed in any respect or superseded by new Bylaws in whole or in part, (a) by the affirmative vote of the holders of record of shares entitling them to exercise a majority of the voting power of the Corporation at an annual or special meeting called for such purpose, or by their unanimous written consent; or (b) by the Board of Directors at an annual or special meeting called for such purpose, or by their unanimous written consent as provided in 15 Pa.C.S.A. § 1504b.

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INDEMNIFICATION AND INSURANCE

Section 38.   Indemnification.

The Corporation shall indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he or she is or was a director, officer, employee, or agent of the Corporation, or is or was serving at the request of the Corporation as a director, trustee, officer, employee, member, manager, or agent of another corporation, limited liability company, partnership, joint venture, trust or other enterprise, against expenses, including attorney’s fees, judgments, fines and amounts paid in settlement, actually and reasonably incurred by him or her in connection with such action, suit, or proceeding, if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, if he or she had no reasonable cause to believe his or her conduct was unlawful, to the full extent and according to the procedures and requirements set forth in the Pennsylvania General Corporation Law as now in effect or as amended from time to time.  The Corporation shall pay, to the full extent then permitted by law, expenses, including attorney’s fees, incurred by a member of the Board of Directors in defending any such action, suit or proceeding as they are incurred, in advance of the final disposition thereof, and may pay, in the same manner and to the full extent then permitted by law, such expenses incurred by any other person.

The indemnification and payment of expenses provided hereby shall not be exclusive of, and shall be in addition to, any other rights granted to those seeking indemnification under any law, the Articles of Incorporation, any agreement, vote of shareholders or disinterested members of the Board of Directors, or otherwise, both as to action in official capacities and as to action in another capacity while he or she is a member of the Board of Directors, or an officer, employee or agent of the Corporation, and shall continue as to a person who has ceased to be a member of the Board of Directors, officer, employee or agent and shall inure to the benefit of the heirs, executors and administrators of such a person.

Section 39.   Insurance.

The Corporation may, to the full extent then permitted by law and authorized by the Board of Directors, purchase and maintain insurance or furnish similar protection, including but not limited to trust funds, letters of credit or self-insurance, on behalf of or for any persons described in Section 38 against any liability asserted against and incurred by any such person in any such capacity, or arising out of his status as such, whether or not the Corporation would have the power to indemnify such person against such liability.  Insurance may be purchased from or maintained with a person in which the Corporation has a financial interest.

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EMERGENCY BYLAWS

Section 40.   Emergency Bylaws.

The Board of Directors may adopt, at any meeting, either before or during “an emergency” as that term is defined in 15 Pa.C.S.A. § 1509, emergency bylaws to be operative during, but only during, an emergency.  The emergency bylaws may contain any provisions which may be made by emergency bylaws as provided in 15 Pa.C.S.A. § 1509..

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EX-12.7

											EXHIBIT 12.7
											Page 1
METROPOLITAN EDISON COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
		Year Ended December 31,
			2003		2004		2005		2006 (b)		2007
		(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	60,953	$	66,955	$	45,919	$	(240,195)	$	95,463
Interest and other charges, before reduction for amounts capitalized
	and deferred		46,277		45,057		44,655		47,385		51,022
Provision for income taxes			44,006		38,217		30,084		77,326		68,270
Interest element of rentals charged to income (a)			437		1,401		1,597		1,616		2,160
	Earnings as defined	$	151,673	$	151,630	$	122,255	$	(113,868)	$	216,915
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred		$	42,498	$	45,057	$	44,655	$	47,385	$	51,022
Subsidiary's preferred stock dividend requirements			3,779		-		-		-		-
Interest element of rentals charged to income (a)			437		1,401		1,597		1,616		2,160
	Fixed charges as defined	$	46,714	$	46,458	$	46,252	$	49,001	$	53,182
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES			3.25		3.26		2.64		(2.32)		4.08
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.
	(b) The earnings as defined in 2006 would need to increase $162,869,000 for the fixed charge ratios to be 1.0.

										EXHIBIT 12.7
											Page 2
METROPOLITAN EDISON COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS
PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)
		Year Ended December 31,
			2003		2004		2005		2006 (b)			2007
		(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	60,953	$	66,955	$	45,919	$	(240,195)		$	95,463
Interest and other charges, before reduction for amounts capitalized
	and deferred		46,277		45,057		44,655		47,385			51,022
Provision for income taxes			44,006		38,217		30,084		77,326			68,270
Interest element of rentals charged to income (a)			437		1,401		1,597		1,616			2,160
	Earnings as defined	$	151,673	$	151,630	$	122,255	$	(113,868)		$	216,915
FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS
	PREFERRED STOCK DIVIDEND REQUIREMENTS
	(PRE-INCOME TAX BASIS):
Interest before reduction for amounts capitalized and deferred		$	42,498	$	45,057	$	44,655	$	47,385		$	51,022
Preferred stock dividend requirements			3,779		-		-		-			-
Adjustments to preferred stock dividends
	to state on a pre-income tax basis		-		-		-		-			-
Interest element of rentals charged to income (a)			437		1,401		1,597		1,616			2,160
Fixed charges as defined plus preferred stock
	dividend requirements (pre-income tax basis)	$	46,714	$	46,458	$	46,252	$	49,001		$	53,182
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS
	(PRE-INCOME TAX BASIS)		3.25		3.26		2.64		(2.32)			4.08
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.
	(b) The earnings as defined in 2006 would need to increase $162,869,000 for the fixed charge ratios to be 1.0.

EX-3.11

AMENDED AND RESTATED

ARTICLES OF INCORPORATION

OF

PENNSYLVANIA ELECTRIC COMPANY

Charter Number 272862

(effective December 19, 2007)

ARTICLE I

The name of the corporation is PENNSYLVANIA ELECTRIC COMPANY (hereinafter referred to as the “Corporation”).

ARTICLE II

The place in the Commonwealth of Pennsylvania where the registered office of the Corporation is located is:

     1001 Broad Street

     Johnstown, Pennsylvania   15907

     Cambria County

ARTICLE III

The purpose or purposes for which the Corporation is incorporated is as follows:

A.           To generate, produce, acquire, transmit, distribute, furnish, sell, and supply electricity to public and private consumers; and

B.           To engage in any other lawful business for which corporations may be incorporated under the Pennsylvania Business Corporation Law of 1988, as amended.

ARTICLE IV

The aggregate number of shares which the Corporation is authorized to issue shall be sixteen million eight hundred thirty-five thousand (16,835,000) shares, classified as follows:

A.           Common Stock, five million four hundred thousand (5,400,000) shares, with a par value of $20 per share;

B.           Preferred Stock, eleven million four hundred thirty-five thousand (11,435,000) shares, without par value, and having a maximum aggregate stated value of $250,000,000.

ARTICLE V

The Board of Directors may adopt an amendment to these Articles of Incorporation determining, in whole or in part, the express terms, within the limits set forth in these Articles of Incorporation or the Pennsylvania Business Corporation Law, of any class of shares before the issuance of any shares of that class, or of one or more series within a class before the issuance of shares of that series; including, without limitation, division of shares into classes or into series within any class or classes, determination of the designation and the number of shares of any class or series, and the determination of the relative voting rights, preferences, limitations, rights to dividends, conversion rights, redemption rights, stated value, and other special rights of the shares of any class or series.  The Board of Directors may provide by resolution that any or all classes and series of shares, or any part thereof, may be uncertificated shares, provided that any then-outstanding shares of that class or series represented by a certificate shall not become uncertificated shares until the certificate is surrendered to the Corporation. [15 Pa.C.S. 1528]

ARTICLE VI

A director shall not be personally liable, as such, for monetary damages for any action taken unless: (A) the director has breached or failed to perform the duties of his office under the Articles of Incorporation or the Bylaws of the Corporation, or the Pennsylvania Business Corporation Law; and (B) the breach or failure to perform constitutes self-dealing, willful misconduct or recklessness. This Article shall not apply to: (i) the responsibility or liability of a director pursuant to any criminal statute; or (ii) the liability of a director for the payment of taxes pursuant to Federal, State or local law. [15 Pa.C.S. §1713]

ARTICLE VII

The Corporation may purchase its shares, regardless of class, from time to time, to such extent, in such manner, and upon such terms as its Board of Directors shall determine. [15 Pa.C.S. §1551]

ARTICLE VIII

The shareholders shall have no right to vote cumulatively in the election of Directors.

ARTICLE IX

The Corporation was incorporated on June 10, 1919 under the Corporation Act of 1874, as amended and supplemented.

ARTICLE X

These Amended and Restated Articles of Incorporation take the place of and supersede the original articles of incorporation and all amendments thereto.

EX-3.12

AMENDED AND RESTATED

BYLAWS

OF

PENNSYLVANIA ELECTRIC COMPANY

December 14, 2007

MEETINGS OF SHAREHOLDERS

Section 1.   Annual Meetings.

The annual meeting of shareholders shall be held on such date and at such time as the Board of Directors may determine each year.  Such meetings may be held within or without the Commonwealth of Pennsylvania at such time and place as the Directors may determine.  The Directors may determine that the meeting shall not be held at any physical place, but instead may be held solely by means of communications equipment as authorized by Section 9 below.

Section 2.   Special Meetings.

Special meetings of the shareholders may be called at any time by (i) the Chairman of the Board, (ii) the President, (iii) the Directors, by action at a meeting or a majority of the Directors acting without a meeting, or (iv) the holders of 20% or more of the outstanding shares entitled to vote thereat.  Such meetings may be held within or without the Commonwealth of Pennsylvania at such time and place as may be specified in the notice thereof.

Section 3.   Notice of Meetings.

Written notice stating the time, place, if any, and purposes of a meeting of the shareholders, and the means, if any, by which shareholders can be present and vote at the meeting through the use of communications equipment shall be given by personal delivery, or by mail, facsimile transmission, overnight delivery service, or any other means of communication authorized by the shareholder to whom the notice is given, not less than five days before the date of the meeting, unless the meeting will consider a fundamental change as described in The Pennsylvania Consolidated Statutes at Chapter 19 in which case not less than ten days notice is required.  Such notice may be given by or at the direction of the Chairman of the Board, the President or the Corporate Secretary.  Notices sent by mail shall be sent postage prepaid and shall be addressed to each shareholder at his address as it appears upon the records of the Corporation.  Notice by mail shall be deemed to be given at the time when the notice is deposited in the mail, notice by personal delivery or by overnight delivery service shall be deemed to be given when deposited, and notice by facsimile, or other electronic communications shall be deemed to be given at the time when confirmation of successful transmission is received.  Any shareholder may waive in writing notice of any meeting, either before or after the holding of such meeting, and by attending any meeting without protesting the lack of proper notice, shall be deemed to have waived notice thereof.

Section 4.   Business Transacted at Meetings.

Business transacted at any meeting of shareholders shall be for the purposes stated in the notice.

Section 5.   Quorum and Adjournments.

The holders of a majority of the stock issued and outstanding and entitled to vote thereat, present in person or represented by proxy, shall constitute a quorum at all meetings of the shareholders for the transaction of business except as otherwise provided by statute or by the Articles of Incorporation.  If, however, such quorum shall not be present or represented at any meeting of the shareholders, the shareholders entitled to vote thereat, present in person or represented by proxy, shall have power to adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum shall be present or represented.  At such adjourned meeting at which a quorum shall be present or represented, any business may be transacted which might have been transacted at the meeting as originally notified.

Section 6.   Required Vote; Judges.

(a)            When a quorum is present or represented at any meeting, the vote of the holders of a majority of the stock having voting power present in person or represented by proxy shall decide any question brought before such meeting, unless the question is one upon which by express provision of the statutes or of the Articles of Incorporation a different vote is required in which case such express provision shall govern and control the decision of such question.

(b)            Judges of election may be appointed to act at any meeting of shareholders in accordance with Pennsylvania law.

Section 7.   Voting Power of Shareholders.

Every shareholder of record of the Corporation shall be entitled at each meeting of shareholders to one vote for each share of stock held by such shareholder according to the books of the Corporation as of the date of such vote or, if a record date is set by the Board of Directors, as of such record date.

Section 8.   Voting by Proxy.

At any meeting of the shareholders, any shareholder may be represented and vote by a proxy or proxies appointed by an instrument in writing or by any other form of verifiable communication, including any form of electronic or other communications, to the full extent legally permitted (now or hereafter).  In the event that any such instrument shall designate two or more persons to act as proxies, a majority of such persons present at the meeting, or, if only one shall be present, then that one shall have and may exercise all of the powers conferred by such instrument upon all of the persons so designated unless the instrument shall otherwise provide.  No such proxy shall be valid after the expiration of three (3) years from the date of its execution, unless coupled with an interest, or unless the person executing it specifies therein the length of time for which it is to continue in force.  Subject to the above, any proxy duly executed is not revoked and continues in full force and effect until an instrument or verifiable communication revoking it or a duly executed proxy bearing a later date is filed with the Corporate Secretary of the Corporation.

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Section 9.   Participation by Shareholders Through Communications Equipment.

If authorized by the Directors, the shareholders and proxyholders who are not physically present at a meeting of shareholders may attend a meeting of shareholders by use of communications equipment that enables the shareholder or proxyholder an opportunity to participate in the meeting and to vote on matters submitted to the shareholders, including an opportunity to read or hear the proceedings of the meeting and to speak or otherwise participate in the proceedings contemporaneously with those physically present.

Section 10.   Action by Shareholders Without a Meeting.

Any action which may be taken by the vote of the shareholders at a meeting may be taken without a meeting if authorized by a writing or writings signed by all of the holders of shares who would be entitled to notice of a meeting for such purpose.  Such written consent shall be filed with or entered upon the records of the Corporation.

DIRECTORS

Section 11.   Authority of Directors.

The business of the Corporation shall be managed by its Board of Directors, which may exercise all such powers of the Corporation and do all such lawful acts and things as are not by statute, the Articles of Incorporation, or these Bylaws directed or required to be exercised or done by the shareholders.

Section 12.   Number; Qualifications.

The number of Directors shall be not less than three (3) and not more than ten (10) (plus any Directors separately elected by the holders of any class of stock other than the Common Stock as provided in the Articles of Incorporation as amended from time to time).  The number of Directors may be determined (a) by the vote of the holders of a majority of the shares entitled to vote thereon at any annual meeting or special meeting called for the purpose of electing Directors or (b) by action of the Board of Directors at a meeting by the vote of a majority of the Directors in office at the time or in a writing signed by all the Directors in office at the time.  When so fixed, such number shall continue to be the authorized number of Directors until changed by the shareholders or Directors in the manner described above.  Any increase in the number of Directors shall be deemed to create a vacancy or vacancies which may be filled as provided in Section 15.  A reduction in the number of Directors shall not be applied to remove any Director from office prior to the expiration of his term.  Directors need not be shareholders of the Corporation.

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Section 13.   Election of Directors.

At each meeting of the shareholders for the election of Directors, the persons receiving the greatest number of votes shall be the Directors.  Such elections shall be by ballot whenever requested by any person entitled to vote at such meeting; but unless so requested, such election may be conducted in any way approved at such meeting.

Section 14.   Term of Office; Removal; Resignations.

(a)            Directors shall hold office until the annual meeting of the shareholders next following their election and until their respective successors are elected, or until their earlier resignation, death or removal from office.

(b)            Any Director or the entire Board of Directors may be removed upon the affirmative vote of the holders of a majority of the voting power of the Corporation.

(c)            Any Director may resign at any time by giving written notice of his resignation to the President or Corporate Secretary. Any resignation will be effective upon actual receipt by such person or, if later, as of the date and time specified in such written notice.

Section 15.   Vacancies.

Vacancies, including those caused by an increase in the number of Directors, may be filled by a majority of the remaining Directors though less than a quorum.  When one or more Directors shall give notice of his or their resignation to the Board, effective at a future date, the Board shall have the power to fill such vacancy or vacancies to take effect when such resignation or resignations shall become effective, each Director so appointed to hold office during the remainder of the term of office of the resigning Director or Directors.  Whenever any vacancy shall occur among the Directors, the remaining Directors shall constitute the Directors of the Corporation until such vacancy is filled or until the number of Directors is changed as in Section 12 hereof.

MEETINGS OF THE BOARD OF DIRECTORS

Section 16.   Organizational Meeting.

Immediately after each annual meeting of the shareholders at which Directors are elected, or each special meeting held in lieu thereof, the newly elected Directors, if a quorum thereof is present, shall hold an organizational meeting at the same place or at such other time and place as may be fixed by the shareholders at such meeting, for the purpose of electing officers and transacting any other business.  Notice of such meeting need not be given.  If for any reason such organizational meeting is not held at such time, a special meeting of the Directors for such purpose shall be held as soon thereafter as practicable.

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Section 17.   Special Meetings.

Special meetings of the Directors may be held at any time within or without the Commonwealth of Pennsylvania upon call by the Chairman of the Board, the President, or the Corporate Secretary upon the written request of two Directors.

Notice of the place, if any, and time of each meeting of the Directors shall be given to each Director either by personal delivery or by mail, facsimile transmission, overnight delivery service, or any other means of communication authorized by the Director, at least two days before the meeting. The notice need not specify the purposes of the meeting.  Notices sent by mail shall be sent postage prepaid and shall be addressed to each Director at his address as it appears upon the records of the Corporation.  Notice by mail shall be deemed to be given at the time when the notice is deposited in the mail, notice by personal delivery or by overnight delivery service shall be deemed to be given when received, and notice by facsimile, or other electronic communications shall be deemed to be given at the time when confirmation of successful transmission is received.  Such notice may be waived in writing by Directors either before or after the meeting, and such written waivers shall be filed with or entered upon the records of the meeting.  The attendance of any Director at any such meeting without protesting the lack of proper notice, prior to or at the commencement of the meeting, shall be deemed to be a waiver by the Director of notice of the meeting.  Unless otherwise limited in the notice thereof, any business may be transacted at any organizational, regular or special meeting.

Section 18.   Quorum and Adjournments; Participation by Communications Equipment.

(a)            A majority of the Directors, at a meeting duly called and held, shall be necessary to constitute a quorum for the transaction of business and the act of a majority of the Directors present at any meeting at which a quorum is present shall be the act of the Board of Directors, except as may be otherwise specifically provided by statute or by the Articles of Incorporation. Any action required or permitted to be taken at a meeting of the Directors may be taken without a meeting if a consent in writing, setting forth the action so taken, shall be signed by all of the Directors entitled to vote with respect to the subject matter thereof. Any meeting duly called, whether or not a quorum is present, may, by vote of a majority of the Directors present, be adjourned from time to time and place to place within or without the Commonwealth of Pennsylvania, in which case no further notice of the adjourned meeting need be given.

(b)            Meetings of the Board of Directors or of any committee of the Board of Directors may be held through any means of communications equipment if all persons participating can hear each other, and such participation will constitute presence in person at such meeting.

Section 19.   Committees.

The Board of Directors may, by resolution passed by a majority of the Directors, designate one or more committees, each committee to consist of one or more of the Directors of the Corporation, which, to the extent provided in the resolution, shall have and may exercise the powers of the Board of Directors in the management of the business and affairs of the Corporation.  Such committee or committees shall have such name or names as may be determined from time to time by resolution adopted by the Board of Directors.  The committees shall keep regular minutes of their proceedings and report the same to the Board when required.

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Section 20.   Compensation.

The Directors may be paid their expenses, if any, for attendance at each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors.  The sums may be different for different Directors, and the sum shall be established by resolution of the Board of Directors and may be changed from time to time by resolution.  No such payment shall preclude any Director from serving the Corporation in any other capacity and receiving compensation therefor.  Members of special or standing committees may be allowed like compensation for attending committee meetings.

Section 21.   Action by Directors Without a Meeting.

Any action required or permitted to be taken at a meeting of the Board of Directors or any committee of the Board of Directors may be taken without a meeting if, prior or subsequent to such action, all members of the Board of Directors or of such committee, as the case may be, consent thereto in writing and such written consents are filed with the Corporate Secretary of the Corporation.

EXECUTIVE COMMITTEE

Section 22.   Executive Committee.

The Board of Directors at any time may elect from its members an Executive Committee which shall consist of not less than three (3) members.  Each member of such Committee shall hold office during the pleasure of the Board and may be removed by a majority vote of the whole Board at any time with or without cause.  Vacancies occurring in the Committee may be filled by the Board.  The Committee shall prescribe its own rules for calling and holding meetings, and for transacting business, subject, however, to any rules prescribed by the Board of Directors, and the Committee shall keep minutes of its actions.  Action by the Committee may be taken at meetings thereof attended by not less than a majority thereof, or without a meeting by instrument in writing signed by not less than a majority of the members.  Except as the Committee’s powers and duties may be limited or otherwise prescribed by the Board of Directors, the Committee, during the intervals between the meetings of the Board, shall possess and may exercise all of the powers and authority of the Board of Directors, however conferred, provided, however, that the Committee shall not be empowered to elect the officers (other than Assistant Secretaries and Assistant Treasurers) or to fill vacancies in the Board of Directors or in the Executive Committee.  Subject to such exceptions, persons dealing with the Corporation shall be entitled to rely upon any action of the Committee with the same force and effect as though such action had been taken by the Board of Directors.

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OFFICERS

Section 23.   Generally.

The Corporation may have a Chairman, elected by the Directors from among their number, and shall have a President, a Corporate Secretary and a Treasurer.   The Corporation may also have one or more Vice Chairmen, Vice Presidents, Senior Vice Presidents and such other officers and assistant officers as the Board of Directors may deem appropriate.  If the Board of Directors so desires, it may elect a Chief Executive Officer to manage the affairs of the Corporation, subject to the direction and control of the Board of Directors.  All of the officers shall be elected by the Board of Directors.  Notwithstanding the foregoing, by specific action, the Board of Directors may authorize the Chairman or the President to appoint any person to any office other than Chairman, President, Corporate Secretary, or Treasurer.  Any number of offices may be held by the same person, and no two offices must be held by the same person.  Any of the offices may be left vacant from time to time as the Board of Directors may determine.  In case of the absence or disability of any officer of the Corporation or for any other reason deemed sufficient by a majority of the Board of Directors, the Board of Directors may delegate the absent or disabled officer's powers or duties to any other officer or to any Director.

Section 24.  Authority and Duties of Officers.  

The officers of the Corporation shall have such authority and shall perform such duties as are customarily incident to their respective offices, or as may be specified from time to time by the Board of Directors, the Chairman or the President regardless of whether such authority and duties are customarily incident to such office.

Section 25.    Compensation.  

The compensation of all officers and agents of the Corporation who are also members of the Board of Directors of the Corporation will be fixed by the Board of Directors or by a committee of the Board of Directors.  The Board of Directors may fix, or delegate the power to fix, the compensation of the other officers and agents of the Corporation to the Chief Executive Officer or any other officer of the Corporation.

Section 26.   Succession.  

The officers of the Corporation will hold office until their successors are elected.  Any officer may be removed at any time by the affirmative vote of a majority of the whole Board.  Any vacancy occurring in any office of the Corporation may be filled by the Board of Directors or by the Chairman or President as provided in Section 23.

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Section 27.   Delegation of Duties.

The Directors are authorized to delegate the duties of any officers to any other officer and generally to control the action of the officers and to require the performance of duties in addition to those mentioned herein.

SHARES CERTIFICATES

Section 28.   Transfer and Registration of Certificates

The Board of Directors shall have authority to make such rules and regulations, not inconsistent with law, the Articles, or these Bylaws, as it deems expedient concerning the issuance, transfer, and registration of certificates for shares and the shares represented thereby and may appoint transfer agents and registrars thereof.  The Directors may provide by resolution that some or all of any or all classes and series of shares shall be uncertificated shares, provided that any then-outstanding shares of that class or series represented by a certificate shall not become uncertificated shares until the certificate is surrendered to the Corporation.

Section 29.   Substituted Certificates

Any person claiming that a certificate for shares has been lost, stolen, or destroyed shall make an affidavit or affirmation of that fact and, if required, shall give the Corporation (and its registrar or registrars and its transfer agent or agents, if any) a bond of indemnity, in such form and with one (1) or more sureties satisfactory to the Board, and if required by the Board of Directors, shall advertise the same in such manner as the Board of Directors may require, whereupon a new certificate may be executed and delivered of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, or destroyed.

RECORD DATES AND CLOSING OF TRANSFER BOOKS

Section 30.   Record Dates and Closing of Transfer Books.

The Board of Directors may fix a time not exceeding sixty (60) days preceding the date of any meeting of shareholders or the date fixed for the payment of any dividend or distribution or the date for the allotment of rights as the record date for the determination of the shareholders entitled to notice of or to vote at any such meeting or entitled to receive payment of any such dividend, distribution or allotment of rights, and in such case only shareholders of record on the date so fixed shall be entitled to notice of or to vote at such meeting or to receive payment of such dividend, distribution or allotment of rights, as the case may be, notwithstanding any transfer of any shares on the books of the Corporation after any record date so fixed.  The Board of Directors may close the books of the Corporation against transfers of shares during the whole or any part of the period between such record date and the date of the event in respect for which such record date was fixed.

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REGISTERED SHAREHOLDERS

Section 31.   Recognition of Record Ownership.

The Corporation shall be entitled to recognize the exclusive right of a person registered on its books as the owner of shares to receive dividends, and to vote as such owner, and to hold liable for calls and assessments a person registered on its books as the owner of shares, and shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of Pennsylvania.

GENERAL PROVISIONS

DIVIDENDS

Section 32.   Payment of Dividends.

The Board of Directors may declare dividends upon the capital stock of the Corporation, subject to the provisions of the Articles of Incorporation, if any, at any regular or special meeting pursuant to law.  Dividends may be paid in cash, in property or in shares of the capital stock, subject to the provisions of the Articles of Incorporation.  Before payment of any dividend, there may be set aside out of any funds of the Corporation available for dividends such sum or sums as the Directors from time to time, in their absolute discretion, think proper as a reserve or reserves to meet contingencies, or for equalizing dividends, or for repairing or maintaining any property of the Corporation, or for such other purpose as the Directors shall think conducive to the interest of the Corporation and the Directors may modify or abolish any such reserves in the manner in which it was created.

FISCAL YEAR

Section 33.   Fiscal Year.

The fiscal year of the Corporation shall be fixed by resolution of the Board of Directors.

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SEAL

Section 34.   Corporate Seal.

The Directors may adopt a corporate seal of the Corporation which shall be of such design, and shall contain such words, as may be prescribed by the Directors.  Failure to affix any such corporate seal shall not affect the validity of any instrument.

TRANSFER AGENT AND REGISTRAR

Section 35.   Transfer Agent; Registrar.

The Corporation may open transfer books in any state of the United States or in any foreign country for the purpose of transferring securities issued by it, and it may employ an agent or agents to keep the records of its securities to transfer or to register securities or both, in Pennsylvania or in other states or in a foreign country, or both, and the acts of such agents shall be binding on the Corporation.  The duties and liabilities of such agent or agents shall be such as may be agreed to by the Corporation.  If no such transfer agent is appointed to act in Pennsylvania in respect to its shares, the Corporation shall keep an office in Pennsylvania at which shares shall be transferable, and at which it shall keep books in which shall be recorded the names and addresses of all shareholders and all transfers of shares.

PROVISIONS IN ARTICLES OF INCORPORATION

Section 36.   Governance By Articles of Incorporation.

These Bylaws are at all times subject to the provisions of the Articles of Incorporation of the Corporation (including in such term whenever used in these Bylaws, amendments thereto), and in case of any conflict between any provision herein and in the Articles of Incorporation, the provisions in the Articles of Incorporation shall be deemed to govern.

AMENDMENTS

Section 37.  Procedure for Amendments.

These Bylaws may be altered, amended, or repealed in any respect or superseded by new Bylaws in whole or in part, (a) by the affirmative vote of the holders of record of shares entitling them to exercise a majority of the voting power of the Corporation at an annual or special meeting called for such purpose, or by their unanimous written consent; or (b) by the Board of Directors at an annual or special meeting called for such purpose, or by their unanimous written consent as provided in 15 Pa.C.S.A. § 1504b.

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INDEMNIFICATION AND INSURANCE

Section 38.   Indemnification.

The Corporation shall indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he or she is or was a director, officer, employee, or agent of the Corporation, or is or was serving at the request of the Corporation as a director, trustee, officer, employee, member, manager, or agent of another corporation, limited liability company, partnership, joint venture, trust or other enterprise, against expenses, including attorney’s fees, judgments, fines and amounts paid in settlement, actually and reasonably incurred by him or her in connection with such action, suit, or proceeding, if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation, and with respect to any criminal action or proceeding, if he or she had no reasonable cause to believe his or her conduct was unlawful, to the full extent and according to the procedures and requirements set forth in the Pennsylvania General Corporation Law as now in effect or as amended from time to time.  The Corporation shall pay, to the full extent then permitted by law, expenses, including attorney’s fees, incurred by a member of the Board of Directors in defending any such action, suit or proceeding as they are incurred, in advance of the final disposition thereof, and may pay, in the same manner and to the full extent then permitted by law, such expenses incurred by any other person.

The indemnification and payment of expenses provided hereby shall not be exclusive of, and shall be in addition to, any other rights granted to those seeking indemnification under any law, the Articles of Incorporation, any agreement, vote of shareholders or disinterested members of the Board of Directors, or otherwise, both as to action in official capacities and as to action in another capacity while he or she is a member of the Board of Directors, or an officer, employee or agent of the Corporation, and shall continue as to a person who has ceased to be a member of the Board of Directors, officer, employee or agent and shall inure to the benefit of the heirs, executors and administrators of such a person.

Section 39.   Insurance.

The Corporation may, to the full extent then permitted by law and authorized by the Board of Directors, purchase and maintain insurance or furnish similar protection, including but not limited to trust funds, letters of credit or self-insurance, on behalf of or for any persons described in Section 38 against any liability asserted against and incurred by any such person in any such capacity, or arising out of his status as such, whether or not the Corporation would have the power to indemnify such person against such liability.  Insurance may be purchased from or maintained with a person in which the Corporation has a financial interest.

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EMERGENCY BYLAWS

Section 40.   Emergency Bylaws.

The Board of Directors may adopt, at any meeting, either before or during “an emergency” as that term is defined in 15 Pa.C.S.A. § 1509, emergency bylaws to be operative during, but only during, an emergency.  The emergency bylaws may contain any provisions which may be made by emergency bylaws as provided in 15 Pa.C.S.A. § 1509..

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EX-12.8

											EXHIBIT 12.8
											Page 1
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
		Year Ended December 31,
			2003		2004		2005		2006		2007
		(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	20,237	$	36,030	$	27,553	$	84,182	$	92,938
Interest and other charges, before reduction for amounts capitalized
	and deferred		37,660		40,022		39,900		45,278		54,840
Provision for income taxes			24,836		30,001		16,613		56,539		64,015
Interest element of rentals charged to income (a)			3,076		3,016		3,225		3,247		3,214
	Earnings as defined	$	85,809	$	109,069	$	87,291	$	189,246	$	215,007
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred		$	33,883	$	40,022	$	39,900	$	45,278	$	54,840
Subsidiary's preferred stock dividend requirements			3,777		-		-		-		-
Interest element of rentals charged to income (a)			3,076		3,016		3,225		3,247		3,214
	Fixed charges as defined	$	40,736	$	43,038	$	43,125	$	48,525	$	58,054
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES			2.11		2.53		2.02		3.90		3.70
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

										EXHIBIT 12.8
											Page 2
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS
PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)
		Year Ended December 31,
			2003		2004		2005		2006		2007
		(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items		$	20,237	$	36,030	$	27,553	$	84,182	$	92,938
Interest and other charges, before reduction for amounts capitalized
	and deferred		37,660		40,022		39,900		45,278		54,840
Provision for income taxes			24,836		30,001		16,613		56,539		64,015
Interest element of rentals charged to income (a)			3,076		3,016		3,225		3,247		3,214
	Earnings as defined	$	85,809	$	109,069	$	87,291	$	189,246	$	215,007
FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS
	PREFERRED STOCK DIVIDEND REQUIREMENTS
	(PRE-INCOME TAX BASIS):
Interest before reduction for amounts capitalized and deferred		$	33,883	$	40,022	$	39,900	$	45,278	$	54,840
Preferred stock dividend requirements			3,777		-		-		-		-
Adjustments to preferred stock dividends
	to state on a pre-income tax basis		-		-		-		-		-
Interest element of rentals charged to income (a)			3,076		3,016		3,225		3,247		3,214
Fixed charges as defined plus preferred stock
	dividend requirements (pre-income tax basis)	$	40,736	$	43,038	$	43,125	$	48,525	$	58,054
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS
	(PRE-INCOME TAX BASIS)		2.11		2.53		2.02		3.90		3.70
	(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

EX-23.3

EXHIBIT 23.3

PENNSYLVANIA ELECTRIC COMPANY

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (Nos. 333-62295, 333-62295-01, and 333-62295-02) of Pennsylvania Electric Company of our report dated February 28, 2008 relating to the financial statements, which appears in the Annual Report to Stockholders, which is incorporated in this Annual Report on Form 10-K. We also consent to the incorporation by reference of our report dated February 28, 2008 relating to the financial statement schedules, which appears in this Form 10-K.

PricewaterhouseCoopers LLP

Cleveland, OH

February 28, 2008