FirstEnergy Solutions 10K 2007 Annual report | SEC Filing

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

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

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

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

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 $314 million, 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

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.

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.

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.

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.

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.

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

��

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.

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.

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.

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.

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.

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.

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.

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

New Accounting Standards and Interpretations

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.

Management's Report on Internal Control Over Financial Reporting

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.

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.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

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.

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.

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.

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.

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.

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	%

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.

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

New Accounting Standards and Interpretations

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.

Management's Report on Internal Control Over Financial Reporting

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.

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.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

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.

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.

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.

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.

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.

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	%

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.

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

New Accounting Standards and Interpretations

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.

Management's Report on Internal Control Over Financial Reporting

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.

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

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.

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.

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.

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.

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.

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

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.

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).

Legal Proceedings

New Accounting Standards and Interpretations

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.

Management's Report on Internal Control Over Financial Reporting

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.

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.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

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.

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.

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.

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.

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.

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	%

	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).

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.

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

New Accounting Standards and Interpretations

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.

Management's Report on Internal Control Over Financial Reporting

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.

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.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

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.

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.

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.

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.

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.

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	%

	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.

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.

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

New Accounting Standards and Interpretations

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.

Management's Report on Internal Control Over Financial Reporting

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.

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.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 28, 2008

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.

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.

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.

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.

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.

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:

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.

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.

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.

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:

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

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Meet 22.5% of New Jerseys electricity needs with renewable energy resources by that date;

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Reduce air pollution related to energy use;

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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;

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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

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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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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:

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

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are cost-based; and

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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.

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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;

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establishing or defining the PLR obligations to customers in the Companies' service areas;

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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.

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

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.

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:

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.

(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

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.

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.

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	)

100

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.

101

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:

103

	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

104

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.

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.

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

113

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.

114

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 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.

115

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.

116

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

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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 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.

118

(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.

Post Transition Period Rate Design

119

Distribution of MISO Network Service Revenues

MISO Ancillary Services Market and Balancing Area Consolidation

Duquesnes Request to Withdraw from PJM

120

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

Organized Wholesale Power Markets

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		-		$	-

122

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

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.

123

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.

124

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 an obligation exists even though there may be uncertainty about timing or method of settlement and further clarifies SFAS 143, stating that the uncertainty surrounding the timing and method of settlement when settlement is conditional on a future event occurring should be reflected in the measurement of the liability, not in the recognition of the liability. 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

125

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.

126

(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.

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 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.

127

National Ambient Air Quality Standards

Mercury Emissions

W. H. Sammis Plant

128

Climate Change

Clean Water Act

129

Regulation of Hazardous Waste

(D) OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

130

Nuclear Plant Matters

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.

131

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.

132

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.

133

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

134

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"

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"

SFAS 160 - "Noncontrolling Interests in Consolidated Financial Statements an Amendment of ARB No. 51"

FSP FIN 39-1 - "Amendment of FASB Interpretation No. 39"

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

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Readability	7th grade Avg

FirstEnergy Solutions Inactive 10-K2007 FY Annual report

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