FirstEnergy Solutions 10-K 2008 FY Annual report

ANNUAL REPORT 2008

Contents		Page
Glossary of Terms		iii-v
FirstEnergy Solutions Corp.
	Management's Narrative Analysis of Results of Operations	1-5
	Management Reports	6
	Report of Independent Registered Public Accounting Firm	7
	Consolidated Statements of Income	8
	Consolidated Balance Sheets	9
	Consolidated Statements of Capitalization	10
	Consolidated Statements of Common Stockholder’s Equity	11
	Consolidated Statements of Cash Flows	12
Ohio Edison Company
	Management's Narrative Analysis of Results of Operations	13-15
	Management Reports	16
	Report of Independent Registered Public Accounting Firm	17
	Consolidated Statements of Income	18
	Consolidated Balance Sheets	19
	Consolidated Statements of Capitalization	20
	Consolidated Statements of Common Stockholder’s Equity	21
	Consolidated Statements of Cash Flows	22
The Cleveland Electric Illuminating Company
	Management's Narrative Analysis of Results of Operations	23-25
	Management Reports	26
	Report of Independent Registered Public Accounting Firm	27
	Consolidated Statements of Income	28
	Consolidated Balance Sheets	29
	Consolidated Statements of Capitalization	30
	Consolidated Statements of Common Stockholder’s Equity	31
	Consolidated Statements of Cash Flows	32
The Toledo Edison Company
	Management's Narrative Analysis of Results of Operations	33-35
	Management Reports	36
	Report of Independent Registered Public Accounting Firm	37
	Consolidated Statements of Income	38
	Consolidated Balance Sheets	39
	Consolidated Statements of Capitalization	40
	Consolidated Statements of Common Stockholder’s Equity	41
	Consolidated Statements of Cash Flows	42
Jersey Central Power & Light Company
	Management's Narrative Analysis of Results of Operations	43-46
	Management Reports	47
	Report of Independent Registered Public Accounting Firm	48
	Consolidated Statements of Income	49
	Consolidated Balance Sheets	50
	Consolidated Statements of Capitalization	51
	Consolidated Statements of Common Stockholder’s Equity	52
	Consolidated Statements of Cash Flows	53

i

Contents (Cont’d)		Page
Metropolitan Edison Company
	Management's Narrative Analysis of Results of Operations	54-57
	Management Reports	58
	Report of Independent Registered Public Accounting Firm	59
	Consolidated Statements of Income	60
	Consolidated Balance Sheets	61
	Consolidated Statements of Capitalization	62
	Consolidated Statements of Common Stockholder’s Equity	63
	Consolidated Statements of Cash Flows	64
Pennsylvania Electric Company
	Management's Narrative Analysis of Results of Operations	65-68
	Management Reports	69
	Report of Independent Registered Public Accounting Firm	70
	Consolidated Statements of Income	71
	Consolidated Balance Sheets	72
	Consolidated Statements of Capitalization	73
	Consolidated Statements of Common Stockholder’s Equity	74
	Consolidated Statements of Cash Flows	75
Combined Management’s Discussion and Analysis of Registrant Subsidiaries		76-90
Combined Notes to Consolidated Financial Statements		91-145

ii

GLOSSARY OF TERMS

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

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
Centerior	Centerior Energy Corporation, former parent of CEI and TE, which merged with OE to form FirstEnergy on November 8, 1997
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
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
Utilities	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
Waverly	The Waverly Power and Light Company, a wholly owned subsidiary of Penelec
The following abbreviations and acronyms are used to identify frequently used terms in this report:
ACO	Administrative Consent Order
AEP	American Electric Power Company, Inc.
ALJ	Administrative Law Judge
AMP-Ohio	American Municipal Power - Ohio
AOCI	Accumulated Other Comprehensive Income
AOCL	Accumulated Other Comprehensive Loss
AQC	Air Quality Control
ARB	Accounting Research Bulletin
ARO	Asset Retirement Obligation
BGS	Basic Generation Service
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAT	Commercial Activity Tax
CBP	Competitive Bid Process
CO2	Carbon Dioxide
CTC	Competitive Transition Charge
DFI	Demand for Information
DOJ	United States Department of Justice
DRA	Division of Ratepayer Advocate
EIS	Energy Independence Strategy
EITF	Emerging Issues Task Force
EITF 01-8	Determining Whether an Arrangement Contains a Lease
EITF 08-6	Equity Method Investment Accounting Considerations
EMP	Energy Master Plan

iii

GLOSSARY OF TERMS Cont’d.

EPA	Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ESP	Electric Security Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
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 Bond
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”
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
IRS	Internal Revenue Service
ISO	Independent System Operator
kV	Kilovolt
KWH	Kilowatt-hours
LED	Light-emitting Diode
LOC	Letter of Credit
MEW	Mission Energy Westside, Inc.
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service, Inc.
MRO	Market Rate Offer
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
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
OSBA	Office of Small Business Advocate
OTC	Over the Counter
PCRB	Pollution Control Revenue Bond
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort; an electric utility’s obligation to provide generation service to customers whose alternative supplier fails to deliver service
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PSA	Power Supply Agreement
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RECB	Regional Expansion Criteria and Benefits
RFP	Request for Proposal
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Service
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment

iv

GLOSSARY OF TERMS Cont’d.

SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 101	SFAS No. 101, "Accounting for Discontinuation of Application of SFAS 71"
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 132(R)-1	SFAS No. 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”
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”
SFAS 161	SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an Amendment  of FASB Statement No. 133”
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
TSC	Transmission Service Charge
VIE	Variable Interest Entity

v

This combined Annual Report is separately filed by FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant.

Forward-Looking Statements:This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management's intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms "anticipate," "potential," "expect," "believe," "estimate" and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements 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, the impact of the PUCO's regulatory process on the Ohio Companies associated with the ESP and MRO filings, including any resultant mechanism under which the Ohio Companies may not fully recover costs (including, but not limited to, the costs of generation supply procured by the Ohio Companies, Regulatory Transition Charges and fuel charges), or the outcome of any competitive generation procurement process in Ohio, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices and availability, replacement power costs being higher than anticipated or inadequately hedged, the continued ability of the 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 greenhouse gas emission regulations, the potential impacts of the U.S. Court of Appeals' July 11, 2008 decision requiring revisions to the CAIR rules and the scope of any laws, rules or regulations that may ultimately take their place, the uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the AQC Plan (including that such amounts could be higher than anticipated or that certain generating units may need to be shut down) or levels of emission reductions related to the Consent Decree resolving the NSR 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), 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 the RCP, including the recovery of deferred fuel costs), Met-Ed's and Penelec's transmission service charge filings with the PPUC, the continuing availability of generating units and their ability to operate at or near full capacity, 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 changing market conditions that could affect the value of assets held in nuclear decommissioning trusts, pension trusts and other trust funds, and cause the registrants to make additional contributions sooner, or in an amount that is larger than currently anticipated, the ability to access the public securities and other capital and credit markets in accordance with FirstEnergy’s financing plan and the cost of such capital, changes in general economic conditions affecting the registrants, the state of the capital and credit markets affecting the registrants, interest rates and any actions taken by credit rating agencies that could negatively affect the registrants’ access to financing or its costs and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees, the continuing decline of the national and regional economy and its impact on the registrants’ major industrial and commercial customers, issues concerning the soundness of financial institutions and counterparties with which the registrants do business, and the risks and other factors discussed from time to time in the registrant’s 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 for management to predict all such factors, nor assess the impact of any such factor on the registrant’s 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. 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 and maintains 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 derived 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 included a full-requirements PSA with OE, CEI and TE to supply each of their default service obligations through December 31, 2008, at prices that considered their respective PUCO-authorized billing rates. See Regulatory Matters – Ohio below for a discussion of power supply for 2009 and beyond. FES also has a partial requirements wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to supply a portion of each of their respective default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty day written notice prior to the end of the calendar year. The fixed prices under the partial requirements agreement are expected to remain below wholesale market prices during the term of the agreement. FES also supplies a portion of Penn’s default service requirements at market-based rates as a result of Penn’s 2008 competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois.

Results of Operations

Net income decreased to $506 million in 2008 from $529 million in 2007 primarily due to higher fuel, depreciation and other operating expenses and lower investment income, partially offset by higher revenues and lower purchased power and interest expenses.

Revenues

Revenues increased by $193million in 2008 compared to 2007 primarily due to increases in revenues from wholesale sales, partially offset by lower retail generation sales. The increase in revenues in 2008 from 2007 is summarized below:

Revenues by Type of Service	2008		2007		Increase (Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	615	$	712	$	(97	)
Wholesale		717		603		114
Total Non-Affiliated Generation Sales		1,332		1,315		17
Affiliated Wholesale Generation Sales		2,968		2,901		67
Transmission		150		103		47
Other		68		6		62
Total Revenues	$	4,518	$	4,325	$	193

Retail generation sales revenues decreased due to lower contract renewals for commercial and industrial customers in the PJM market and the termination of certain government aggregation programs in the MISO market. Non-affiliated wholesale revenues increased due to higher capacity prices and sales volumes in the PJM market, partially offset by decreased sales volumes in the MISO market.

Increased affiliated company wholesale sales resulted from higher unit prices for the Ohio Companies partially offset by lower unit prices for the Pennsylvania Companies and decreased sales volumes to all affiliates. Higher unit prices on sales to the Ohio Companies were due to the PSA provision that provides for prices to reflect the increase in the Ohio Companies’ retail generation rates (see Regulatory Matters – Ohio). While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the overall composite price to decline. The lower PSA affiliated sales volumes were due to milder weather and reduced default service requirements in Penn’s service territory as a result of its RFP process.

1

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated generation sales in 2008 compared to 2007:

	Increase
Source of Change in Non-Affiliated Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 15.8% decrease in sales volumes	$	(113	)
Change in prices		16
		(97	)
Wholesale:
Effect of 3.8% increase in sales volumes		23
Change in prices		91
		114
Net Increase in Non-Affiliated Generation Revenues	$	17

	Increase
Source of Change in Affiliated Generation Revenues	(Decrease)
	(In millions)
Ohio Companies:
Effect of 1.5% decrease in sales volumes	$	(34	)
Change in prices		129
		95
Pennsylvania Companies:
Effect of 1.5% decrease in sales volumes		(10	)
Change in prices		(18	)
		(28	)
Net Increase in Affiliated Generation Revenues	$	67

Transmission revenue increased $47 million due primarily to higher rates for transmission service in MISO and PJM. Other revenue increased by $62 million principally due to revenue from affiliated companies for the lessor equity interests in Beaver Valley Unit 2 and Perry that were acquired by NGC during the second quarter of 2008.

Expenses

Total expenses increased by $194 million in 2008 compared to 2007. The following tables summarize the factors contributing to the changes in fuel and purchased power costs in 2008 from 2007:

Source of Change in Fuel Costs	Increase
	(In millions)
Fossil Fuel:
Change due to volume consumed	$	90
Change due to increased unit costs		129
		219
Nuclear Fuel:
Change due to volume consumed		8
Change due to increased unit costs		1
		9
Net Increase in Fuel Costs	$	228

Source of Change in Purchased Power Costs	Increase  (Decrease)
	(In millions)
Purchased Power From Affiliates
Change due to volume purchased	$	(124	)
Change due to decreased unit costs		(9	)
		(133	)
Purchased Power From Non-affiliates:
Change due to volume purchased		(215	)
Change due to increased unit costs		230
		15
Net Decrease in Purchased Power Costs	$	(118	)

2

Fossil fuel costs increased $219 million in 2008, primarily as a result of the assignment of CEI’s and TE’s leasehold interest in the Bruce Mansfield Plant to FGCO in October 2007 ($66 million) and higher unit prices due to increased coal transportation costs ($112 million), increased prices for existing eastern coal contracts ($32 million) and emission allowance costs ($5 million). Nuclear fuel expense increased $9 million, primarily reflecting higher generation in 2008.

Purchased power costs decreased as a result of reduced purchases from affiliates, partially offset by increased non-affiliated purchased power unit costs. Purchases from affiliated companies decreased as a result of the assignment of CEI’s and TE’s leasehold interests in the Mansfield Plant to FGCO; prior to the assignment, FGCO purchased the associated output from CEI and TE. Purchased power costs from non-affiliates increased primarily as a result of higher spot market prices in MISO and higher capacity prices in PJM, partially offset by reduced volumes reflecting lower retail sales requirements and more generation available from FES’ facilities.

Other operating expenses increased by $44million in 2008 from 2007, primarily due to expenses associated with the assignment of CEI’s and TE’s leasehold interests in the Mansfield Plant to FGCO ($38 million) and the sale and leaseback of Mansfield Unit 1 ($74 million) completed in the second half of 2007. Transmission expenses decreased as a result of reduced congestion charges ($35 million). Lower fossil operating costs were primarily due to a gain on the sale of a coal contract in the fourth quarter of 2008 ($21 million), reduced scheduled outage activity ($17 million) and increased gains from emission allowance sales ($5 million), partially offset by costs associated with a cancelled electro-catalytic oxidation project ($13 million).

Depreciation expense increased by $39 million in 2008 primarily due to the assignment of the Mansfield Plant to FGCO described above and NGC’s acquisition of certain lessor equity interests in the sale and leaseback of Perry and Beaver Valley Unit 2.

Other Expense

Other expense increased by $33 million in 2008 primarily due to a $49 million additional loss on nuclear decommissioning trust investments as a result of securities impairments during 2008 and reduced investment income from loans to the unregulated money pool ($15 million). Interest expense to affiliates decreased $36 million due to reduced loans from the unregulated money pool and the repayment of notes payable to affiliates since 2007, partially offset by higher other interest expense (net of capitalized interest) of $5 million.

Working Capital

As of December 31, 2008, FES’ net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings and the classification of certain variable interest rate PCRBs as currently payable long-term debt (see Note 10(C)). As of December 31, 2008, FES had access to $1.3 billion of short-term financing under revolving credit facilities. In addition, FES has the ability to borrow from FirstEnergy under the unregulated money pool to meet its short-term working capital requirements.

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 2008 is summarized in the following table:

3

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, 2008	$	-		$	(26	)	$	(26	)
Additions/change in value of existing contracts		(1	)		(19	)		(20	)
Settled contracts		-			4			4
Outstanding net liability as of December 31, 2008	$	(1	)	$	(41	)	$	(42	)
Non-commodity net liabilities as of December 31, 2008:
Interest rate swaps	$	-		$	-		$	-
Net liabilities – derivative contacts as of December 31, 2008	$	(1	)	$	(41	)	$	(42	)
Impact of changes in commodity derivative contracts(*)
Income Statement effects (Pre-Tax)	$	(1	)	$	-		$	(1	)
Balance Sheet effects:
OCI (Pre-Tax)	$	-		$	(15	)	$	(15	)

(*) 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, 2008 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	1		$	11		$	12
Other liabilities		(2	)		(43	)		(45	)
Non-Current-
Other deferred charges		-			-			-
Other noncurrent liabilities		-			(9	)		(9	)
Net liabilities	$	(1	)	$	(41	)	$	(42	)

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	2009				2010				2011			2012			2013			Thereafter			Total
	(In millions)
Prices actively quoted(1)		$	(16	)		$	(9	)		$	-		$	-		$	-		$	-		$	(25	)
Broker quote sheets(2)			(17	)			-				-			-			-			-			(17	)
Total		$	(33	)		$	(9	)		$	-		$	-		$	-		$	-		$	(42	)

(1) Exchange traded.

(2) Validated by observable market transactions.

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, 2008. Based on derivative contracts held as of December 31, 2008, an adverse 10% change in commodity prices would decrease net income by approximately $2 million for the next 12 months.

FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ power portfolio as of December 31, 2008, and forward prices as of that date, FES had $103 million outstanding in margining accounts. Under a hypothetical adverse change in forward prices (15% decrease in prices), FES would be required to post an additional $98 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post significantly higher amounts for margining.

4

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	2009			2010			2011			2012			2013			after			Total			Value
	(Dollars in millions)
Assets
Investments Other Than Cash
and Cash Equivalents:
Fixed Income	$	11		$	74											$	653		$	738		$	737
Average interest rate		2.8	%		5.0	%											4.4	%		4.4	%
Liabilities
Long-term Debt:
Fixed rate	$	41		$	53		$	58		$	68		$	75		$	182		$	477		$	453
Average interest rate		8.9	%		8.9	%		8.9	%		9.0	%		9.0	%		7.4	%		8.3	%
Variable rate																$	2,075		$	2,075		$	2,075
Average interest rate																	1.5	%		1.5	%
Short-term Borrowings:	$	1,265																	$	1,265		$	1,265
Average interest rate		1.1	%																	1.1	%

Fluctuations in the fair value of NGC's decommissioning trust balances will eventually affect earnings (immediately for other-than-temporary impairments 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, 2008, NGC’s decommissioning trust balance totaled $1.0 billion, comprised of 37% equity securities and 63% debt instruments.

Equity Price Risk

Included in NGC’s nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $380 million as of December 31, 2008. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $38 million reduction in fair value as of December 31, 2008 (see Note 5).

Credit Risk

Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. 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 our counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of 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, 2008, the largest credit concentration was with JP Morgan, which is currently rated investment grade, representing 11.4% of FES’ total approved credit risk.

Legal Proceedings

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

New Accounting Standards and Interpretations

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

5

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of FirstEnergy Solutions Corp. (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2008 consolidated financial statements.

FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s 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.

FirstEnergy’s 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 Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s 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 Company’s 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 ten meetings in 2008.

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 Company’s 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 Company’s internal control over financial reporting was effective as of December 31, 2008.

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

6

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of FirstEnergy Solutions Corp.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of FirstEnergy Solutions Corp. and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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

February24, 2009

7

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31,	2008			2007			2006
	(In thousands)
REVENUES:
Electric sales to affiliates (Note 3)	$	2,968,323		$	2,901,154		$	2,609,299
Electric sales to non-affiliates		1,332,364			1,315,141			1,265,604
Other		217,666			108,732			136,450
Total revenues		4,518,353			4,325,027			4,011,353
EXPENSES (Note 3):
Fuel		1,315,293			1,087,010			1,105,657
Purchased power from affiliates		101,409			234,090			257,001
Purchased power from non-affiliates		778,882			764,090			590,491
Other operating expenses		1,084,548			1,041,039			1,027,564
Provision for depreciation		231,899			192,912			179,163
General taxes		88,004			87,098			73,332
Total expenses		3,600,035			3,406,239			3,233,208
OPERATING INCOME		918,318			918,788			778,145
OTHER INCOME (EXPENSE):
Investment income (loss)		(22,678	)		41,438			45,937
Miscellaneous income		1,698			11,438			8,565
Interest expense to affiliates (Note 3)		(29,829	)		(65,501	)		(162,673	)
Interest expense - other		(111,682	)		(92,199	)		(26,468	)
Capitalized interest		43,764			19,508			11,495
Total other expense		(118,727	)		(85,316	)		(123,144	)
INCOME BEFORE INCOME TAXES		799,591			833,472			655,001
INCOME TAXES		293,181			304,608			236,348
NET INCOME	$	506,410		$	528,864		$	418,653
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part of these statements.

8

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS

As of December 31,	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	39	$	2
Receivables-
Customers (less accumulated provisions of $5,899,000 and $8,072,000,
respectively, for uncollectible accounts)		86,123		133,846
Associated companies		378,100		376,499
Other (less accumulated provisions of $6,815,000 and $9,000
respectively, for uncollectible accounts)		24,626		3,823
Notes receivable from associated companies		129,175		92,784
Materials and supplies, at average cost		521,761		427,015
Prepayments and other		112,535		92,340
		1,252,359		1,126,309
PROPERTY, PLANT AND EQUIPMENT:
In service		9,871,904		8,294,768
Less - Accumulated provision for depreciation		4,254,721		3,892,013
		5,617,183		4,402,755
Construction work in progress		1,747,435		761,701
		7,364,618		5,164,456
INVESTMENTS:
Nuclear plant decommissioning trusts		1,033,717		1,332,913
Long-term notes receivable from associated companies		62,900		62,900
Other		61,591		40,004
		1,158,208		1,435,817
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		267,762		276,923
Lease assignment receivable from associated companies (Note 6)		71,356		215,258
Goodwill		24,248		24,248
Property taxes		50,104		47,774
Pension assets (Note 4)		-		16,723
Unamortized sale and leaseback costs		69,932		70,803
Other		96,434		43,953
		579,836		695,682
	$	10,355,021	$	8,422,264
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	2,024,898	$	1,441,196
Short-term borrowings-
Associated companies		264,823		264,064
Other		1,000,000		300,000
Accounts payable-
Associated companies		472,338		445,264
Other		154,593		177,121
Accrued taxes		79,766		171,451
Other		248,439		237,806
		4,244,857		3,036,902
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		2,944,423		2,414,231
Long-term debt and other long-term obligations		571,448		533,712
		3,515,871		2,947,943
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		1,026,584		1,060,119
Accumulated deferred investment tax credits		62,728		61,116
Asset retirement obligations		863,085		810,114
Retirement benefits		194,177		63,136
Property taxes		50,104		48,095
Lease market valuation liability		307,705		353,210
Other		89,910		41,629
		2,594,293		2,437,419
COMMITMENTS AND CONTINGENCIES (Notes 6 & 13)
	$	10,355,021	$	8,422,264
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part of these balance sheets.

9

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2008			2007
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, authorized 750 shares,
7 shares outstanding	$	1,464,229		$	1,164,922
Accumulated other comprehensive income (Note 2(F))		(91,871	)		140,654
Retained earnings (Note 10(A))		1,572,065			1,108,655
Total		2,944,423			2,414,231
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 10(C)):
Secured notes:
FirstEnergy Solutions Corp.
5.150% due 2009-2015		22,868			-
FirstEnergy Nuclear Generation Corp.
8.830% due 2009-2016		5,007			-
8.890% due 2009-2016		82,680			-
9.000% due 2009-2017		234,635			-
9.120% due 2009-2016		68,311			-
12.000% due 2009-2017		1,174			-
		391,807			-
Total secured notes		414,675			-
Unsecured notes:
FirstEnergy Generation Corp.
*   1.250% due 2017		28,525			28,525
*   3.375% due 2018		2,805			-
*   3.375% due 2018		2,985			-
*   1.050% due 2019		90,140			90,140
*   1.100% due 2020		141,260			141,260
*   1.250% due 2023		234,520			234,520
*   4.350% due 2028		15,000			15,000
*   7.125% due 2028		25,000			-
*   0.750% due 2029		6,450			6,450
*   1.000% due 2029		100,000			100,000
*   1.000% due 2040		43,000			43,000
*   0.850% due 2041		129,610			129,610
*   1.000% due 2041		26,000			26,000
*   1.100% due 2041		56,600			56,600
*   3.375% due 2047		46,300			-
		948,195			871,105
FirstEnergy Nuclear Generation Corp.
5.390% due to associated companies 2025		62,900			62,900
*   7.250% due 2032		23,000			-
*   7.250% due 2032		33,000			-
*   0.950% due 2033		46,500			46,500
*   0.950% due 2033		54,600			54,600
*   1.000% due 2033		26,000			26,000
*   1.200% due 2033		99,100			99,100
*   1.300% due 2033		8,000			8,000
*   1.350% due 2033		135,550			135,550
*   1.380% due 2033		15,500			15,500
*   1.450% due 2033		62,500			62,500
*   1.450% due 2033		107,500			107,500
*   3.375% due 2033		9,100			-
*   3.375% due 2033		20,450			-
*   0.700% due 2034		7,200			7,200
*   0.750% due 2034		82,800			82,800
*   0.700% due 2035		72,650			72,650
*   0.750% due 2035		98,900			98,900
*   1.050% due 2035		60,000			60,000
*   1.350% due 2035		163,965			163,965
		1,189,215			1,103,665
Total unsecured notes		2,137,410			1,974,770
Capital lease obligations (Note 6)		44,319			199
Net unamortized discount on debt		(58	)		(61	)
Long-term debt due within one year		(2,024,898	)		(1,441,196	)
Total long-term debt and other long-term obligations		571,448			533,712
TOTAL CAPITALIZATION	$	3,515,871		$	2,947,943
* Denotes variable rate issue with applicable year-end interest rate shown.
The accompanying Combined Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part of these statements.

10

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
										Accumulated
				Common Stock						Other
	Comprehensive			Number			Carrying			Comprehensive			Retained
	Income			of Shares			Value			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2006					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
Net income	$	506,410												506,410
Net unrealized loss on derivative instruments, net
of $5,512,000 of income tax benefits		(9,200	)								(9,200	)
Change in unrealized gain on investments, net of
$82,014,000 of income tax benefits		(137,689	)								(137,689	)
Pension and other postretirement benefits, net
of $47,853,000 of income tax benefits (Note 4)		(85,636	)								(85,636	)
Comprehensive income	$	273,885
Equity contribution from parent								280,000
Stock options exercised, restricted stock units
and other adjustments								13,262
Consolidated tax benefit allocation								6,045
Cash dividends declared on common stock														(43,000	)
Balance, December 31, 2008					7		$	1,464,229		$	(91,871	)	$	1,572,065
The accompanying Combined Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part of these statements.

11

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2008			2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	506,410		$	528,864		$	418,653
Adjustments to reconcile net income to net cash from
operating activities-
Provision for depreciation		231,899			192,912			179,163
Nuclear fuel and lease amortization		111,978			100,720			89,178
Deferred rents and lease market valuation liability		(43,263	)		69			-
Deferred income taxes and investment tax credits, net		116,626			(334,545	)		115,878
Investment impairment (Note 2(E))		115,207			22,817			10,255
Accrued compensation and retirement benefits		16,011			6,419			25,052
Commodity derivative transactions, net		5,100			5,930			24,144
Gain on asset sales		(38,858	)		(12,105	)		(37,663	)
Cash collateral, net		(60,621	)		(31,059	)		40,680
Pension trust contributions		-			(64,020	)		-
Decrease (increase) in operating assets-
Receivables		59,782			(99,048	)		(15,462	)
Materials and supplies		(59,983	)		56,407			(1,637	)
Prepayments and other current assets		(12,302	)		(13,812	)		(5,237	)
Increase (decrease) in operating liabilities-
Accounts payable		34,467			(104,599	)		19,970
Accrued taxes		(90,568	)		61,119			12,235
Accrued interest		1,398			1,143			4,101
Other		(40,355	)		(22,895	)		(20,469	)
Net cash provided from operating activities		852,928			294,317			858,841
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		618,375			427,210			1,156,910
Equity contributions from parent		280,000			700,000			-
Short-term borrowings, net		700,759			-			46,402
Redemptions and Repayments-
Common stock		-			(600,000	)		-
Long-term debt		(462,540	)		(1,536,411	)		(1,130,910	)
Short-term borrowings, net		-			(458,321	)		-
Common stock dividend payments		(43,000	)		(117,000	)		(8,454	)
Other		(5,147	)		(5,199	)		(6,899	)
Net cash provided from (used for) financing activities		1,088,447			(1,589,721	)		57,049
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(1,835,629	)		(738,709	)		(577,287	)
Proceeds from asset sales		23,077			12,990			34,215
Proceeds from sale and leaseback transaction		-			1,328,919			-
Sales of investment securities held in trusts		950,688			655,541			1,066,271
Purchases of investment securities held in trusts		(987,304	)		(697,763	)		(1,066,271	)
Loan repayments from (loans to) associated companies		(36,391	)		734,862			(333,030	)
Other		(55,779	)		(436	)		(39,788	)
Net cash provided from (used for) investing activities		(1,941,338	)		1,295,404			(915,890	)
Net change in cash and cash equivalents		37			-			-
Cash and cash equivalents at beginning of year		2			2			2
Cash and cash equivalents at end of year	$	39		$	2		$	2
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	92,103		$	136,121		$	173,337
Income taxes	$	196,963		$	613,814		$	155,771
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part of these statements.

12

OHIO EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They provide generation services to those franchise customers electing to retain OE and Penn as their power supplier. Until December 31, 2008, OE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of power supply for 2009 and beyond.

Results of Operations

Net income increased to $212 million in 2008 from $197 million in 2007. The increase primarily resulted from higher electric sales revenues and lower purchased power costs, partially offset by a decrease in the deferral of new regulatory assets and lower investment income.

Revenues

Revenues increased by $110 million, or 4.4%, in 2008 compared with 2007, primarily due to increases in retail generation revenues ($78 million) and distribution throughput revenues ($21 million).

Retail generation revenues increased primarily due to higher average prices across all customer classes, partially offset by decreased KWH sales. The higher average prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see Regulatory Matters – Ohio). Reduced summer usage in 2008 compared to 2007 contributed to the decreased KWH sales to residential and commercial customers (cooling degree days decreased by 27.7% and 26.1% in OE’s and Penn’s service territories, respectively). Commercial and industrial retail KWH sales were also impacted by increased customer shopping in Penn’s service territory in 2008 and weakening economic conditions.

Changes in retail generation sales and revenues in 2008 from 2007 are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(0.9	)%
Commercial		(1.6	)%
Industrial		(5.7	)%
Decrease in Generation Sales		(2.7	)%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	41
Commercial		19
Industrial		18
Increase in Generation Revenues	$	78

Revenues from distribution throughput increased by $21 million in 2008 compared to 2007 due to higher average unit prices for all customer classes, partially offset by lower KWH deliveries. The higher average prices resulted from Ohio transmission rider increases that became effective July 1, 2007 and July 1, 2008. The lower KWH deliveries to residential and commercial customers reflected the milder weather conditions described above. Reduced deliveries to industrial customers reflected the downturn in the economy.

Changes in distribution KWH deliveries and revenues in 2008 from 2007 are summarized in the following tables.

Distribution KWH Deliveries	Decrease
Residential		(1.4)	%
Commercial		(1.7)	%
Industrial		(4.8)	%
Other		(0.1)	%
Decrease in Distribution Deliveries		(2.7)	%

13

Distribution Revenues	Increase
	(In millions)
Residential	$	8
Commercial		6
Industrial		5
Other		2
Increase in Distribution Revenues	$	21

Expenses

Total expenses increased by $67 million in 2008 from 2007. The following table presents changes from the prior year by expense category.

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	(41	)
Other operating costs		(2	)
Provision for depreciation		2
Amortization of regulatory assets		24
Deferral of new regulatory assets		79
General taxes		5
Net Increase in Expenses	$	67

Lower purchased power costs in 2008 reflected the lower retail generation KWH sales, reducing the purchase volumes required. The decrease in other operating costs for 2008 was primarily due to lower employee benefit expenses. Higher depreciation expense in 2008 reflected capital additions since the end of 2007. Higher amortization of regulatory assets in 2008 was principally due to increased amortization of MISO transmission cost deferrals. The decrease in the deferral of new regulatory assets for 2008 was primarily due to lower MISO cost deferrals ($25 million) and lower RCP fuel deferrals ($59 million), as more transmission and generation costs were recovered from customers through PUCO-approved riders. The increase in general taxes for 2008 was primarily due to higher Pennsylvania capital stock taxes.

Other Income

Other income decreased $31 million in 2008 compared with 2007 primarily due to reductions in interest income on associated company notes receivable resulting from principal payments made in 2007 and a lower net receivable position from the regulated money pool in 2008 compared to 2007.

Income taxes decreased in 2008, primarily due to the favorable resolution of tax positions taken on federal returns in prior years.

Interest Rate Risk

OE’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 OE’s investment portfolio and debt obligations.

Comparison of Carrying Value to Fair Value
																					There-								Fair
Year of Maturity	2009				2010				2011				2012				2013				after				Total				Value
	(Dollars in millions)
Assets
Investments Other Than Cash
and Cash Equivalents:
Fixed Income		$	25			$	29			$	31			$	34			$	39			$	438			$	596			$	618
Average interest rate			8.5	%			8.6	%			8.6	%			8.7	%			8.7	%			7.0	%			7.4	%
Liabilities
Long-term Debt:				��
Fixed rate		$	1			$	65			$	1			$	1			$	2			$	1,062			$	1,132			$	1,123
Average interest rate			9.2	%			5.5	%			9.7	%			9.7	%			7.5	%			7.0	%			6.9	%
Variable rate																						$	100			$	100			$	100
Average interest rate																							2.3	%			2.3	%
Short-term Borrowings:		$	2																							$	2			$	2
Average interest rate			0.0	%																							0.0	%

14

Equity Price Risk

Included in OE’s nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $18 million as of December 31, 2008. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $2 million reduction in fair value as of December 31, 2008 (see Note 5). As part of the intra-system generation asset transfers in 2005, OE’s nuclear decommissioning trust investments were transferred to NGC with the exception of its retained leasehold interests in nuclear generation assets

Legal Proceedings

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

New Accounting Standards and Interpretations

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

15

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of Ohio Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2008 consolidated financial statements.

FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s 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.

FirstEnergy’s 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 Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s 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 Company’s 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 ten meetings in 2008.

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 Company’s 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 Company’s internal control over financial reporting was effective as of December 31, 2008.

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

16

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Ohio Edison Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of Ohio Edison Company and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 24, 2009

17

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2008			2007			2006
	(In thousands)
REVENUES (Note 3):
Electric sales	$	2,487,956		$	2,375,306		$	2,312,956
Excise and gross receipts tax collections		113,805			116,223			114,500
Total revenues		2,601,761			2,491,529			2,427,456
EXPENSES (Note 3):
Purchased power from affiliates		1,203,314			1,261,439			1,263,805
Purchased power from non-affiliates		114,972			98,344			12,170
Other operating costs		565,893			567,726			576,141
Provision for depreciation		79,444			77,405			72,982
Amortization of regulatory assets		216,274			191,885			190,245
Deferral of new regulatory assets		(98,541	)		(177,633	)		(159,465	)
General taxes		186,396			181,104			180,446
Total expenses		2,267,752			2,200,270			2,136,324
OPERATING INCOME		334,009			291,259			291,132
OTHER INCOME (EXPENSE) (Note 3):
Investment income		56,103			85,848			130,853
Miscellaneous income (expense)		(5,138	)		4,409			1,751
Interest expense		(75,058	)		(83,343	)		(90,355	)
Capitalized interest		414			266			2,198
Subsidiary's preferred stock dividend requirements		-			-			(597	)
Total other income (expense)		(23,679	)		7,180			43,850
INCOME BEFORE INCOME TAXES		310,330			298,439			334,982
INCOME TAXES		98,584			101,273			123,343
NET INCOME		211,746			197,166			211,639
PREFERRED STOCK DIVIDEND REQUIREMENTS
AND REDEMPTION PREMIUM		-			-			4,552
EARNINGS ON COMMON STOCK	$	211,746		$	197,166		$	207,087
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.

18

OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	146,343	$	732
Receivables-
Customers (less accumulated provisions of $6,065,000 and $8,032,000, respectively,
for uncollectible accounts)		277,377		248,990
Associated companies		234,960		185,437
Other (less accumulated provisions of $7,000 and $5,639,000, respectively,
for uncollectible accounts)		14,492		12,395
Notes receivable from associated companies		222,861		595,859
Prepayments and other		5,452		10,341
		901,485		1,053,754
UTILITY PLANT:
In service		2,903,290		2,769,880
Less - Accumulated provision for depreciation		1,113,357		1,090,862
		1,789,933		1,679,018
Construction work in progress		37,766		50,061
		1,827,699		1,729,079
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		256,974		258,870
Investment in lease obligation bonds (Note 6)		239,625		253,894
Nuclear plant decommissioning trusts		116,682		127,252
Other		100,792		36,037
		714,073		676,053
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		575,076		737,326
Pension assets (Note 4)		-		228,518
Property taxes		60,542		65,520
Unamortized sale and leaseback costs		40,130		45,133
Other		33,710		48,075
		709,458		1,124,572
	$	4,152,715	$	4,583,458
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	101,354	$	333,224
Short-term borrowings-
Associated companies		-		50,692
Other		1,540		2,609
Accounts payable-
Associated companies		131,725		174,088
Other		26,410		19,881
Accrued taxes		77,592		89,571
Accrued interest		25,673		22,378
Other		85,209		65,163
		449,503		757,606
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		1,294,054		1,576,175
Long-term debt and other long-term obligations		1,122,247		840,591
		2,416,301		2,416,766
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		653,475		781,012
Accumulated deferred investment tax credits		13,065		16,964
Asset retirement obligations		80,647		93,571
Retirement benefits		308,450		178,343
Deferred revenues - electric service programs		4,634		46,849
Other		226,640		292,347
		1,286,911		1,409,086
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	4,152,715	$	4,583,458
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.

19

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2008			2007
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, 175,000,000 shares authorized,
60 shares outstanding	$	1,224,416		$	1,220,512
Accumulated other comprehensive income (loss) (Note 2(F))		(184,385	)		48,386
Retained earnings (Note 10(A))		254,023			307,277
Total		1,294,054			1,576,175
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 10(C)):
Ohio Edison Company-
First mortgage bonds:
8.250% due 2018		25,000			-
8.250% due 2038		275,000			-
Total		300,000			-
Secured notes:
5.375% due 2028		-			13,522
6.895% weighted average interest rate due 2008-2010		1,324			3,900
Total		1,324			17,422
Unsecured notes:
4.000% due 2008		-			175,000
*   3.000% 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
*   3.800% due 2018		-			23,000
*   1.500% due 2023		50,000			50,000
6.875% due 2036		350,000			350,000
Total		850,000			1,081,000
Pennsylvania Power Company-
First mortgage bonds:
9.740% due 2008-2019		10,747			11,721
7.625% due 2023		6,500			6,500
Total		17,247			18,221
Secured notes:
5.400% due 2013		1,000			1,000
5.375% due 2028		-			1,734
Total		1,000			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)		4,219			329
Net unamortized discount on debt		(13,089	)		(8,791	)
Long-term debt due within one year		(101,354	)		(333,224	)
Total long-term debt and other long-term obligations		1,122,247			840,591
TOTAL CAPITALIZATION	$	2,416,301		$	2,416,766
* Denotes variable rate issue with applicable year-end interest rate shown.
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.

20

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
										Accumulated
				Common Stock						Other
	Comprehensive			Number			Carrying			Comprehensive			Retained
	Income			of Shares			Value			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2006					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 declared 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 declared on common stock														(150,000	)
Balance, December 31, 2007					60			1,220,512			48,386			307,277
Net income	$	211,746												211,746
Change in unrealized gain on investments, net of
$5,702,000 of income tax benefits		(10,370	)								(10,370	)
Pension and other postretirement benefits, net
of $121,425,000 of income tax benefits (Note 4)		(222,401	)								(222,401	)
Comprehensive loss	$	(21,025	)
Restricted stock units								(16	)
Stock-based compensation								1
Consolidated tax benefit allocation								3,919
Cash dividends declared on common stock														(265,000	)
Balance, December 31, 2008					60		$	1,224,416		$	(184,385	)	$	254,023
The accompanying Combined Notes to Consolidated Financial Statements as the relate to Ohio Edison Company are an integral part of these statements.

21

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2008			2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	211,746		$	197,166		$	211,639
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		79,444			77,405			72,982
Amortization of regulatory assets		216,274			191,885			190,245
Deferral of new regulatory assets		(98,541	)		(177,633	)		(159,465	)
Amortization of lease costs		(7,702	)		(7,425	)		(7,928	)
Deferred income taxes and investment tax credits, net		16,125			423			(68,259	)
Accrued compensation and retirement benefits		17,139			(46,313	)		5,004
Electric service prepayment programs		(42,215	)		(39,861	)		(34,983	)
Pension trust contributions		-			(20,261	)		-
Decrease (increase) in operating assets-
Receivables		(61,926	)		(57,461	)		103,925
Prepayments and other current assets		5,937			3,265			1,275
Increase (decrease) in operating liabilities-
Accounts payable		14,166			15,649			(53,798	)
Accrued taxes		(8,983	)		(81,079	)		23,436
Accrued interest		3,295			(2,334	)		16,379
Other		(247	)		6,129			6,617
Net cash provided from operating activities		344,512			59,555			307,069
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		292,169			-			593,978
Redemptions and Repayments-
Common stock		-			(500,000	)		(500,000	)
Preferred stock		-			-			(78,480	)
Long-term debt		(249,897	)		(112,497	)		(613,002	)
Short-term borrowings, net		(51,761	)		(114,475	)		(186,511	)
Dividend Payments-
Common stock		(315,000	)		(100,000	)		(148,000	)
Preferred stock		-			-			(1,423	)
Other		(3,432	)		-			(1,798	)
Net cash used for financing activities		(327,921	)		(826,972	)		(935,236	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(182,512	)		(145,311	)		(123,210	)
Sales of investment securities held in trusts		120,744			37,736			39,226
Purchases of investment securities held in trusts		(127,680	)		(43,758	)		(41,300	)
Loan repayments from (loans to) associated companies, net		373,138			(79,115	)		78,101
Collection of principal on long-term notes receivable		1,756			960,327			553,734
Cash investments		(57,792	)		37,499			112,584
Other		1,366			59			8,815
Net cash provided from investing activities		129,020			767,437			627,950
Net increase (decrease) in cash and cash equivalents		145,611			20			(217	)
Cash and cash equivalents at beginning of year		732			712			929
Cash and cash equivalents at end of year	$	146,343		$	732		$	712
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	67,508		$	80,958		$	57,243
Income taxes	$	118,834		$	133,170		$	156,610
The accompanying Combined Notes to Consolidated Financial Statements as the relate to Ohio Edison Company are an integral part of these statements.

22

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. Until December 31, 2008, CEI purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of power supply for 2009 and beyond.

Results of Operations

Net income in 2008 increased to $285 million from $276 million in 2007. The increase resulted primarily from the elimination of fuel costs and lower other operating costs, due to the assignment of leasehold interests in generating assets to FGCO, partially offset by lower revenues and regulatory asset deferrals and higher purchased power costs and regulatory asset amortization.

Revenues

Revenues decreased by $7 million, or 0.4%, in 2008 compared to 2007, primarily due to a decrease in wholesale generation revenues ($92 million), partially offset by increases in retail generation revenues ($64 million), distribution revenues ($6 million), and transmission revenues ($16 million).

Wholesale generation revenues decreased due to the assignment of CEI’s leasehold interests in the Bruce Mansfield Plant to FGCO in October 2007. Prior to the assignment, CEI sold power from its interests in the plant to FGCO.

Retail generation revenues increased in 2008 due to higher average unit prices across all customer classes, partially offset by a decrease in sales volume compared to 2007. The higher average unit prices were driven by the 2008 fuel cost recovery rider that became effective January 16, 2008 (see Regulatory Matters – Ohio). Milder weather in 2008, compared to 2007, contributed to the decrease in sales volume; a 13.6% decrease in cooling degrees days was partially offset by a 4.5% increase in heating degree days. Weakening economic conditions in CEI’s service territory contributed to reduced generation KWH sales in the industrial sector, primarily to automotive customers.

Changes in retail generation sales and revenues in 2008 compared to 2007 are summarized in the following tables:

Retail KWH Sales	Decrease
Residential		(0.3	)%
Commercial		(0.7	)%
Industrial		(2.6	)%
Decrease in Retail Sales		(1.4	)%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	23
Commercial		17
Industrial		24
Increase in Generation Revenues	$	64

Revenues from distribution throughput increased by $6 million in 2008 compared to 2007 primarily due to higher average unit prices for all customer classes, partially offset by decreases in KWH deliveries. The higher average unit prices resulted from transmission rider increases that became effective July 1, 2007 and July 1, 2008. The lower KWH deliveries in 2008 reflected the weather and economic impacts described above.

Changes in distribution KWH deliveries and revenues in 2008 compared to 2007 are summarized in the following tables.

Distribution KWH Deliveries	Decrease
Residential		(1.1	)%
Commercial		(1.9	)%
Industrial		(2.9	)%
Decrease in Distribution Deliveries		(2.1	)%

23

Distribution Revenues	Increase
	(In millions)
Residential	$	-
Commercial		3
Industrial		3
Increase in Distribution Revenues	$	6

Transmission revenues were higher in 2008, compared to 2007, due to increased MISO auction revenue rights. CEI defers the difference between revenue from its transmission rider and net transmission costs incurred, resulting in no material effect to current period earnings.

Expenses

Total expenses decreased by $9 million in 2008 compared to 2007. The following table presents the change from the prior year by expense category:

Expenses  - Changes	Increase (Decrease)
	(In millions)
Fuel costs	$	(40	)
Purchased power costs		22
Other operating costs		(51	)
Provision for depreciation		(3	)
Amortization of regulatory assets		19
Deferral of new regulatory assets		42
General taxes		2
Net Decrease in Expenses	$	(9	)

The absence of fuel costs in 2008 was due to the assignment of CEI’s leasehold interests in the Mansfield Plant to FGCO in October 2007. Prior to the assignment, CEI incurred fuel expenses and other operating costs related to its leasehold interest in the plant. Higher purchased power costs reflected higher unit prices, as provided for under the PSA with FES, partially offset by a decrease in volume due to lower KWH sales. Other operating costs were lower primarily due to the assignment of CEI’s leasehold interests in the Mansfield plant as described above. Higher amortization of regulatory assets resulted from increased transition cost amortization ($13 million) under the effective interest method and increased amortization of transmission cost deferrals ($6 million). The decrease in the deferral of new regulatory assets was primarily due to lower transmission cost deferrals ($16 million) and RCP fuel cost deferrals ($40 million), as more transmission and generation costs were recovered from customers through PUCO-approved riders, partially offset by higher RCP distribution deferrals ($12 million).

Other Expense

Other expense increased by $21 million in 2008 compared to 2007 primarily due to lower investment income and miscellaneous income, partially offset by a reduction in interest expense. Lower investment income resulted primarily from repayments during 2007 of notes receivable from associated companies. The lower interest expense was primarily due to long-term debt redemptions during 2007. Miscellaneous income decreased primarily due to reduced life insurance investment values and the absence of a make-whole payment in 2007 related to the redemption of lessor notes associated with CEI’s leasehold interest in Mansfield Unit 1, which was subsequently assigned to FGCO.

Income taxes decreased in 2008, primarily due to the favorable resolution of tax positions taken on federal returns in prior years.

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 CEI’s investment portfolio and debt obligations.

24

Comparison of Carrying Value to Fair Value
																					There-								Fair
Year of Maturity	2009				2010				2011				2012				2013				after				Total				Value
	(Dollars in millions)
Assets
Investments Other Than Cash
and Cash Equivalents:
Fixed Income		$	37			$	49			$	53			$	66			$	75			$	146			$	426			$	435
Average interest rate			7.7	%			7.7	%			7.7	%			7.7	%			7.7	%			7.7	%			7.7	%
Liabilities
Long-term Debt:
Fixed rate		$	150			$	18			$	20			$	22			$	324			$	1,207			$	1,741			$	1,618
Average interest rate			7.4	%			7.7	%			7.7	%			7.7	%			5.8	%			7.2	%			7.0	%
Short-term Borrowings:		$	228																							$	228			$	228
Average interest rate			1.8	%																							1.8	%

Legal Proceedings

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

New Accounting Standards and Interpretations

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

25

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of The Cleveland Electric Illuminating Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2008 consolidated financial statements.

FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s 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.

FirstEnergy’s 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 Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s 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 Company’s 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 ten meetings in 2008.

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 Company’s 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 Company’s internal control over financial reporting was effective as of December 31, 2008.

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

26

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of Directors of

The Cleveland Electric Illuminating Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 24, 2009

27

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2008			2007			2006
	(In thousands)
REVENUES (Note 3):
Electric sales	$	1,746,309		$	1,753,385		$	1,702,089
Excise tax collections		69,578			69,465			67,619
Total revenues		1,815,887			1,822,850			1,769,708
EXPENSES (Note 3):
Fuel		-			40,551			50,291
Purchased power (primarily from affiliates)		770,480			748,214			704,517
Other operating costs		259,438			310,274			290,904
Provision for depreciation		72,383			75,238			63,589
Amortization of regulatory assets		163,534			144,370			127,403
Deferral of new regulatory assets		(107,571	)		(149,556	)		(128,220	)
General taxes		143,058			141,551			134,663
Total expenses		1,301,322			1,310,642			1,243,147
OPERATING INCOME		514,565			512,208			526,561
OTHER INCOME (EXPENSE) (Note 3):
Investment income		34,392			57,724			100,816
Miscellaneous income (expense)		(2,455	)		7,902			6,428
Interest expense		(125,976	)		(138,977	)		(141,710	)
Capitalized interest		786			918			2,618
Total other expense		(93,253	)		(72,433	)		(31,848	)
INCOME BEFORE INCOME TAXES		421,312			439,775			494,713
INCOME TAXES		136,786			163,363			188,662
NET INCOME	$	284,526		$	276,412		$	306,051
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.

28

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	226	$	232
Receivables-
Customers (less accumulated provisions of $5,916,000 and
$7,540,000, respectively, for uncollectible accounts)		276,400		251,000
Associated companies		113,182		166,587
Other		13,834		12,184
Notes receivable from associated companies		19,060		52,306
Prepayments and other		2,787		2,327
		425,489		484,636
UTILITY PLANT:
In service		2,221,660		2,256,956
Less - Accumulated provision for depreciation		846,233		872,801
		1,375,427		1,384,155
Construction work in progress		40,651		41,163
		1,416,078		1,425,318
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes (Note 7)		425,715		463,431
Other		10,249		10,285
		435,964		473,716
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,688,521		1,688,521
Regulatory assets		783,964		870,695
Pension assets (Note 4)		-		62,471
Property taxes		71,500		76,000
Other		10,818		32,987
		2,554,803		2,730,674
	$	4,832,334	$	5,114,344
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	150,688	$	207,266
Short-term borrowings-
Associated companies		227,949		531,943
Accounts payable-
Associated companies		106,074		169,187
Other		7,195		5,295
Accrued taxes		87,810		94,991
Accrued interest		13,932		13,895
Other		40,095		34,350
		633,743		1,056,927
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		1,603,882		1,489,835
Long-term debt and other long-term obligations		1,591,586		1,459,939
		3,195,468		2,949,774
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		704,270		725,523
Accumulated deferred investment tax credits		13,030		18,567
Retirement benefits		128,738		93,456
Deferred revenues - electric service programs		3,510		27,145
Lease assignment payable to associated companies (Note 6)		40,827		131,773
Other		112,748		111,179
		1,003,123		1,107,643
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	4,832,334	$	5,114,344
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these balance sheets.

29

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2008			2007
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, 105,000,000 shares authorized,
67,930,743 shares outstanding	$	878,785		$	873,536
Accumulated other comprehensive loss (Note 2(F))		(134,857	)		(69,129	)
Retained earnings (Note 10(A))		859,954			685,428
Total		1,603,882			1,489,835
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 10(C)):
First mortgage bonds-
6.860% due 2008		-			125,000
8.875% due 2018		300,000			-
Total		300,000			125,000
Secured notes-
7.430% due 2009		150,000			150,000
7.880% due 2017		300,000			300,000
5.375% due 2028		-			5,993
*   3.750% due 2030		-			81,640
Total		450,000			537,633
Unsecured notes-
5.650% due 2013		300,000			300,000
5.700% due 2017		250,000			250,000
5.950% due 2036		300,000			300,000
7.664% due to associated companies 2009-2016 (Note 7)		141,210			153,044
Total		991,210			1,003,044
Capital lease obligations (Note 6)		3,062			3,748
Net unamortized discount on debt		(1,998	)		(2,220	)
Long-term debt due within one year		(150,688	)		(207,266	)
Total long-term debt and other long-term obligations		1,591,586			1,459,939
TOTAL CAPITALIZATION	$	3,195,468		$	2,949,774
* Denotes variable rate issue with applicable year-end interest rate shown.
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements.

30

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
										Accumulated
				Common Stock						Other
	Comprehensive			Number			Carrying			Comprehensive			Retained
	Income			of Shares			Value			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2006					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 declared 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 declared on common stock														(304,000	)
Balance, December 31, 2007					67,930,743			873,536			(69,129	)		685,428
Net income	$	284,526												284,526
Pension and other postretirement benefits, net
of $33,136,000 of income tax benefits (Note 4)		(65,728	)								(65,728	)
Comprehensive income	$	218,798
Restricted stock units								(1	)
Stock-based compensation								1
Consolidated tax benefit allocation								5,249
Cash dividends declared on common stock														(110,000	)
Balance, December 31, 2008					67,930,743		$	878,785		$	(134,857	)	$	859,954
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements.

31

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2008			2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	284,526		$	276,412		$	306,051
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		72,383			75,238			63,589
Amortization of regulatory assets		163,534			144,370			127,403
Deferral of new regulatory assets		(107,571	)		(149,556	)		(128,220	)
Deferred rents and lease market valuation liability					(357,679	)		(71,943	)
Deferred income taxes and investment tax credits, net		11,918			(22,767	)		(17,093	)
Accrued compensation and retirement benefits		1,563			3,196			2,367
Electric service prepayment programs		(23,634	)		(24,443	)		(19,673	)
Pension trust contributions		-			(24,800	)		-
Decrease (increase) in operating assets-
Receivables		66,963			209,426			(137,711	)
Prepayments and other current assets		(450	)		(152	)		160
Increase (decrease) in operating liabilities-
Accounts payable		13,787			(316,638	)		293,214
Accrued taxes		(3,149	)		(33,659	)		7,342
Accrued interest		37			(5,138	)		147
Other		6,290			706			(6,387	)
Net cash provided from (used for) operating activities		486,197			(225,484	)		419,246
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		300,000			249,602			298,416
Short-term borrowings, net		-			277,581			-
Redemptions and Repayments-
Common stock		-			-			(300,000	)
Long-term debt		(213,319	)		(492,825	)		(376,702	)
Short-term borrowings, net		(315,827	)		-			(143,272	)
Dividend Payments-
Common stock		(185,000	)		(204,000	)		(180,000	)
Other		(2,568	)		(2,709	)		(2,754	)
Net cash used for financing activities		(416,714	)		(172,351	)		(704,312	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(137,265	)		(149,131	)		(119,795	)
Loan repayments from (loans to) associated companies, net		33,246			6,714			(7,813	)
Collection of principal on long-term notes receivable		-			486,634			376,135
Investments in lessor notes		37,707			56,179			44,556
Other		(3,177	)		(2,550	)		(8,003	)
Net cash provided from (used for) investing activities		(69,489	)		397,846			285,080
Net increase (decrease) in cash and cash equivalents		(6	)		11			14
Cash and cash equivalents at beginning of year		232			221			207
Cash and cash equivalents at end of year	$	226		$	232		$	221
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	122,834		$	141,390		$	135,276
Income taxes	$	153,042		$	186,874		$	180,941
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements.

32

THE TOLEDO EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. Until December 31, 2008, TE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of power supply for 2009 and beyond.

Results of Operations

Net income in 2008 decreased to $75million from $91million in 2007. The decrease resulted primarily from lower electric sales revenues, higher purchased power costs and a decrease in the deferral of new regulatory assets, partially offset by lower other operating costs.

Revenues

Revenues decreased $68million, or 7.1%, in 2008 compared to 2007 due to lower wholesale generation revenues ($133 million), partially offset by increased retail generation revenues ($49million), distribution revenues ($7million) and transmission revenues ($9 million).

The decrease in wholesale revenues was primarily due to lower associated company sales of KWH from TE’s leasehold interests in generating plants. Revenues from TE’s leasehold interests in Beaver Valley Unit 2 decreased by $68 million due to the unit’s 39-day refueling outage in the second quarter of 2008 and the incremental pricing impacts related to the termination of TE’s sale agreement with CEI. At the end of 2007, TE terminated its Beaver Valley Unit 2 output sale agreement with CEI. During 2008, TE sold the 158 MW entitlement from its 18.26% leasehold interest in the unit to NGC. Revenues from PSA sales decreased by $69 million in 2008 due to the assignment of TE’s leasehold interests in the Bruce Mansfield Plant to FGCO in October 2007. Prior to the assignment, TE sold power from its interests in the plant to FGCO.

Retail generation revenues increased in 2008 due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers compared to 2007. The higher average prices were driven by the 2008 fuel cost recovery rider that became effective January 16, 2008 (see Regulatory Matters – Ohio). The increase in sales to residential and commercial customers was due primarily to less customer shopping; generation services provided by alternative suppliers as a percentage of total sales delivered in TE’s franchise area to residential and commercial customers decreased by one and five percentage points, respectively. Reduced industrial KWH sales, principally to the automotive and steel sectors, reflected weakening economic conditions.

Changes in retail electric generation KWH sales and revenues in 2008 from 2007 are summarized in the following tables.

	Increase
Retail KWH Sales	(Decrease)
Residential		0.5	%
Commercial		6.4	%
Industrial		(6.8	)%
Net Decrease in Retail KWH Sales		(2.4	)%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	11
Commercial		16
Industrial		22
Increase in Retail Generation Revenues	$	49

33

Revenues from distribution throughput increased by $7 million in 2008 compared to 2007 due to higher average unit prices for all customer classes, partially offset by lower KWH deliveries. The higher average prices resulted from PUCO-approved transmission rider increases that became effective July 1, 2007 and July 1, 2008. The reduction in commercial and industrial KWH deliveries reflected the economic downturn.

Changes in distribution KWH deliveries and revenues in 2008 from 2007 are summarized in the following tables.

Distribution KWH Deliveries	Decrease
Residential		(0.6	)%
Commercial		(1.3	)%
Industrial		(6.8	)%
Decrease in Distribution Deliveries		(3.8	)%

Distribution Revenues	Increase
	(In millions)
Residential	$	4
Commercial		2
Industrial		1
Increase in Distribution Revenues	$	7

Expenses

Total expenses decreased $24 million in 2008 from 2007. The following table presents changes from the prior year by expense category.

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	15
Other operating costs		(89	)
Provision for depreciation		(4	)
Amortization of regulatory assets		5
Deferral of new regulatory assets		48
General taxes		1
Net Decrease in Expenses	$	(24	)

Higher purchased power costs primarily reflected higher unit prices as provided for under the PSA with FES, partially offset by a decrease in volume due to lower retail generation KWH sales. Other operating costs decreased primarily due to the reversal of the above-market lease liability ($31 million) associated with TE’s leasehold interest in Beaver Valley Unit 2, as a result of the termination of the CEI sale agreement described above, and lower fuel costs ($26 million) and other operating costs ($30 million) due to the assignment of TE’s leasehold interests in the Mansfield Plant in October 2007. These decreases were partially offset by increased costs ($8 million) associated with TE’s leasehold interests in Beaver Valley Unit 2, due to a refueling outage in the second quarter of 2008. Depreciation expense decreased primarily due to the transfer of leasehold improvements for the Mansfield Plant and Beaver Valley Unit 2 to FGCO and NGC, respectively, during 2008.

The increase in the amortization of regulatory assets was primarily due to increased amortization of transmission cost deferrals ($7 million), partially offset by lower amortization of transition cost deferrals ($3 million). The change in the deferral of new regulatory assets was primarily due to lower RCP distribution cost deferrals ($24 million) due to the application of overrecovered RTC revenues to the deferred balance, and lower deferred fuel costs ($19 million) and MISO transmission expenses ($5 million), as more generation and transmission costs were recovered from customers through PUCO-approved riders. Higher general taxes primarily reflected increased KWH taxes, property taxes and Ohio commercial activity taxes.

Other Expense

Other expense decreased $4 million in 2008 compared to 2007, primarily due to lower interest expense, partially offset by lower investment income. The lower interest expense resulted from lower money pool borrowings from associated companies in 2008 and the redemption of long-term debt ($89 million aggregate principal amount in 2008 and the second half of 2007). The decrease in investment income resulted primarily from repayments in 2007 of notes receivable from associated companies, customer accounts receivable financing activity and redemptions of lessor notes.

34

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 TE’s investment portfolio and debt obligations.

Comparison of Carrying Value to Fair Value
																					There-								Fair
Year of Maturity	2009				2010				2011				2012				2013				after				Total				Value
	(Dollars in millions)
Assets
Investments Other Than Cash and Cash Equivalents:
Fixed Income		$	12			$	18			$	21			$	22			$	25			$	165			$	263			$	274
Average interest rate			7.7	%			7.7	%			7.7	%			7.7	%			7.7	%			6.2	%			6.8	%
Liabilities
Long-term Debt:
Fixed rate																						$	300			$	300			$	244
Average interest rate																							6.2	%			6.2	%
Short-term Borrowings:		$	111																							$	111			$	111
Average interest rate			1.5	%																							1.5	%

Legal Proceedings

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

New Accounting Standards and Interpretations

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

35

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of The Toledo Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2008 consolidated financial statements.

FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s 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.

FirstEnergy’s 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 Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s 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 Company’s 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 ten meetings in 2008.

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 Company’s 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 Company’s internal control over financial reporting was effective as of December 31, 2008.

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

36

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of The Toledo Edison Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of The Toledo Edison Company and its subsidiary at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 24, 2009

37

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2008			2007			2006
	(In thousands)
REVENUES (Note 3):
Electric sales	$	865,016		$	934,772		$	899,930
Excise tax collections		30,489			29,173			28,071
Total revenues		895,505			963,945			928,001
EXPENSES (Note 3):
Purchased power (primarily from affiliates)		413,344			398,423			368,654
Other operating costs		190,441			279,047			284,561
Provision for depreciation		32,422			36,743			33,310
Amortization of regulatory assets		109,201			104,348			95,032
Deferral of new regulatory assets		(15,097	)		(62,664	)		(54,946	)
General taxes		52,324			50,640			50,869
Total expenses		782,635			806,537			777,480
OPERATING INCOME		112,870			157,408			150,521
OTHER INCOME (EXPENSE) (Note 3):
Investment income		22,823			27,713			38,187
Miscellaneous expense		(7,832	)		(6,651	)		(7,379	)
Interest expense		(23,286	)		(34,135	)		(23,179	)
Capitalized interest		164			640			1,123
Total other income (expense)		(8,131	)		(12,433	)		8,752
INCOME BEFORE INCOME TAXES		104,739			144,975			159,273
INCOME TAXES		29,824			53,736			59,869
NET INCOME		74,915			91,239			99,404
PREFERRED STOCK DIVIDEND REQUIREMENTS		-			-			9,409
EARNINGS ON COMMON STOCK	$	74,915		$	91,239		$	89,995
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.

38

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	14	$	22
Receivables-
Customers		751		449
Associated companies		61,854		88,796
Other (less accumulated provisions of $203,000 and $615,000,
respectively, for uncollectible accounts)		23,336		3,116
Notes receivable from associated companies		111,579		154,380
Prepayments and other		1,213		865
		198,747		247,628
UTILITY PLANT:
In service		870,911		931,263
Less - Accumulated provision for depreciation		407,859		420,445
		463,052		510,818
Construction work in progress		9,007		19,740
		472,059		530,558
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes (Note 6)		142,687		154,646
Long-term notes receivable from associated companies		37,233		37,530
Nuclear plant decommissioning trusts		73,500		66,759
Other		1,668		1,756
		255,088		260,691
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		500,576		500,576
Regulatory assets		109,364		203,719
Pension assets (Note 4)		-		28,601
Property taxes		22,970		21,010
Other		48,706		20,496
		681,616		774,402
	$	1,607,510	$	1,813,279
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	34	$	34
Accounts payable-
Associated companies		70,455		245,215
Other		4,812		4,449
Notes payable to associated companies		111,242		13,396
Accrued taxes		24,433		30,245
Lease market valuation liability		36,900		36,900
Other		23,183		22,747
		271,059		352,986
CAPITALIZATION (See Statements of Capitalization):
Common stockholder's equity		480,050		485,191
Long-term debt and other long-term obligations		299,626		303,397
		779,676		788,588
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		78,905		103,463
Accumulated deferred investment tax credits		6,804		10,180
Lease market valuation liability (Note 6)		273,100		310,000
Retirement benefits		73,106		63,215
Asset retirement obligations		30,213		28,366
Deferred revenues - electric service programs		1,458		12,639
Lease assignment payable to associated companies		30,529		83,485
Other		62,660		60,357
		556,775		671,705
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	1,607,510	$	1,813,279
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these balance sheets.

39

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2008			2007
	(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		175,879			173,169
Accumulated other comprehensive loss (Note 2(F))		(33,372	)		(10,606	)
Retained earnings (Note 10(A))		190,533			175,618
Total		480,050			485,191
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 10(C)):
Secured notes-
5.375% due 2028		-			3,751
Unsecured notes-
6.150% due 2037		300,000			300,000
Capital lease obligations (Note 6)		80			114
Net unamortized discount on debt		(420	)		(434	)
Long-term debt due within one year		(34	)		(34	)
Total long-term debt and other long-term obligations		299,626			303,397
TOTAL CAPITALIZATION	$	779,676		$	788,588
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.

40

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
													Accumulated
				Common Stock						Other			Other
	Comprehensive			Number			Par			Paid-In			Comprehensive			Retained
	Income			of Shares			Value			Capital			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2006					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 declared 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 declared on common stock																	(120,000	)
Balance, December 31, 2007					29,402,054			147,010			173,169			(10,606	)		175,618
Net income	$	74,915															74,915
Unrealized gain on investments, net
of $1,421,000 of income taxes		2,372												2,372
Pension and other postretirement benefits, net
of $11,630,000 of income tax benefits (Note 4)		(25,138	)											(25,138	)
Comprehensive income	$	52,149
Restricted stock units											47
Stock-based compensation											1
Consolidated tax benefit allocation											2,662
Cash dividends declared on common stock																	(60,000	)
Balance, December 31, 2008					29,402,054		$	147,010		$	175,879		$	(33,372	)	$	190,533
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.

41

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2008			2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	74,915		$	91,239		$	99,404
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		32,422			36,743			33,310
Amortization of regulatory assets		109,201			104,348			95,032
Deferral of new regulatory assets		(15,097	)		(62,664	)		(54,946	)
Deferred rents and lease market valuation liability		(37,938	)		265,981			(32,925	)
Deferred income taxes and investment tax credits, net		(16,869	)		(26,318	)		(37,133	)
Accrued compensation and retirement benefits		1,483			5,276			4,415
Electric service prepayment programs		(11,181	)		(10,907	)		(9,060	)
Pension trust contribution		-			(7,659	)		-
Decrease (increase) in operating assets-
Receivables		20,186			(64,489	)		6,387
Prepayments and other current assets		(348	)		(13	)		208
Increase (decrease) in operating liabilities-
Accounts payable		(164,397	)		8,722			39,847
Accrued taxes		(5,812	)		(14,954	)		(2,026	)
Accrued interest		(17	)		(1,350	)		1,899
Other		(3,289	)		5,188			4,640
Net cash provided from (used for) operating activities		(16,741	)		329,143			149,052
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			-			299,550
Short-term borrowings, net		97,846			-			62,909
Redemptions and Repayments-
Common stock		-			-			(225,000	)
Preferred stock		-			-			(100,840	)
Long-term debt		(3,860	)		(85,797	)		(202,550	)
Short-term borrowings, net		-			(153,567	)		-
Dividend Payments-
Common stock		(70,000	)		(85,000	)		(75,000	)
Preferred stock		-			-			(4,569	)
Other		(131	)		-			(2,887	)
Net cash provided from (used for) financing activities		23,855			(324,364	)		(248,387	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(57,385	)		(58,871	)		(61,232	)
Loan repayments from (loans to) associated companies, net		42,822			(51,002	)		(52,178	)
Collection of principal on long-term notes receivable		276			91,308			202,787
Redemption of lessor notes (Note 6)		11,959			14,847			9,305
Sales of investment securities held in trusts		37,931			44,682			53,458
Purchases of investment securities held in trusts		(40,960	)		(47,853	)		(53,724	)
Other		(1,765	)		2,110			926
Net cash provided from (used for) investing activities		(7,122	)		(4,779	)		99,342
Net change in cash and cash equivalents		(8	)		-			7
Cash and cash equivalents at beginning of year		22			22			15
Cash and cash equivalents at end of year	$	14		$	22		$	22
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	22,203		$	33,841		$	17,785
Income taxes	$	62,879		$	73,845		$	95,753
The accompanying Combined Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.

42

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also provides generation services to franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.

Results of Operations

Net income increased to $187million in 2008 from $186million in 2007. The increase was primarily due to higher operating revenues, lower other operating costs and lower amortization of regulatory assets, partially offset by higher purchased power costs and other expenses.

Revenues

Revenues increased $228 million, or 7%, in 2008 compared with 2007 due to higher retail generation revenues ($182 million) and higher wholesale revenues ($62 million), partially offset by a decrease in distribution throughput ($7 million).

Retail generation revenues from all customer classes increased due to higher unit prices resulting from the BGS auctions effective June 1, 2007, and June 1, 2008, partially offset by decreased retail generation KWH sales. Residential and commercial sales volumes decreased primarily as a result of milder weather (heating degree days and cooling degree days decreased by 2.3% and 6.4%, respectively, in 2008 compared to 2007). Customer shopping also contributed to the decreased sales volumes in the commercial sector (shopping increased by 3.5 percentage points in 2008 compared to 2007). Industrial sales volumes decreased primarily due to weakening economic conditions and increased customer shopping.

Changes in retail generation KWH sales and revenues by customer class in 2008 compared to 2007 are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(1.7)	%
Commercial		(6.1)	%
Industrial		(6.3)	%
Decrease in Generation Sales		(3.7)	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	124
Commercial		52
Industrial		6
Increase in Generation Revenues	$	182

Wholesale generation revenues increased $62million in 2008 primarily due to higher market prices for NUG sales in PJM, partially offset by a decrease in sales volume compared to 2007.

JCP&L defers amounts by which the costs of supplying BGS and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates from retail customers and revenues from the sale of NUG power.

Distribution revenues decreased $7 million in 2008 compared to 2007 due to lower KWH deliveries, reflecting the weather and economic impacts described above, partially offset by a slight increase in composite unit prices.

Changes in distribution KWH deliveries and revenues by customer class in 2008 compared to 2007 are summarized in the following tables:

Distribution KWH Deliveries	Decrease
Residential		(1.7)	%
Commercial		(1.6)	%
Industrial		(3.9)	%
Decrease in Distribution Deliveries		(2.0)	%

43

Distribution Revenues	Decrease
	(In millions)
Residential	$	(1	)
Commercial		(5	)
Industrial		(1	)
Decrease in Distribution Revenues	$	(7	)

Expenses

Total expenses increased by $214 million in 2008 compared to 2007. The following table presents changes from the prior year period by expense category:

Expenses  - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	248
Other operating costs		(23	)
Provision for depreciation		11
Amortization of regulatory assets		(23	)
General taxes		1
Net increase in expenses	$	214

Purchased power costs increased in 2008 primarily due to higher unit prices resulting from the BGS auctions effective June 1, 2007, and June 1, 2008, partially offset by a decrease in purchases due to the lower generation KWH sales discussed above. Other operating costs decreased primarily as a result of lower professional and contractor costs charged to expense (more costs were dedicated to capital projects in 2008) and lower employee benefit expenses. Depreciation expense increased primarily due to an increase in depreciable property during 2007. Amortization of regulatory assets decreased in 2008 primarily due to the completion in December 2007 of regulatory asset recovery associated with TMI-2 and lower transition cost amortization due to the lower KWH deliveries discussed above.

Other Expenses

Other expenses increased by $15 million in 2008 compared to 2007 primarily due to interest expense associated with JCP&L’s $550 million issuance of senior notes in May 2007, reduced life insurance investment values and lower interest income on regulatory asset balances.

Sale of Investment

On April 17, 2008, JCP&L closed the sale of its 86-MW Forked River Power Plant to Maxim Power Corp. for $20 million. In conjunction with this sale, FES entered into a 10-year tolling agreement with Maxim for the entire capacity of the plant. The sale is subject to regulatory accounting and did not have a material impact on JCP&L’s earnings in 2008. The New Jersey Rate Counsel has appealed the NJBPU’s approval of the sale to the Appellate Division of the Superior Court of New Jersey, where it is currently pending.

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. FirstEnergy’s 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. Certain 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 or regulatory liability for below-market costs. The change in the fair value of commodity derivative contracts related to energy production during 2008 is summarized in the following table:

44

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, 2008	$	(740	)	$	-	$	(740	)
Additions/Changes in value of existing contracts		1			-		1
Settled contracts		229			-		229
Net Liabilities - Derivatives Contracts as of December 31, 2008(1)	$	(510	)	$	-	$	(510	)
Impact of Changes in Commodity Derivative Contracts(2)
Income Statement Effects (Pre-Tax)	$	-		$	-	$	-
Balance Sheet Effects:
Regulatory Asset (Net)	$	(230	)	$	-	$	(230	)

(1) Includes $510 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, 2008 as follows:

Balance Sheet Classification	Non-Hedge			Hedge		Total
	(In millions)
Non-Current-
Other deferred charges	$	22		$	-	$	22
Other noncurrent liabilities		(532	)		-		(532	)
Net liabilities	$	(510	)	$	-	$	(510	)

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, 2008 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2009				2010				2011				2012				2013				Thereafter				Total
	(In millions)
Broker quote sheets(1)		$	(161	)		$	(149	)		$	(109	)		$	(41	)		$	-			$	-			$	(460	)
Prices based on models			-				-				-				-				(25	)			(25	)			(50	)
Total(2)		$	(161	)		$	(149	)		$	(109	)		$	(41	)		$	(25	)		$	(25	)		$	(510	)

(1) Validated by observable market transactions.

(2) Includes $510 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, 2008. Based on derivative contracts held as of December 31, 2008, 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.

45

Comparison of Carrying Value to Fair Value
																					There-								Fair
Year of Maturity	2009				2010				2011				2012				2013				after				Total				Value
(Dollars in millions)
Assets
Investments Other Than Cash and Cash Equivalents:
Fixed Income						$	1															$	258			$	259			$	259
Average interest rate							4.0	%															4.6	%			4.6	%
Liabilities
Long-term Debt:
Fixed rate		$	29			$	31			$	32			$	34			$	36			$	1,407			$	1,569			$	1,520
Average interest rate			5.3	%			5.4	%			5.6	%			5.7	%			5.7	%			5.8	%			5.8	%
Short-term Borrowings:		$	121																							$	121			$	121
Average interest rate			1.5	%																							1.5	%

Equity Price Risk

Included in JCP&L’s nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $66 million as of December 31, 2008. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $7 million reduction in fair value as of December 31, 2008 (see Note 5).

Legal Proceedings

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

New Accounting Standards and Interpretations

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

46

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of Jersey Central Power & Light Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2008 consolidated financial statements.

FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s 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.

FirstEnergy’s 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 Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s 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 Company’s 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 ten meetings in 2008.

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 Company’s 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 Company’s internal control over financial reporting was effective as of December 31, 2008.

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

47

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of Directors of

Jersey Central Power & Light Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of Jersey Central Power & Light Company and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 24, 2009

48

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2008			2007			2006
	(In thousands)
REVENUES (Note 3):
Electric sales	$	3,420,772		$	3,191,999		$	2,617,390
Excise tax collections		51,481			51,848			50,255
Total revenues		3,472,253			3,243,847			2,667,645
EXPENSES (Note 3):
Purchased power from affiliates		-			-			25,102
Purchased power from non-affiliates		2,206,251			1,957,975			1,496,227
Other operating costs		302,894			325,814			320,847
Provision for depreciation		96,482			85,459			83,172
Amortization of regulatory assets		364,816			388,581			274,704
General taxes		67,340			66,225			63,925
Total expenses		3,037,783			2,824,054			2,263,977
OPERATING INCOME		434,470			419,793			403,668
OTHER INCOME (EXPENSE):
Miscellaneous income (expense)		(1,037	)		8,570			13,323
Interest expense (Note 3)		(99,459	)		(96,988	)		(83,411	)
Capitalized interest		1,245			3,789			3,758
Total other expense		(99,251	)		(84,629	)		(66,330	)
INCOME BEFORE INCOME TAXES		335,219			335,164			337,338
INCOME TAXES		148,231			149,056			146,731
NET INCOME		186,988			186,108			190,607
PREFERRED STOCK DIVIDEND REQUIREMENTS		-			-			1,018
EARNINGS ON COMMON STOCK	$	186,988		$	186,108		$	189,589
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements.

49

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	66	$	94
Receivables-
Customers (less accumulated provisions of $3,230,000 and $3,691,000,
respectively, for uncollectible accounts)		340,485		321,026
Associated companies		265		21,297
Other		37,534		59,244
Notes receivable - associated companies		16,254		18,428
Prepaid taxes		10,492		1,012
Other		18,066		17,603
		423,162		438,704
UTILITY PLANT:
In service		4,307,556		4,175,125
Less - Accumulated provision for depreciation		1,551,290		1,516,997
		2,756,266		2,658,128
Construction work in progress		77,317		90,508
		2,833,583		2,748,636
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		181,468		176,512
Nuclear plant decommissioning trusts		143,027		175,869
Other		2,145		2,083
		326,640		354,464
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		1,228,061		1,595,662
Goodwill		1,810,936		1,826,190
Pension assets (Note 4)		-		100,615
Other		29,946		29,809
		3,068,943		3,552,276
	$	6,652,328	$	7,094,080
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	29,094	$	27,206
Short-term borrowings-
Associated companies		121,380		130,381
Accounts payable-
Associated companies		12,821		7,541
Other		198,742		193,848
Accrued taxes		20,561		3,124
Accrued interest		9,197		9,318
Other		133,091		103,286
		524,886		474,704
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		2,729,010		3,017,864
Long-term debt and other long-term obligations		1,531,840		1,560,310
		4,260,850		4,578,174
NONCURRENT LIABILITIES:
Power purchase contract liability		531,686		763,173
Accumulated deferred income taxes		689,065		800,214
Nuclear fuel disposal costs		196,235		192,402
Asset retirement obligations		95,216		89,669
Retirement benefits		190,182		2,468
Other		164,208		193,276
		1,866,592		2,041,202
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	6,652,328	$	7,094,080
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these balance sheets.

50

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2008			2007
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, $10 par value, 16,000,000 shares authorized,
14,421,637 shares outstanding	$	144,216		$	144,216
Other paid-in capital		2,644,756			2,655,941
Accumulated other comprehensive loss (Note 2(F))		(216,538	)		(19,881	)
Retained earnings (Note 10(A))		156,576			237,588
Total		2,729,010			3,017,864
LONG-TERM DEBT (Note 10(C)):
Secured notes-
5.390% due 2008-2010		33,469			52,273
5.250% due 2008-2012		33,229			41,631
5.810% due 2010-2013		77,075			77,075
5.410% due 2012-2014		25,693			25,693
6.160% due 2013-2017		99,517			99,517
5.520% due 2014-2018		49,220			49,220
5.610% due 2018-2021		51,139			51,139
Total		369,342			396,548
Unsecured notes-
5.625% due 2016		300,000			300,000
5.650% due 2017		250,000			250,000
4.800% due 2018		150,000			150,000
6.400% due 2036		200,000			200,000
6.150% due 2037		300,000			300,000
Total		1,200,000			1,200,000
Net unamortized discount on debt		(8,408	)		(9,032	)
Long-term debt due within one year		(29,094	)		(27,206	)
Total long-term debt		1,531,840			1,560,310
TOTAL CAPITALIZATION	$	4,260,850		$	4,578,174
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements.

51

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
													Accumulated
				Common Stock						Other			Other
	Comprehensive			Number			Par			Paid-In			Comprehensive			Retained
	Income			of Shares			Value			Capital			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2006					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 declared 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 declared 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
Net income	$	186,988															186,988
Net unrealized gain on derivative instruments		276												276
Pension and other postretirement benefits, net
of $131,317,000 of income tax benefits (Note 4)		(196,933	)											(196,933	)
Comprehensive loss	$	(9,669	)
Restricted stock units											3
Stock-based compensation											1
Consolidated tax benefit allocation											4,065
Cash dividends declared on common stock																	(268,000	)
Purchase accounting fair value adjustment											(15,254	)
Balance, December 31, 2008					14,421,637		$	144,216		$	2,644,756		$	(216,538	)	$	156,576
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements.

52

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2008			2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	186,988		$	186,108		$	190,607
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		96,482			85,459			83,172
Amortization of regulatory assets		364,816			388,581			274,704
Deferred purchased power and other costs		(165,071	)		(203,157	)		(281,498	)
Deferred income taxes and investment tax credits, net		12,834			(30,791	)		43,896
Accrued compensation and retirement benefits		(35,791	)		(23,441	)		(12,670	)
Cash collateral from (returned to) suppliers		23,106			(31,938	)		(109,108	)
Pension trust contributions		-			(17,800	)		-
Decrease (increase) in operating assets-
Receivables		8,042			(73,259	)		1,103
Materials and supplies		348			(364	)		61
Prepaid taxes		(9,562	)		12,321			5,385
Other current assets		(38	)		2,096			(2,134	)
Increase (decrease) in operating liabilities-
Accounts payable		10,174			(39,396	)		53,330
Accrued taxes		2,582			11,658			(52,905	)
Accrued interest		(121	)		(5,140	)		(5,458	)
Other		(13,002	)		5,369			1,272
Net cash provided from operating activities		481,787			266,306			189,757
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			543,807			382,400
Short-term borrowings, net		-			-			5,194
Redemptions and Repayments-
Long-term debt		(27,206	)		(325,337	)		(207,231	)
Short-term borrowings, net		(9,001	)		(56,159	)		-
Common stock		-			(125,000	)		(77,000	)
Preferred stock		-			-			(13,312	)
Dividend Payments-
Common stock		(268,000	)		(94,000	)		(100,000	)
Preferred stock		-			-			(354	)
Other		(80	)		(609	)		-
Net cash used for financing activities		(304,287	)		(57,298	)		(10,303	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(178,358	)		(199,856	)		(160,264	)
Proceeds from asset sales		20,000			-			-
Loan repayments from (loans to) associated companies, net		2,173			6,029			(6,037	)
Sales of investment securities held in trusts		248,185			195,973			216,521
Purchases of investment securities held in trusts		(265,441	)		(212,263	)		(219,416	)
Other		(4,087	)		1,162			(10,319	)
Net cash used for investing activities		(177,528	)		(208,955	)		(179,515	)
Net increase (decrease) in cash and cash equivalents		(28	)		53			(61	)
Cash and cash equivalents at beginning of year		94			41			102
Cash and cash equivalents at end of year	$	66		$	94		$	41
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	99,731		$	102,492		$	80,101
Income taxes	$	145,943		$	156,073		$	134,279
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements.

53

METROPOLITAN EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier. Met-Ed has a partial requirements wholesale power sales agreement with FES, to supply a portion of each of its default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty day written notice prior to the end of the calendar year.

Results of Operations

In 2008, Met-Ed reported net income of $88 million compared to $95 million 2007. The decrease was primarily due to higher purchased power costs, net amortization of regulatory assets and other operating costs, partially offset by higher revenues.

Revenues

Revenues increased by $142 million, or 9.4%, in 2008 compared to 2007 principally due to higher wholesale generation revenues and distribution throughput revenues. Wholesale revenues increased by $111million in 2008 compared to 2007, primarily reflecting higher PJM spot market prices. Increased distribution throughput revenues were partially offset by decreases in retail generation revenues and PJM transmission revenues.

In 2008, retail generation revenues decreased $3million primarily due to lower KWH sales to industrial customers due to the weakening economy, partially offset by higher KWH sales to commercial customers and higher composite unit prices in all customer classes.

Changes in retail generation sales and revenues in 2008 compared to 2007 are summarized in the following tables:

	Increase
Retail Generation KWH Sales	(Decrease)
Residential		-
Commercial		1.3	%
Industrial		(4.0	)%
Net Decrease in Retail Generation Sales		(0.7	)%

	Increase
Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	1
Commercial		3
Industrial		(7	)
Net Decrease in Retail Generation Revenues	$	(3	)

Revenues from distribution throughput increased $47 million in 2008 compared to 2007. Higher rates received for transmission services, resulting from the annual update of Met-Ed’s TSC rider effective June 1, 2008 (see Regulatory Matters). Decreased KWH deliveries in the industrial customer class were partially offset by increased KWH deliveries to commercial customers.

Changes in distribution KWH deliveries and revenues in 2008 compared to 2007 are summarized in the following tables:

	Increase
Distribution KWH Deliveries	(Decrease)
Residential		-
Commercial		1.3	%
Industrial		(4.0	)%
Net Decrease in Distribution Deliveries		(0.7	)%

54

Distribution Revenues	Increase
	(In millions)
Residential	$	21
Commercial		17
Industrial		9
Increase in Distribution Revenues	$	47

Transmission revenues decreased by $15million in 2008 compared to 2007, primarily due to decreased auction revenue rights in PJM. Met-Ed defers the difference between transmission revenues and net transmission costs incurred, resulting in no material effect to current period earnings.

Expenses

Total operating expenses increased by $153 million in 2008 compared to 2007. The following table presents changes from the prior year by expense category:

Expenses – Changes	Increase
	(In millions)
Purchased power costs	$	112
Other operating costs		10
Provision for depreciation		2
Amortization of regulatory assets		8
Deferral of new regulatory assets		15
General taxes		6
Increase in expenses	$	153

Purchased power costs increased by $112 million in 2008 due to higher composite unit prices paid to non-affiliates in the PJM market. Other operating costs increased by $10 million in 2008 primarily due to higher transmission expenses resulting from higher transmission losses and congestion costs, partially offset by the absence of costs associated with an ice storm in Met-Ed’s service territory in the fourth quarter of 2007 that caused widespread damage to its electrical system.

Amortization of regulatory assets increased in 2008 due to higher CTC revenues applied to non-NUG costs. The deferral of new regulatory assets decreased in 2008 primarily due to the absence of the 2007 deferral of previously expensed decommissioning costs ($15 million) for the Saxton nuclear research facility and decreased transmission cost deferrals ($6 million) partially offset by higher universal service charge deferrals ($6 million).

In 2008, general taxes increased primarily due to higher gross receipts taxes resulting from increased sales revenues.

Other Expense

Other expense increased $4 million in 2008 primarily due to a $10 million decrease in interest earned on stranded regulatory assets, reflecting lower regulatory asset balances, partially offset by lower interest expense of $7 million due to decreased borrowings from the regulated money pool.

Market Risk Information

Met-Ed uses various market risk sensitive instruments, including derivative contracts, 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.

55

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. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. Certain of Met-Ed’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 or regulatory liability for below-market costs. The change in the fair value of commodity derivative contracts related to energy production during 2008 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 liabilities as of January 1, 2008	$	(9	)	$	-	$	(9	)
Additions/Changes in value of existing contracts		144			-		144
Settled contracts		29			-		29
Net Assets - Derivatives Contracts as of December 31, 2008(1)	$	164		$	-	$	164
Impact of Changes in Commodity Derivative Contracts(2)
Income Statement Effects (Pre-Tax)	$	-		$	-	$	-
Balance Sheet Effects:
Regulatory Liability (net)	$	(173	)	$	-	$	(173	)

(1) Includes $164 million in non-hedge commodity derivative contracts (primarily with NUGs) that are 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, 2008 as follows:

	Non-Hedge			Hedge		Total
	(In millions)
Non-Current-
Other deferred charges	$	314		$	-	$	314
Other noncurrent liabilities		(150	)		-		(150	)
Net assets	$	164		$	-	$	164

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, 2008 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2009				2010				2011				2012				2013			Thereafter			Total
	(In millions)
Broker quote sheets(1)		$	(39	)		$	(29	)		$	(28	)		$	(23	)		$	-		$	-		$	(119	)
Prices based on models			-				-				-				-				42			241			283
Total(2)		$	(39	)		$	(29	)		$	(28	)		$	(23	)		$	42		$	241		$	164

(1) Validated by observable market transactions.

(2) Includes $164 million in non-hedge commodity derivative contracts (primarily with NUGs) that are 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-Ed’s consolidated financial position or cash flows as of December 31, 2008. Based on derivative contracts held as of December 31, 2008, an adverse 10% change in commodity prices would not have a material effect on Met-Ed’s net income for the next 12 months.

56

Interest Rate Risk

Met-Ed’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 Met-Ed’s investment portfolio and debt obligations.

Comparison of Carrying Value to Fair Value
												There-						Fair
Year of Maturity	2009			2010			2011	2012	2013			after			Total			Value
	(Dollars in millions)
Assets
Investments Other Than Cash and Cash Equivalents:
Fixed Income												$	116		$	116		$	116
Average interest rate													4.4	%		4.4	%
Liabilities
Long-term Debt:
Fixed rate				$	100				$	150		$	263		$	513		$	490
Average interest rate					4.5	%				5.0	%		4.9	%		4.8	%
Variable rate												$	29		$	29		$	29
Average interest rate													1.1	%		1.1	%
Short-term Borrowings:	$	265													$	265		$	265
Average interest rate		0.9	%													0.9	%

Equity Price Risk

Included in Met-Ed’s nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $110 million as of December 31, 2008. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $11 million reduction in fair value as of December 31, 2008 (see Note 5).

Legal Proceedings

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

New Accounting Standards and Interpretations

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

57

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of Metropolitan Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2008 consolidated financial statements.

FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s 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.

FirstEnergy’s 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 Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s 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 Company’s 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 ten meetings in 2008.

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 Company’s 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 Company’s internal control over financial reporting was effective as of December 31, 2008.

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

58

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Metropolitan Edison Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of Metropolitan Edison Company and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 24, 2009

59

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2008			2007			2006
	(In thousands)
REVENUES:
Electric sales	$	1,573,781		$	1,437,498		$	1,175,655
Gross receipts tax collections		79,221			73,012			67,403
Total revenues		1,653,002			1,510,510			1,243,058
EXPENSES:
Purchased power from affiliates (Note 3)		303,779			290,205			177,836
Purchased power from non-affiliates		593,203			494,284			456,597
Other operating costs (Note 3)		429,745			419,512			304,243
Provision for depreciation		44,556			42,798			41,715
Amortization of regulatory assets		131,542			123,410			115,672
Deferral of new regulatory assets		(110,038	)		(124,821	)		(126,571	)
Goodwill impairment (Note 2(E))		-			-			355,100
General taxes		85,643			80,135			77,411
Total expenses		1,478,430			1,325,523			1,402,003
OPERATING INCOME (LOSS)		174,572			184,987			(158,945	)
OTHER INCOME (EXPENSE):
Interest income		17,647			28,953			34,402
Miscellaneous income (expense)		105			(339	)		8,042
Interest expense (Note 3)		(43,651	)		(51,022	)		(47,385	)
Capitalized interest		258			1,154			1,017
Total other expense		(25,641	)		(21,254	)		(3,924	)
INCOME (LOSS) BEFORE INCOME TAXES		148,931			163,733			(162,869	)
INCOME TAXES		60,898			68,270			77,326
NET INCOME (LOSS)	$	88,033		$	95,463		$	(240,195	)
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.

60

METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	144	$	135
Receivables-
Customers (less accumulated provisions of $3,616,000 and $4,327,000,
respectively, for uncollectible accounts)		159,975		142,872
Associated companies		17,034		27,693
Other		19,828		18,909
Notes receivable from associated companies		11,446		12,574
Prepaid taxes		6,121		14,615
Other		1,621		1,348
		216,169		218,146
UTILITY PLANT:
In service		2,065,847		1,972,388
Less - Accumulated provision for depreciation		779,692		751,795
		1,286,155		1,220,593
Construction work in progress		32,305		30,594
		1,318,460		1,251,187
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		226,139		286,831
Other		976		1,360
		227,115		288,191
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		416,499		424,313
Regulatory assets		412,994		522,767
Pension assets (Note 4)		-		51,427
Power purchase contract asset		300,141		141,356
Other		31,031		36,411
		1,160,665		1,176,274
	$	2,922,409	$	2,933,798
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	28,500	$	-
Short-term borrowings-
Associated companies		15,003		185,327
Other		250,000		100,000
Accounts payable-
Associated companies		28,707		29,855
Other		55,330		66,694
Accrued taxes		16,238		16,020
Accrued interest		6,755		6,778
Other		30,647		27,393
		431,180		432,067
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		1,004,064		1,048,632
Long-term debt and other long-term obligations		513,752		542,130
		1,517,816		1,590,762
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		387,757		438,890
Accumulated deferred investment tax credits		7,767		8,390
Nuclear fuel disposal costs		44,328		43,462
Asset retirement obligations		170,999		160,726
Retirement benefits		145,218		8,681
Power purchase contract liability		150,324		169,176
Other		67,020		81,644
		973,413		910,969
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	2,922,409	$	2,933,798
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these balance sheets.

61

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2008			2007
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, 900,000 shares authorized,
859,500 shares outstanding	$	1,196,172		$	1,203,186
Accumulated other comprehensive loss (Note 2(F))		(140,984	)		(15,397	)
Accumulated deficit (Note 10(A))		(51,124	)		(139,157	)
Total		1,004,064			1,048,632
LONG-TERM DEBT (Note 10(C)):
First mortgage bonds-
5.950% due 2027		13,690			13,690
Total		13,690			13,690
Unsecured notes-
4.450% due 2010		100,000			100,000
4.950% due 2013		150,000			150,000
4.875% due 2014		250,000			250,000
*   1.100% due 2021		28,500			28,500
Total		528,500			528,500
Net unamortized premium (discount) on debt		62			(60	)
Long-term debt due within one year		(28,500	)		-
Total long-term debt		513,752			542,130
TOTAL CAPITALIZATION	$	1,517,816		$	1,590,762
* Denotes variable rate issue with applicable year-end interest rate shown.
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.

62

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
									Accumulated			Retained
				Common Stock					Other			Earnings
	Comprehensive			Number		Carrying			Comprehensive			(Accumulated
	Income (Loss)			of Shares		Value			Income (Loss)			Deficit)
	(Dollars in thousands)
Balance, January 1, 2006					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 declared 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	)
Net Income	$	88,033											88,033
Net unrealized gain on derivative instruments		335								335
Pension and other postretirement benefits, net
of $86,030,000 of income tax benefits (Note 4)		(125,922	)							(125,922	)
Comprehensive loss	$	(37,554	)
Restricted stock units							9
Stock-based compensation							1
Consolidated tax benefit allocation							791
Purchase accounting fair value adjustment							(7,815	)
Balance, December 31, 2008					859,500	$	1,196,172		$	(140,984	)	$	(51,124	)
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.

63

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2008			2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	88,033		$	95,463		$	(240,195	)
Adjustments to reconcile net income (loss) to net cash from operating activities-
Provision for depreciation		44,556			42,798			41,715
Amortization of regulatory assets		131,542			123,410			115,672
Deferred costs recoverable as regulatory assets		(25,132	)		(70,778	)		(82,674	)
Deferral of new regulatory assets		(110,038	)		(124,821	)		(126,571	)
Deferred income taxes and investment tax credits, net		49,939			35,502			50,278
Accrued compensation and retirement benefits		(23,244	)		(18,852	)		(6,876	)
Goodwill impairment		-			-			355,100
Loss on sale of investment		-			5,432			-
Cash collateral from (to) suppliers		-			1,600			(1,580	)
Pension trust contributions		-			(11,012	)		-
Decrease (increase) in operating assets-
Receivables		(24,282	)		(38,220	)		37,107
Prepayments and other current assets		8,223			(926	)		(4,385	)
Increase (decrease) in operating liabilities-
Accounts payable		(12,512	)		(62,760	)		94,582
Accrued taxes		470			10,128			(5,647	)
Accrued interest		(23	)		(718	)		(1,804	)
Other		15,629			12,870			(2,633	)
Net cash provided from (used for) operating activities		143,161			(884	)		222,089
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		28,500			-			-
Short-term borrowings, net		-			143,826			1,260
Redemptions and Repayments-
Long-term debt		(28,568	)		(50,000	)		(100,000	)
Short-term borrowings, net		(20,324	)		-			-
Dividend Payments-
Common stock		-			-			(25,000	)
Other		(266	)		(35	)		(7	)
Net cash provided from (used for) financing activities		(20,658	)		93,791			(123,747	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(110,301	)		(103,711	)		(84,817	)
Proceeds from sale of investment		-			4,953			-
Sales of investment securities held in trusts		181,007			184,619			176,460
Purchases of investment securities held in trusts		(193,061	)		(196,140	)		(185,943	)
Loan repayments from (loans to) associated companies, net		1,128			18,535			(3,242	)
Other		(1,267	)		(1,158	)		(790	)
Net cash used for investing activities		(122,494	)		(92,902	)		(98,332	)
Net increase in cash and cash equivalents		9			5			10
Cash and cash equivalents at beginning of year		135			130			120
Cash and cash equivalents at end of year	$	144		$	135		$	130
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	38,627		$	44,501		$	44,597
Income taxes	$	16,872		$	30,741		$	42,173
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.

64

PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier. Penelec has a partial requirements wholesale power sales agreement with FES, to supply a portion of each of its default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty day written notice prior to the end of the calendar year.

Results of Operations

Net income decreased to $88 million in 2008, compared to $93 million in 2007. The decrease was primarily due to increased purchased power costs and net amortization of regulatory assets, partially offset by higher revenues and decreased other operating costs.

Revenues

Revenues increased by $112 million, or 8.0%, in 2008 compared to 2007 primarily due to higher retail and wholesale generation revenues, distribution throughput revenues and transmission revenues. Wholesale revenues increased $91 million in 2008 compared to the same period of 2007, primarily reflecting higher PJM spot market prices.

In 2008, retail generation revenues increased $4 million primarily due to higher composite unit prices in all customer classes and higher KWH sales to residential and commercial customers, partially offset by a decrease in KWH sales to industrial customers due to the weakening economy.

Changes in retail generation sales and revenues in 2008 as compared to 2007 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)
Residential		1.4	%
Commercial		0.9	%
Industrial		(1.9	)%
Net Increase in Retail Generation Sales		0.2	%

Retail Generation Revenues	Increase (Decrease)
	(In millions)
Residential	$	4
Commercial		2
Industrial		(2	)
Net Increase in Retail Generation Revenues	$	4

Revenues from distribution throughput increased $15 million in 2008 compared to 2007. Higher usage in the residential and commercial sectors along with an increase in transmission rates, resulting from the annual update of Penelec’s TSC rider effective June 1, 2008 (see Regulatory Matters) and a slight decrease in usage in the industrial sector.

Changes in distribution KWH deliveries and revenues in 2008 as compared to 2007 are summarized in the following tables:

Distribution KWH Deliveries	Increase (Decrease)
Residential		1.4	%
Commercial		0.9	%
Industrial		(0.3	)%
Net Increase in Distribution Deliveries		0.6	%

65

Distribution Revenues	Increase
	(In millions)
Residential	$	11
Commercial		3
Industrial		1
Increase in Distribution Revenues	$	15

Transmission revenues increased by $5 million in 2008 compared to 2007, primarily due to higher financial transmission rights revenue in PJM. Penelec defers the difference between transmission revenues and net transmission costs incurred in PJM, resulting in no material effect to current period earnings.

Expenses

Total operating expenses increased by $111 million in 2008 compared to 2007. The following table presents changes from the prior year by expense category:

Expenses - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	85
Other operating costs		(7	)
Provision for depreciation		5
Amortization of regulatory assets, net		24
General taxes		4
Net Increase in expenses	$	111

Purchased power costs increased by $85 million, or 10.8%, in 2008 compared to 2007, primarily due to higher composite unit prices paid to non-affiliates in the PJM market. Other operating costs decreased by $7 million in 2008, principally due to lower labor and contractor costs charged to operating expense, reflecting a higher level of capital-related projects in 2008, and reduced billings from FESC for employee benefits. Depreciation expense increased primarily due to an increase in depreciable property since December 31, 2007.

Amortization of regulatory assets (net of deferrals) increased in 2008 compared to 2007 primarily due to the absence of the 2007 deferral of previously expensed decommissioning costs ($12 million) for the Saxton nuclear research facility and decreased transmission cost deferrals ($20 million), partially offset by an increase in universal service charge deferrals ($8 million).

General taxes increased in 2008 primarily due to higher gross receipts taxes resulting from increased sales revenues.

Other Expense

In 2008, other expense increased primarily due to higher interest expense associated with Penelec’s $300 million senior note issuance in August 2007 and reduced life insurance investment values.

Market Risk Information

Penelec uses various market risk sensitive instruments, including derivative contracts, 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.

66

Commodity Price Risk

Penelec is exposed to market risk primarily due to fluctuations in electricity, energy transmission and natural gas prices. To manage the volatility relating to these exposures, Penelec uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. Certain of Penelec’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 or regulatory liability for below-market costs. The change in the fair value of commodity derivative contracts related to energy production during 2008 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 liabilities as of January 1, 2008	$	(16	)	$	-	$	(16	)
Additions/Changes in value of existing contracts		50			-		50
Settled contracts		9			-		9
Net Assets - Derivatives Contracts as of December 31, 2008(1)	$	43		$	-	$	43
Impact of Changes in Commodity Derivative Contracts(2)
Income Statement Effects (Pre-Tax)	$	-		$	-	$	-
Balance Sheet Effects:
Regulatory Liability (net)	$	(59	)	$	-	$	(59	)

(1) Includes $43 million in non-hedge commodity derivative contracts (primarily with NUGs) that are 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, 2008 as follows:

	Non-Hedge			Hedge		Total
	(In millions)
Non-Current-
Other deferred charges	$	127		$	-	$	127
Other noncurrent liabilities		(84	)		-		(84	)
Net assets	$	43		$	-	$	43

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, 2008 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2009				2010				2011				2012				2013			Thereafter			Total
	(In millions)
Broker quote sheets(1)		$	(31	)		$	(22	)		$	(35	)		$	(36	)		$	-		$	-		$	(124	)
Prices based on models			-				-				-				-				28			139			167
Total(2)		$	(31	)		$	(22	)		$	(35	)		$	(36	)		$	28		$	139		$	43

(1) Validated by observable market transactions.

(2) Includes $43 million in non-hedge commodity derivative contracts (primarily with NUGs) that are 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 Penelec’s consolidated financial position or cash flows as of December 31, 2008. Based on derivative contracts held as of December 31, 2008, an adverse 10% change in commodity prices would not have a material effect on Penelec’s net income for the next 12 months.

67

Interest Rate Risk

Penelec’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 Penelec’s investment portfolio and debt obligations.

Comparison of Carrying Value to Fair Value
												There-								Fair
Year of Maturity	2009				2010				2011	2012	2013	after				Total				Value
(Dollars in millions)
Assets
Investments Other Than Cash and Cash Equivalents:
Fixed Income													$	179			$	179			$	179
Average interest rate														3.9	%			3.9	%
Liabilities
Long-term Debt:
Fixed rate		$	100			$	59						$	575			$	734			$	676
Average interest rate			6.1	%			6.8	%						5.9	%			6.0	%
Variable rate													$	45			$	45			$	45
Average interest rate														1.2	%			1.2	%
Short-term Borrowings:		$	281														$	281			$	281
Average interest rate			0.9	%														0.9	%

Equity Price Risk

Included in Penelec’s nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $53 million as of December 31, 2008. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5 million reduction in fair value as of December 31, 2008 (see Note 5).

Legal Proceedings

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

New Accounting Standards and Interpretations

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

68

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements of Pennsylvania Electric Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2008 consolidated financial statements.

FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s 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.

FirstEnergy’s 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 Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s 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 Company’s 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 ten meetings in 2008.

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 Company’s 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 Company’s internal control over financial reporting was effective as of December 31, 2008.

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

69

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Pennsylvania Electric Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of Pennsylvania Electric Company and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 24, 2009

70

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2008			2007			2006
	(In thousands)
REVENUES:
Electric sales	$	1,443,461		$	1,336,517		$	1,086,781
Gross receipts tax collections		70,168			65,508			61,679
Total revenues		1,513,629			1,402,025			1,148,460
EXPENSES (Note 3):
Purchased power from affiliates		284,074			284,826			154,420
Purchased power from non-affiliates		591,487			505,528			471,947
Other operating costs		228,257			234,949			203,868
Provision for depreciation		54,643			49,558			48,003
Amortization of regulatory assets, net		71,091			46,761			21,887
General taxes		79,604			76,050			72,612
Total expenses		1,309,156			1,197,672			972,737
OPERATING INCOME		204,473			204,353			175,723
OTHER INCOME (EXPENSE):
Miscellaneous income		1,359			6,501			8,986
Interest expense (Note 3)		(59,424	)		(54,840	)		(45,278	)
Capitalized interest		(591	)		939			1,290
Total other expense		(58,656	)		(47,400	)		(35,002	)
INCOME BEFORE INCOME TAXES		145,817			156,953			140,721
INCOME TAXES		57,647			64,015			56,539
NET INCOME	$	88,170		$	92,938		$	84,182
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.

71

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	23	$	46
Receivables-
Customers (less accumulated provisions of $3,121,000 and $3,905,000,
respectively, for uncollectible accounts)		146,831		137,455
Associated companies		65,610		22,014
Other		26,766		19,529
Notes receivable from associated companies		14,833		16,313
Prepaid taxes		16,310		1,796
Other		1,517		1,281
		271,890		198,434
UTILITY PLANT:
In service		2,324,879		2,219,002
Less - Accumulated provision for depreciation		868,639		838,621
		1,456,240		1,380,381
Construction work in progress		25,146		24,251
		1,481,386		1,404,632
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		115,292		137,859
Non-utility generation trusts		116,687		112,670
Other		293		531
		232,272		251,060
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		768,628		777,904
Pension assets (Note 4)		-		66,111
Power purchase contract asset		119,748		60,514
Other		18,658		33,893
		907,034		938,422
	$	2,892,582	$	2,792,548
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	145,000	$	-
Short-term borrowings-
Associated companies		31,402		214,893
Other		250,000		-
Accounts payable-
Associated companies		63,692		83,359
Other		48,633		51,777
Accrued taxes		13,264		15,111
Accrued interest		13,131		13,167
Other		31,730		25,311
		596,852		403,618
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		949,109		1,072,057
Long-term debt and other long-term obligations		633,132		777,243
		1,582,241		1,849,300
NONCURRENT LIABILITIES:
Regulatory liabilities		136,579		48,718
Accumulated deferred income taxes		169,807		210,776
Retirement benefits		172,718		41,298
Asset retirement obligations		87,089		81,849
Power purchase contract liability		83,600		85,355
Other		63,696		71,634
		713,489		539,630
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	2,892,582	$	2,792,548
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these balance sheets.

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PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2008			2007
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, $20 par value, 5,400,000 shares authorized,
4,427,577 shares outstanding	$	88,552		$	88,552
Other paid-in capital		912,441			920,616
Accumulated other comprehensive income (loss) (Note 2(F))		(127,997	)		4,946
Retained earnings (Note 10(A))		76,113			57,943
Total		949,109			1,072,057
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			300,000
6.625% due 2019		125,000			125,000
*  1.130% due 2020		20,000			20,000
*  1.210% due 2025		25,000			25,000
Total		755,000			755,000
Net unamortized discount on debt		(1,178	)		(2,067	)
Long-term debt due within one year		(145,000	)		-
Total long-term debt		633,132			777,243
TOTAL CAPITALIZATION	$	1,582,241		$	1,849,300
* 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.

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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, 2006					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 declared 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 $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 declared 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
Net income	$	88,170															88,170
Net unrealized gain on investments, net		9												9
of $13,000 of income taxes
Net unrealized gain on derivative instruments, net		69												69
of $4,000 of income tax benefits
Pension and other postretirement benefits, net
of $90,822,000 of income tax benefits (Note 4)		(133,021	)											(133,021	)
Comprehensive loss	$	(44,773	)
Restricted stock units											35
Stock-based compensation											1
Consolidated tax benefit allocation											1,066
Cash dividends declared on common stock																	(70,000	)
Purchase accounting fair value adjustment											(9,277	)
Balance, December 31, 2008					4,427,577		$	88,552		$	912,441		$	(127,997	)	$	76,113
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.

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PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2008			2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	88,170		$	92,938		$	84,182
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		54,643			49,558			48,003
Amortization of regulatory assets, net		71,091			46,761			21,887
Deferred costs recoverable as regulatory assets		(35,898	)		(71,939	)		(80,942	)
Deferred income taxes and investment tax credits, net		95,227			10,713			28,568
Accrued compensation and retirement benefits		(25,661	)		(20,830	)		5,125
Pension trust contribution		-			(13,436	)		-
Decrease (increase) in operating assets-
Receivables		(74,338	)		18,771			14,299
Prepayments and other current assets		(16,313	)		1,159			683
Increase (decrease) in operating liabilities-
Accounts payable		(1,966	)		(59,513	)		67,602
Accrued taxes		(2,181	)		4,743			(1,524	)
Accrued interest		(36	)		5,943			(638	)
Other		17,815			13,125			8,363
Net cash provided from operating activities		170,553			77,993			195,608
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		45,000			299,109			-
Short-term borrowings, net		66,509			15,662			-
Redemptions and Repayments-
Common Stock		-			(200,000	)		-
Long-term debt		(45,556	)		-			-
Short-term borrowings, net		-			-			(61,928	)
Dividend Payments-
Common stock		(90,000	)		(70,000	)		(20,000	)
Other		-			(2,210	)		-
Net cash provided from (used for) financing activities		(24,047	)		42,561			(81,928	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(126,672	)		(94,991	)		(106,980	)
Loan repayments from (loans to) associated companies, net		1,480			3,235			(1,924	)
Sales of investment securities held in trusts		117,751			175,222			99,469
Purchases of investment securities held in trusts		(134,621	)		(199,375	)		(99,469	)
Other, net		(4,467	)		(4,643	)		(4,767	)
Net cash used for investing activities		(146,529	)		(120,552	)		(113,671	)
Net increase (decrease) in cash and cash equivalents		(23	)		2			9
Cash and cash equivalents at beginning of year		46			44			35
Cash and cash equivalents at end of year	$	23		$	46		$	44
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	56,972		$	44,503		$	41,976
Income taxes	$	44,197		$	2,996		$	29,189
The accompanying Combined Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.

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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 Utilities. This information should be read in conjunction with FES’ and the Utilities’ 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 Utilities)

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

· restructuring the electric generation business and allowing the Utilities' customers to select a competitive electric generation supplier other than the Utilities;

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

· providing the Utilities 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 Utilities' transmission and distribution systems; and

· requiring corporate separation of regulated and unregulated business activities.

The Utilities 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, 2008, regulatory assets that did not earn a current return totaled approximately $61 million for JCP&L and $72 million for Met-Ed. 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,
Regulatory Assets*	2008			2007			Decrease
	(In millions)
OE		$	575		$	737		$	(162	)
CEI			784			871			(87	)
TE			109			204			(95	)
JCP&L			1,228			1,596			(368	)
Met-Ed			413			523			(110	)

* Penelec had net regulatory liabilities of approximately $137 million and $49 million as of December 31, 2008 and December 31, 2007, respectively.

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Ohio (Applicable to OE, CEI, TE and FES)

On January 4, 2006, the PUCO issued an order authorizing 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 twenty-five-year period through distribution rates. 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” and remanded the matter to the PUCO for further consideration. 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. On January 9, 2008, the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs incurred during 2008, which was approximately $185 million. 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 $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the deferred fuel costs was also addressed in the Ohio Companies’ comprehensive ESP filing, which was subsequently withdrawn on December 22, 2008, and also as a part of the stipulation and recommendation which was attached to the amended application for an ESP, both as described below.

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. During the evidentiary hearings and filing of briefs, the PUCO Staff decreased their recommended revenue increase to a range of $117 million to $135 million. On January 21, 2009, the PUCO granted the Ohio Companies’ application to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million).  These increases went into effect for OE and TE on January 23, 2009, and will go into effect for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009.

On May 1, 2008, Governor Strickland signed SB221, which became effective on July 31, 2008. The bill requires all utilities to file an ESP with the PUCO, which must contain a proposal for the supply and pricing of retail generation. A utility may also file an MRO with the PUCO, in which it would have to prove the following objective market criteria: 1) the utility or its transmission service affiliate belongs to a FERC approved RTO, or there is comparable and nondiscriminatory access to the electric transmission grid; 2) the RTO has a market-monitor function and the ability to mitigate market power or the utility’s market conduct, or a similar market monitoring function exists with the ability to identify and monitor market conditions and conduct; and 3) a published source of information is available publicly or through subscription that identifies pricing information for traded electricity products, both on- and off-peak, scheduled for delivery two years into the future.

On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and MRO. The MRO filing outlined a CBP for providing retail generation supply if the ESP is not approved and implemented. The CBP would use a “slice-of-system” approach where suppliers bid on tranches (approximately 100 MW) of the Ohio Companies’ total customer load. If the Ohio Companies proceed with the MRO option, successful bidders (including affiliates) would be required to post independent credit requirements and could be subject to significant collateral calls depending upon power price movement. The PUCO denied the MRO application on November 26, 2008.  The Ohio Companies filed an application for rehearing on December 23, 2008, which the PUCO granted on January 21, 2009, for the purpose of further consideration of the matter.

The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. On December 19, 2008, the PUCO significantly modified and approved the ESP as modified.  On December 22, 2008, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application as allowed by the terms of SB221.  The Ohio Companies further notified the PUCO that, pursuant to SB221, the Ohio Companies would continue their current rate plan in effect and filed tariffs to continue those rates.

On December 31, 2008, the Ohio Companies conducted a CBP, using an RFP format administered by an independent third party, for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. Four qualified wholesale bidders were selected, including FES, for 97% of the tranches offered in the RFP. The average winning bid price was equivalent to a retail rate of 6.98 cents per kilowatt-hour. Subsequent to the RFP, the remaining 3% of the Ohio Companies’ wholesale energy and capacity needs were obtained through a bilateral contract with the lowest bidder in the RFP procurement. The power supply obtained through the foregoing processes provides generation service to the Ohio Companies’ retail customers who choose not to shop with alternative suppliers.

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Following comments by other parties on the Ohio Companies’ December 22, 2008, filing which continued the current rate plan, the PUCO issued an Order on January 7, 2009, that prevented OE and TE from collecting RTC and discontinued the collection of two fuel riders for the Ohio Companies.  The Ohio Companies filed an application for rehearing on January 9, 2009, and also filed an application for a new fuel rider to recover the increased costs for purchasing power during the period January 1, 2009 through March 31, 2009. On January 14, 2009, the PUCO approved the Ohio Companies’ request for the new fuel rider, subject to further review, allowed current recovery of those costs for OE and TE, and allowed CEI to collect a portion of those costs currently and defer the remainder. The PUCO also ordered the Ohio Companies to file additional information in order for it to determine that the costs incurred are prudent and whether the recovery of such costs is necessary to avoid a confiscatory result.  The Ohio Companies filed an application for rehearing on that order on January 26, 2009. The applications for rehearing remain pending and the Ohio Companies are unable to predict the ultimate resolution of these issues.

On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies and further ordered that a conference be held on February 5, 2009 to discuss the Staff’s proposal. The Ohio Companies, PUCO Staff, and other parties participated in that conference, and in a subsequent conference held on February 17, 2009. Following discussions with the Staff and other parties regarding the Staff’s proposal, on February 19, 2009, the Ohio Companies filed an amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties representing a diverse range of interests, which substantially reflected the terms as proposed by the Staff as modified through the negotiations of the parties. Specifically, the stipulated ESP provides that generation will be provided by FES at the average wholesale rate of the RFP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers and that for the period of June 1, 2009 through May 31, 2011, retail generation prices will be based upon the outcome of a descending clock CBP on a slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of any increase resulting from this CBP process by authorizing deferral of related purchased power costs, subject to specified limits. The proposed ESP further provides that the Ohio Companies will not seek a base distribution rate increase with an effective date before January 1, 2012, that CEI will agree to write-off approximately $215 million of its Extended RTC balance, and that the Ohio Companies will collect a delivery service improvement rider at an overall average rate of $.002 per kWh for the period of April 1, 2009 through December 31, 2011. If the Stipulated ESP is approved, one-time after-tax charges associated with implementing the ESP would be approximately $11.3 million for OE, $145.7 million for CEI (including the CEI Extended RTC balance) and $3.5 million for TE. The proposed ESP also addresses a number of other issues, including but not limited to, rate design for various customer classes, resolution of the prudence review described above and the collection of deferred costs that were approved in prior proceedings. On February 19, 2009, the PUCO attorney examiner issued an order setting this matter for hearing to begin on February 25, 2009.

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

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement 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 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. If FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.

On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both companies are expected to conclude by the end of February 2009. The TSCs include a component from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.

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On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. As part of the 2008 state budget negotiations, the Alternative Energy Investment Act was enacted in July 2008 creating a $650 million alternative energy fund to increase the development and use of alternative and renewable energy, improve energy efficiency and reduce energy consumption.

On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. The bill addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters and alternative energy. Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its guidelines for the filing of utilities’ energy efficiency and peak load reduction plans.

Major provisions of the legislation include:

· power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a mix of long-term and short-term contracts and spot market purchases;

· the competitive procurement process must be approved by the PPUC and may include auctions, RFPs, and/or bilateral agreements;

· utilities must provide for the installation of smart meter technology within 15 years;

· a minimum reduction in peak demand of 4.5% by May 31, 2013;

· minimum reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and

· an expanded definition of alternative energy to include additional types of hydroelectric and biomass facilities.

Legislation addressing rate mitigation and the expiration of rate caps was not enacted in 2008 but may be considered in the legislative session which began in January 2009. While the form and impact of such legislation is uncertain, several legislators and the Governor have indicated their intent to address these issues in 2009.

On September 25, 2008, Met-Ed and Penelec filed a Voluntary Prepayment Plan with the PPUC that would provide an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010 that would earn interest at 7.5% and be used to reduce electric rates in 2011 and 2012. Met-Ed, Penelec, OCA and OSBA have reached a settlement agreement on the Voluntary Prepayment Plan and have jointly requested that the PPUC approve the settlement. The ALJ issued a decision on January 29, 2009, recommending approval and adoption of the settlement without modification.

On February 20, 2009, Met-Ed and Penelec filed a generation procurement plan covering the period January 1, 2011 through May 31, 2013, with the PPUC. The companies’ plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. Met-Ed and Penelec have requested PPUC approval of their plan by October 2009.

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, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of December 31, 2008, the accumulated deferred cost balance totaled approximately $220 million.

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In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. 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 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. A public hearing on these proposed rules was held on April 23, 2008 and comments from interested parties were submitted by May 19, 2008.

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

The EMP was issued on October 22, 2008, establishing five major goals:

· maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020;

· reduce peak demand for electricity by 5,700 MW by 2020;

· meet 30% of the state’s electricity needs with renewable energy by 2020;

· examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and

· invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey.

The EMP will be followed by appropriate legislation and regulation as necessary. At this time, JCP&L cannot determine the impact, if any, the EMP may have on its operations.

In support of the New Jersey Governor’s Economic Assistance and Recovery Plan, JCP&L announced its intent to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. An estimated $40 million will be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. Approximately $34 million will be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million will be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million will be spent on energy efficiency programs that will complement those currently being offered. Completion of the projects is dependent upon regulatory approval for full recovery of the costs associated with plan implementation.

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

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. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered 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 is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.

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. On April 19, 2007, the FERC issued an order finding 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. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, AEP appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.

The FERC’s 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 FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce the costs of future transmission to be recovered 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 FERC’s Trial Staff, and was certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.

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Post Transition Period Rate Design

The 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 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 the FERC’s 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.

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 the 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, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit.

Interconnection Agreement with AMP-Ohio

On May 29, 2008, TE filed with the FERC a proposed Notice of Cancellation effective midnight December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio protested this filing. TE also filed a Petition for Declaratory Order seeking a FERC ruling, in the alternative if cancellation is not accepted, of TE's right to file for an increase in rates effective January 1, 2009, for power provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a pleading agreeing that TE may seek an increase in rates, but arguing that any increase is limited to the cost of generation owned by TE affiliates. On August 18, 2008, the FERC issued an order that suspended the cancellation of the Agreement for five months, to become effective on June 1, 2009, and established expedited hearing procedures on issues raised in the filing and TE’s Petition for Declaratory Order. On October 14, 2008, the parties filed a settlement agreement and mutual notice of cancellation of the Interconnection Agreement effective midnight December 31, 2008. On October 24, 2008 the presiding judge certified the settlement agreement as uncontested and on December 22, 2008, the FERC issued an order approving the uncontested settlement agreement. This latest action terminates the litigation and the Interconnection Agreement.

Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join MISO. Duquesne’s proposed move would affect numerous FirstEnergy interests, including but not limited to the terms under which FirstEnergy’s Beaver Valley Plant would continue to participate in PJM’s energy markets.  FirstEnergy, therefore, intervened and participated fully in all of the FERC dockets that were related to Duquesne’s proposed move.

In November, 2008, Duquesne and other parties, including FirstEnergy, negotiated a settlement that would, among other things, allow for Duquesne to remain in PJM and provide for a methodology for Duquesne to meet the PJM capacity obligations for the 2011-2012 auction that excluded the Duquesne load.  The settlement agreement was filed on December 10, 2008 and approved by the FERC in an order issued on January 29, 2009.  The MISO opposed the settlement agreement pending resolution of exit fees alleged to be owed by Duquesne.  The FERC did not resolve this issue in its order.

Complaint against PJM RPM Auction

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act.  On September 19, 2008, the FERC denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’ request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report.  On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program.  PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted.  Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments.  On January 15, 2009, the Chief Judge issued an order terminating settlement talks. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement.

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On October 20, 2008, the RPM Buyers filed a request for rehearing of the FERC’s September 19, 2008 order. The FERC has not yet ruled on the rehearing request.

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 Power, 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 believes the proposal promotes a mechanism that will result in 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. Comments on the filing were filed on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.

On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on these compliance filings is not expected to delay the June 1, 2009, start date for MISO Resource Adequacy.

FES Sales to Affiliates

On October 24, 2008, FES, on its own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies in January 2009 pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. On December 23, 2008, the FERC issued an order granting the waiver request and the Ohio Companies made the required compliance filing on December 30, 2008.

On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and Waverly effective November 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be supplied by FES in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the default or failure of supply of their committed resources. Prices for the power provided by FES were not changed in the Third Restated Partial Requirements Agreement.

Environmental Matters

Various federal, state and local authorities regulate FES and the Utilities with regard to air and water quality and other environmental matters. The effects of compliance on FES and the Utilities with regard to environmental matters could have a material adverse effect on their earnings and competitive position to the extent that they compete 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 and the Utilities 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 Utilities’ determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

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Clean Air Act Compliance (Applicable to FES, OE, JCP&L, Met-Ed and Penelec)

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 $37,500 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 CAA. FES has disputed those alleged violations based on its CAA 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 emission limits 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.

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 and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s 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 was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, 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. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $506 million for 2009-2010 (with $414 million expected to be spent in 2009). This amount excludes the potential AQC expenditures related to Burger Units 4 and 5 described below. On September 8, 2008, the Environmental Enforcement Section of the DOJ sent a letter to OE regarding its view that the company was not in compliance with the Sammis NSR Litigation consent decree because the installation of an SNCR at Eastlake Unit 5 was not completed by December 31, 2006. However, the DOJ acknowledged that stipulated penalties could not apply under the terms of the Sammis NSR Litigation consent decree because Eastlake Unit 5 was idled on December 31, 2006 pending installation of the SNCR and advised that it had exercised its discretion not to seek any other penalties for this alleged non-compliance. OE disputed the DOJ's interpretation of the consent decree in a letter dated September 22, 2008. Although the Eastlake Unit 5 issue is no longer active, OE filed a dispute resolution petition on October 23, 2008, with the United States District Court for the Southern District of Ohio, due to potential impacts on its compliance decisions with respect to Burger Units 4 and 5. On December 23, 2008, OE withdrew its dispute resolution petition and subsequently filed a motion to extend the date (from December 31, 2008 to April 15, 2009), under the Sammis NSR Litigation consent decree, to elect for Burger Units 4 and 5 to permanently shut down those units by December 31, 2010, or to repower them or to install flue gas desulfurization (FGD) by later dates. On January 30, 2009, the Court issued an order extending the election date from December 31, 2008 to March 31, 2009.  

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 revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.  On December 10, 2008, the EPA announced it would not finalize this proposed change to the NSR regulations.

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On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal CAA, 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 18, 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. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.

On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR 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 NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, but the Court has yet to rule on Connecticut’s Motion. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986.  Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.

On June 11, 2008, the EPA issued a Notice and Finding of Violation to MEW alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. MEW is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from MEW is disputed. Penelec is unable to predict the outcome of this matter.

On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an ACO modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. FGCO intends to fully comply with the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter.

On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.

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National Ambient Air Quality Standards  (Applicable to FES)

In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR.  On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. The future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

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 the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the 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 petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the United States moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the United States’ petition and denied the industry group’s petition. Accordingly, the EPA could 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. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule.  It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was 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.

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, including CO2, emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration had 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. Also, in an April 16, 2008 speech, former President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. 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. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity in the United States comes from renewable sources by 2012, and 25% by 2025; and implementing an economy-wide cap-and-trade program to reduce GHG emissions 80% by 2050.

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 Environment and Public Works Committee has 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.

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On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting input from the public on the effects of climate change and the potential ramifications of regulation of CO2 under the CAA.

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 EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review one significant aspect of the Second Circuit Court’s opinion which is whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures.  Oral argument before the Supreme Court occurred on December 2, 2008 and a decision is anticipated during the first half of 2009. FES is studying various control options and their costs and effectiveness. Depending on the results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

The U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007.  FGCO is unable to predict the outcome of this matter.

Regulation of Hazardous Waste  (Applicable to FES and each of the Utilities)

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, 2008, FirstEnergy had approximately $1.7 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.

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The Utilities 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, 2008, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $90 million (JCP&L - $64 million, CEI - - $1 million, TE - $1 million and FirstEnergy Corp. - $24 million) have been accrued through December 31, 2008. Included in the total are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

Other Legal Proceedings

Power Outages and Related Litigation  (Applicable to JCP&L)

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

In August 2002, the trial Court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial Court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge was held on June 13, 2008. At that conference, the plaintiffs stated their intent to drop their efforts to create a class-wide damage model and, instead of dismissing the class action, expressed their desire for a bifurcated trial on liability and damages. The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario. Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure.JCP&L has received the plaintiffs’ proposed plan of action, and intends to file its objection to the proposed plan, and also file a renewed motion to decertify the class. JCP&L is defending this action but is unable to predict the outcome. No liability has been accrued as of December 31, 2008.

On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours, and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. In a letter dated January 30, 2009, the NERC submitted a written “Notice of Request for Information” (NOI) to JCP&L. The NOI asked for additional factual details about the December 9 event, which JCP&L provided in its response. JCP&L is not able to predict what actions, if any, the NERC may take in response to JCP&L's NOI submittal.

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Nuclear Plant Matters  (Applicable to FES)

On May 14, 2007, the Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (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 Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC has conducted the employee training required by the confirmatory order and a consultant has performed follow-up reviews to ensure the effectiveness of that training. The NRC continues to monitor FENOC’s compliance with all the commitments made in the confirmatory order.

In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.

Other Legal Matters  (Applicable to FES and each of the Utilities)

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FES' and the Utilities’ normal business operations pending against them. The other potentially material items not otherwise discussed above are described below.

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs also sought 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 opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. Plaintiffs appealed the Court’s denial of the motion for certification as a class action which the Ohio Court of Appeals (7th District) denied on December 11, 2008. The period to file a notice of appeal to the Ohio Supreme Court has expired.

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. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. The Court has yet to render its decision. JCP&L recognized a liability for the potential $16 million award in 2005.

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

FES and the Utilities accrue legal 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. If it were ultimately determined that FES and the Utilities have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on their financial condition, results of operations and cash flows.

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

SFAS 141(R) – “Business Combinations”

In December 2007, the FASB issued SFAS 141(R), which: (i) requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction; (ii) establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and (iii) 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. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FES and the Utilities that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in deferred tax valuation allowances and income tax uncertainties made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. Under SFAS 141(R), adjustments to the acquired entity’s deferred tax assets and uncertain tax position balances occurring outside the measurement period will be recorded as a component of income tax expense, rather than goodwill.The impact of the application of this Standard in periods after implementation will be dependent upon the nature of acquisitions at that time.

SFAS 160 - “Non-controlling Interests in Consolidated Financial Statements – an Amendment ofARB 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 financial statements of FES or the Utilities.

SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”

In March 2008, the FASB issued SFAS 161 that enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. The FASB believes that additional required disclosure of the fair values of derivative instruments and their gains and losses in a tabular format will provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. This Statement also requires cross-referencing within the footnotes to help users of financial statements locate important information about derivative instruments. The Statement is effective for reporting periods beginning after November 15, 2008. FES expects this Standard to increase its disclosure requirements for derivative instruments and hedging activities.

EITF Issue No. 08-6 – “Equity Method Investment Accounting Considerations”

In November 2008, the FASB issued EITF 08-6, which clarifies how to account for certain transactions involving equity method investments. It provides guidance in determining the initial carrying value of an equity method investment, accounting for a change in an investment from equity method to cost method, assessing the impairment of underlying assets of an equity method investment, and accounting for an equity method investee’s issuance of shares. This statement is effective for transactions occurring in fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is not permitted. The impact of the application of this Standard in periods after implementation will be dependent upon the nature of future investments accounted for under the equity method.

FSP SFAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”

In December 2008, the FASB issued Staff Position (FSP) SFAS 132(R)-1, which provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This FSP is effective for fiscal years ending after December 15, 2009. FES and the Utilities expect this Staff Position to increase their disclosure requirements for postretirement benefit plan assets.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

FES and the Utilities are wholly owned subsidiaries of FirstEnergy. FES’ consolidated financial statements include its wholly owned subsidiaries, FGCO and NGC. OE’s consolidated financial statements include its wholly owned subsidiary, Penn.

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. 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 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 Utilities 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 Utilities 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 Utilities 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 Utilities 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. In the fourth quarter of 2008, Met-Ed and Penelec determined that certain NUG contracts should be reflected at fair value, with offsetting regulatory assets or liabilities. The December 31, 2007, balance sheet has been revised for Met-Ed and Penelec to record derivative assets of $141 million and $61 million, respectively, offset by a regulatory liability. 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 Utilities account for the effects of regulation through the application of SFAS 71 since their rates:

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

· are cost-based; and

· can be charged to and collected from customers.

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

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

· restructuring the electric generation business and allowing the Utilities' customers to select a competitive electric generation supplier other than the Utilities;

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

· providing the Utilities 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;

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· continuing regulation of the Utilities' transmission and distribution systems; and

· requiring corporate separation of regulated and unregulated business activities.

Regulatory Assets

The Utilities recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to expense as incurred. Regulatory assets that do not earn a current return as of December 31, 2008 (primarily for certain regulatory transition costs and employee postretirement benefits) totaled approximately $61 million for JCP&L and $72 million for Met-Ed, which will be recovered by 2014 and 2020, respectively.

Regulatory assets on the Utilities’ Consolidated Balance Sheets are comprised of the following:

Regulatory Assets *	OE			CEI			TE			JCP&L			Met-Ed
December 31, 2008	(In millions)
Regulatory transition costs	$	112		$	80		$	12		$	1,236		$	12
Customer shopping incentives		-			420			-			-			-
Customer receivables for future income taxes		68			4			1			59			113
Loss (Gain) on reacquired debt		20			1			(3	)		24			9
Employee postretirement benefit costs		-			7			3			13			8
Nuclear decommissioning, decontamination
and spent fuel disposal costs		-			-			-			(2	)		(55	)
Asset removal costs		(15	)		(36	)		(16	)		(148	)		-
Property losses and unrecovered plant costs		-			-			-			8			-
MISO/PJM transmission costs		31			19			20			-			319
Fuel costs – RCP		109			75			30			-			-
Distribution costs – RCP		222			198			55			-			-
Other		28			16			7			38			7
Total	$	575		$	784		$	109		$	1,228		$	413
December 31, 2007
Regulatory transition costs	$	197		$	227		$	71		$	1,630		$	279
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		-			-			-			-			(129	)
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		$	523

* Penn had net regulatory liabilities of approximately $11 million and $67 million as of December 31, 2008 and 2007, respectively. Penelec had net regulatory liabilities of approximately $137 million and $49 million as of December 31, 2008 and 2007, respectively.

In accordance with the Ohio Companies’ RCP, recovery of the aggregate of the regulatory transition costs and the Extended RTC (deferred customer shopping incentives and interest costs) amounts were completed by OE and TE as of 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 its recovery period, any of CEI’s remaining unamortized Extended RTC balances will be reduced by applying any remaining cost of removal regulatory liability balances; any further remaining Extended RTC balances will be written off. The RCP allowed 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. 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)).

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Transition Cost Amortization

CEI amortizes transition costs using the effective interest method. Extended RTC amortization, beginning in mid-2009, will be equal to the related revenue recovery that is recognized. CEI’s estimated net amortization of regulatory transition costs and Extended RTC amounts (including associated carrying charges) under the RCP is expected to be $216 million in 2009 and $273 million in 2010.

JCP&L’s and Met-Ed’s regulatory transition costs include the deferral of above-market costs for power supplied from NUGs of $555 million for JCP&L (recovered through BGS and NUGC revenues) and $67 million for Met-Ed (recovered through CTC revenues). Projected above-market NUG costs are adjusted to fair value at the end of each quarter, with a corresponding offset to regulatory assets. 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 Utilities' 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 Utilities 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, 2008 with respect to any particular segment of customers. Billed and unbilled customer receivables for FES and the Utilities as of December 31, 2008 and 2007 are shown below.

Customer Receivables	FES		OE		CEI		TE(1)		JCP&L		Met-Ed		Penelec
December 31, 2008	(In millions)
Billed	$	84	$	143	$	150	$	1	$	179	$	93	$	86
Unbilled		2		134		126		-		161		67		61
Total	$	86	$	277	$	276	$	1	$	340	$	160	$	147
December 31, 2007
Billed	$	107	$	143	$	144	$	-	$	162	$	80	$	75
Unbilled		27		106		107		-		159		63		62
Total	$	134	$	249	$	251	$	-	$	321	$	143	$	137
(1)  See Note 12 for a discussion of TE’s accounts receivable financing arrangement with Centerior Funding Corporation.

(C) EMISSION ALLOWANCES

FES holds emission allowances for SO2 and NOX in order to comply with programs implemented by the EPA designed to regulate emissions of SO2 and NOX produced by power plants. Emission allowances are either granted by the EPA at zero cost or are purchased at fair value as needed to meet emission requirements.  Emission allowances are not purchased with the intent of resale. Emission allowances eligible to be used in the current year are recorded in materials and supplies inventory at the lesser of weighted average cost or market value. Emission allowances eligible for use in future years are recorded as other investments. FES recognizes emission allowance costs as fuel expense during the periods that emissions are produced by its generating facilities. Excess emission allowances that are not needed to meet emission requirements may be sold, with any pre-tax gain or loss included in 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 Utilities 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 Utilities’ electric plant in 2008, 2007 and 2006 are shown in the following table:

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	Annual Composite
	Depreciation Rate
	2008			2007			2006
OE		3.1	%		2.9	%		2.8	%
CEI		3.5			3.6			3.2
TE		3.6			3.9			3.8
Penn		2.4			2.3			2.6
JCP&L		2.3			2.1			2.1
Met-Ed		2.3			2.3			2.3
Penelec		2.5			2.3			2.3
FGCO		4.7			4.0			4.1
NGC		2.8			2.8			2.7

Jointly-Owned Generating Stations

JCP&L holds a 50% ownership interest in Yards Creek Pumped Storage Facility having a net book value of approximately $18.9 million as of December 31, 2008.

Asset Retirement Obligations

FES and the Utilities 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 Utilities 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 Utilities evaluate goodwill for impairment at least annually and more frequently as indicators of impairment arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment is indicated, FES and the Utilities recognize a loss – calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill.

The forecasts used in FES’ and the Utilities’ evaluation of goodwill reflect operations consistent with their 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 Utilities' recovery of transition costs as described in Note 9.

FES’ and the Utilities’ 2008 annual review was completed in the third quarter of 2008 with no impairment indicated. Due to the significant downturn in the U.S. economy during the fourth quarter of 2008, goodwill was tested for impairment as of an interim date (December 31, 2008). No impairment was indicated for Penelec, Met-Ed and JCP&L. As discussed in Note 10(B) on February 19, 2009, the Ohio Companies filed an application for an amended ESP, which substantially reflects terms proposed by the PUCO Staff on February 2, 2009. Goodwill for CEI and TE was tested as of December 31, 2008, reflecting the projected results associated with the amended ESP. No impairment was indicated for CEI or TE. If the PUCO’s final decision authorizes less revenue recovery than the amounts assumed, an additional impairment analysis will be performed at that time that could result in future goodwill impairment. During 2008, JCP&L, Met-Ed and Penelec adjusted goodwill due to the realization of tax benefits that had been reserved under purchase accounting.

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FES’ and the Utilities’ 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 Utilities’ 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. 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.

A summary of the changes in FES’ and the Utilities’ goodwill for the three years ended December 31, 2008 is shown below.

Goodwill	FES		CEI		TE		JCP&L			Met-Ed			Penelec
	(In millions)
Balance as of January 1, 2006	$	24	$	1,689	$	501	$	1,986		$	864		$	882
Impairment charges		-		-		-		-			(355	)		-
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
Adjustments related to GPU acquisition		-		-		-		(15	)		(8	)		(9	)
Balance as of December 31, 2008	$	24	$	1,689	$	501	$	1,811		$	416		$	769

Investments

At the end of each reporting period, FES and the Utilities evaluate their investments for impairment. In accordance with SFAS 115, 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 Utilities 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 Utilities’ 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 in December 2006.  Accumulated other comprehensive income (loss), net of tax, included on FES’ and the Utilities’ Consolidated Balance Sheets as of December 31, 2008 and 2007 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	$	(97	)	$	(190	)	$	(135	)	$	(43	)	$	(215	)	$	(140	)	$	(128	)
Unrealized gain on investments		30			6			-			10			-			-			-
Unrealized loss on derivative hedges		(25	)		-			-			-			(2	)		(1	)		-
AOCI (AOCL) Balance, December 31, 2008	$	(92	)	$	(184	)	$	(135	)	$	(33	)	$	(217	)	$	(141	)	$	(128	)
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 loss on derivative hedges		(16	)		-			-			-			(2	)		(1	)		-
AOCI (AOCL) Balance, December 31, 2007	$	141		$	48		$	(69	)	$	(11	)	$	(20	)	$	(15	)	$	5

95

Other comprehensive income (loss) reclassified to net income in the three years ended December 31, 2008 is as follows:

2008	FES			OE		CEI			TE			JCP&L		Met-Ed		Penelec
	(In millions)
Pension and other postretirement      benefits	$	7		$	16	$	1		$	-		$	14	$	9	$	14
Gain on investments		31			9		-			1			-		-		-
Loss on derivative hedges		(3	)		-		-			-			-		-		-
Reclassification to net income		35			25		1			1			14		9		14
Income taxes related to     reclassification to net income		14			10		-			-			6		4		6
Reclassification to net income, net of      income taxes	$	21			15		1			1			8		5		8
2007
Pension and other postretirement      benefits	$	5		$	14	$	(5	)	$	(2	)	$	8	$	6	$	11
Gain on investments		10			-		-			-			-		-		-
Loss on derivative hedges		(12	)		-		-			-			-		-		-
Reclassification to net income		3			14		(5	)		(2	)		8		6		11
Income taxes (benefits) related to     reclassification to net income		1			6		(2	)		(1	)		4		3		5
Reclassification to net income, net of      income taxes (benefits)	$	2		$	8	$	(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	)	$	-	$	-	$	-

3. TRANSACTIONS WITH AFFILIATED COMPANIES

FES’ and the Utilities’ operating revenues, operating expenses, investment income and interest expense include transactions with affiliated companies.  These affiliated company transactions include PSAs between FES and the Utilities, support service billings from FESC and FENOC, and interest on associated company notes.

Effective October 16, 2007 CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO and FGCO assumed all of CEI’s and TE’s obligations arising under those leases. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCO’s leasehold interests under its July 13, 2007 Bruce Mansfield Unit 1 sale and leaseback transaction, to a newly formed wholly-owned subsidiary on December 17, 2007.  The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE remain primarily liable on the 1987 leases and related agreements. FGCO remains primarily liable on the 2007 leases and related agreements, and FES remains primarily liable as a guarantor under the related 2007 guarantees, as to the lessors and other parties to the respective agreements.

During the second quarter of 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant and approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. In addition, NGC purchased 158.5 MW of lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2. The Ohio Companies continue to lease these MW under their respective sale and leaseback arrangements and the related lease debt remains outstanding.

The Ohio Companies had a PSA with FES through December 31, 2008 to meet their PLR and default service obligations. Met-Ed and Penelec have a partial requirements PSA with FES to meet a portion of their PLR and default service obligations (see Note 9). FES is incurring interest expense through FGCO and NGC on associated company notes payable to the Ohio Companies and Penn related to the 2005 intra-system generation asset transfers. The primary affiliated company transactions for FES and the Utilities for the three years ended December 31, 2008 are as follows:

96

Affiliated Company Transactions - 2008	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Revenues:
Electric sales to affiliates	$	2,968	$	70	$	-	$	30	$	-	$	-	$	-
Ground lease with ATSI		-		12		7		2		-		-		-
Expenses:
Purchased power from affiliates		101		1,203		766		411		-		304		284
Support services		552		145		67		62		90		57		56
Investment Income:
Interest income from affiliates		-		15		1		20		1		-		1
Interest income from FirstEnergy		13		13		-		-		-		-		-
Interest Expense:
Interest expense to affiliates		4		3		19		1		3		2		2
Interest expense to FirstEnergy		26		-		7		2		5		4		5

Affiliated Company Transactions - 2007
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
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

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FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to FES and the Utilities from FESC and FENOC. 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 2007 and 2006, TE sold 150 MW of its Beaver Valley Unit 2 leased capacity entitlement to CEI ($98 million in 2007 and $102 million in 2006). This sale agreement was terminated at the end of 2007.

4. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover certain employees. The 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. In December 2008, The Worker, Retiree, and Employer Recovery Act of 2008 (WRERA) was enacted. Among other provisions, the WRERA provides temporary funding relief to defined benefit plans in light of the current economic crisis. It is expected that the WRERA will have a favorable impact on the level of minimum required contributions for years after 2009. The Company estimates that additional cash contributions will not be required before 2011.

FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. During 2006, FirstEnergy amended the OPEB plan effective in 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized health care coverage. During 2008, FirstEnergy further amended the OPEB plan effective in 2010 to limit the monthly contribution for pre-1990 retirees. 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. 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 for 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, 2008.

98

	FirstEnergy						FirstEnergy
Obligations and Funded Status	Pension Benefits						Other Benefits
As of December 31	2008			2007			2008			2007
	(In millions)
Change in benefit obligation
Benefit obligation as of January 1	$	4,750		$	5,031		$	1,182		$	1,201
Service cost		87			88			19			21
Interest cost		299			294			74			69
Plan participants’ contributions		-			-			25			23
Plan amendments		6			-			(20	)		-
Medicare retiree drug subsidy		-			-			2			-
Actuarial (gain) loss		(152	)		(381	)		12			(30	)
Benefits paid		(289	)		(282	)		(105	)		(102	)
Benefit obligation as of December 31	$	4,701		$	4,750		$	1,189		$	1,182
Change in fair value of plan assets
Fair value of plan assets as of January 1	$	5,285		$	4,818		$	618		$	607
Actual return on plan assets		(1,251	)		438			(152	)		43
Company contribution		8			311			54			47
Plan participants’ contribution		-			-			25			23
Benefits paid		(289	)		(282	)		(105	)		(102	)
Fair value of plan assets as of December 31	$	3,753		$	5,285		$	440		$	618
Qualified plan	$	(774	)	$	700
Non-qualified plans		(174	)		(165	)
Funded status	$	(948	)	$	535		$	(749	)	$	(564	)
Accumulated benefit obligation	$	4,367		$	4,397
Amounts Recognized in the Statement of
Financial Position
Noncurrent assets	$	-		$	700		$	-		$	-
Current liabilities		(8	)		(7	)		-			-
Noncurrent liabilities		(940	)		(158	)		(749	)		(564	)
Net asset (liability) as of December 31	$	(948	)	$	535		$	(749	)	$	(564	)
Amounts Recognized in
Accumulated Other Comprehensive Income
Prior service cost (credit)	$	80		$	83		$	(912	)	$	(1,041	)
Actuarial loss		2,182			623			801			635
Net amount recognized	$	2,262		$	706		$	(111	)	$	(406	)
Assumptions Used to Determine
Benefit Obligations As of December 31
Discount rate		7.00	%		6.50	%		7.00	%		6.50	%
Rate of compensation increase		5.20	%		5.20	%
Allocation of Plan Assets
As of December 31
Asset Category
Equity securities		47	%		61	%		56	%		69	%
Debt securities		38			30			38			27
Real estate		9			7			2			2
Private equities		3			1			1			-
Cash		3			1			3			2
Total		100	%		100	%		100	%		100	%

FES’ and the Utilities’ shares of the net pension and OPEB asset (liability) as of December 31, 2008 and 2007 are as follows:

	Pension Benefits					Other Benefits
Net Pension and OPEB Asset (Liability)	2008			2007		2008			2007
	(In millions)
FES	$	(193	)	$	42	$	(124	)	$	(102	)
OE		(38	)		229		(167	)		(178	)
CEI		(27	)		62		(93	)		(93	)
TE		(12	)		29		(59	)		(63	)
JCP&L		(128	)		93		(58	)		8
Met-Ed		(89	)		51		(52	)		(8	)
Penelec		(64	)		66		(103	)		(40	)

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Estimated Items to be Amortized in 2009 Net Periodic Pension Cost from Accumulated Other Comprehensive Income	FirstEnergy Pension Benefits		FirstEnergy Other Benefits
	(In millions)
Prior service cost (credit)	$	13	$	(151	)
Actuarial loss	$	170	$	63

	FirstEnergy												FirstEnergy
	Pension Benefits												Other Benefits
Components of Net Periodic Benefit Costs	2008				2007				2006				2008				2007				2006
	(In millions)
Service cost		$	87			$	88			$	87			$	19			$	21			$	34
Interest cost			299				294				276				74				69				105
Expected return on plan assets			(463	)			(449	)			(396	)			(51	)			(50	)			(46	)
Amortization of prior service cost			13				13				13				(149	)			(149	)			(76	)
Recognized net actuarial loss			8				45				62				47				45				56
Net periodic cost		$	(56	)		$	(9	)		$	42			$	(60	)		$	(64	)		$	73
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost	FirstEnergy Pension Benefits													FirstEnergy Other Benefits
for Years Ended December 31		2008				2007				2006				2008				2007				2006
Discount rate			6.50	%			6.00	%			5.75	%			6.50	%			6.00	%			5.75	%
Expected long-term return on plan assets			9.00	%			9.00	%			9.00	%			9.00	%			9.00	%			9.00	%
Rate of compensation increase			5.20	%			3.50	%			3.50	%

FES’ and the Utilities’ shares of the net periodic pension and OPEB costs for the three years ended December 31, 2008 are as follows:

	Pension Benefits									Other Benefits
Net Periodic Pension and OPEB Costs	2008			2007			2006			2008			2007			2006
	(In millions)
FES	$	15		$	21		$	40		$	(7	)	$	(10	)	$	14
OE		(26	)		(16	)		(6	)		(7	)		(11	)		17
CEI		(5	)		1			4			2			4			11
TE		(3	)		-			1			4			5			8
JCP&L		(15	)		(9	)		(5	)		(16	)		(16	)		2
Met-Ed		(10	)		(7	)		(7	)		(10	)		(10	)		3
Penelec		(13	)		(10	)		(5	)		(13	)		(13	)		7

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 generally 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 and private equity 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.

Assumed Health Care Cost Trend Rates
As of December 31	2008			2007
Health care cost trend rate assumed for next
year (pre/post-Medicare)		8.5-10	%		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			2015-2017

100

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 to FirstEnergy:

	1-Percentage-		1-Percentage-
	Point Increase		Point Decrease
	(In millions)
Effect on total of service and interest cost	$	4	$	(3	)
Effect on accumulated postretirement benefit obligation	$	36	$	(32	)

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 and participant contributions:

	Pension		Other
Year	Benefits		Benefits
	(In millions)
2009	$	302	$	85
2010		309		89
2011		314		94
2012		325		96
2013		338		99
2014- 2018		1,906		524

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:

	2008						2007
	Carrying			Fair			Carrying			Fair
	Value			Value			Value			Value
	(In millions)
FES		$	2,552		$	2,528		$	1,975		$	1,971
OE			1,232			1,223			1,182			1,197
CEI			1,741			1,618			1,666			1,706
TE			300			244			304			283
JCP&L			1,569			1,520			1,597			1,560
Met-Ed			542			519			542			535
Penelec			779			721			779			779

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 Utilities.

(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 Utilities 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 security’s fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment.

Available-For-Sale Securities

FES and the Utilities 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 Utilities have no securities held for trading purposes.

101

The following table provides the fair value of investments in available-for-sale securities as of December 31, 2008 and 2007. The fair value was determined using the specific identification method.

	2008(1)						2007(2)
	Debt			Equity			Debt			Equity
	Securities			Securities			Securities			Securities
	(In millions)
FES		$	429		$	380		$	417		$	916
OE			95			18			45			82
TE			74			-			67			-
JCP&L			258			66			248			102
Met-Ed			115			110			115			172
Penelec			167			53			167			83

(1)	Excludes cash balances of $225 million at FES, $12 million at Penelec, $4 million at OE and $1 million at Met-Ed.
(2)	Excludes cash balances of $2 million at JCP&L and $1 million at Penelec.

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:

	2008								2007
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
Debt securities	(In millions)
FES	$	401	$	28	$	-	$	429	$	402	$	15	$	-	$	417
OE		86		9		-		95		43		2		-		45
TE		66		8		-		74		63		4		-		67
JCP&L		253		9		4		258		249		3		4		248
Met-Ed		111		4		-		115		112		3		-		115
Penelec		164		3		-		167		166		1		-		167
Equity securities
FES	$	355	$	25	$	-	$	380	$	631	$	285	$	-	$	916
OE		17		1		-		18		59		23		-		82
JCP&L		64		2		-		66		89		13		-		102
Met-Ed		101		9		-		110		136		36		-		172
Penelec		51		2		-		53		80		3		-		83

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, 2008 were as follows:

	FES		OE		TE		JCP&L		Met-Ed		Penelec
	(In millions)
2008
Proceeds from sales	$	951	$	121	$	38	$	248	$	181	$	118
Realized gains		99		11		1		1		2		1
Realized losses		184		9		-		17		17		10
Interest and dividend income		37		5		3		14		9		8
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

102

Unrealized gains applicable to the decommissioning trusts of OE, TE and FES (except for those formerly owned by Penn) 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 2009 to 2017 excluding: restricted funds, whose carrying values are 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 $161 million and $87 million in 2008 and 2007, respectively, excluded by SFAS 107, “Disclosures about Fair Values of Financial Instruments,” as of December 31:

	2008												2007
	Cost			Unrealized			Unrealized			Fair			Cost			Unrealized			Unrealized			Fair
	Basis			Gains			Losses			Value			Basis			Gains			Losses			Value
Debt securities	(In millions)
OE		$	240		$	-		$	13		$	227		$	254		$	28		$	-		$	282
CEI			426			9			-			435			463			68			-			531
JCP&L			1			-			-			1			1			-			-			1
Equity securities
OE		$	2		$	-		$	-		$	2		$	2		$	-		$	-		$	2

The following table provides the approximate fair value and related carrying amounts of notes receivable as of December 31:

	2008						2007
	Carrying			Fair			Carrying			Fair
	Value			Value			Value			Value
Notes receivable	(In millions)
FES		$	75		$	74		$	65		$	63
OE			257			294			259			299
CEI			-			-			1			1
TE			180			189			192			223

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 2009 to 2040.

(C) SFAS 157 ADOPTION

Effective January 1, 2008, FES and the Utilities adopted SFAS 157, which provides a framework for measuring fair value under GAAP and, among other things, requires enhanced disclosures about assets and liabilities recognized at fair value. FES and the Utilities also adopted SFAS 159 on January 1, 2008, which provides the option to measure certain financial assets and financial liabilities at fair value. FES and the Utilities have analyzed their financial assets and financial liabilities within the scope of SFAS 159 and, as of December 31, 2008, have elected not to record eligible assets and liabilities at fair value.

As defined in SFAS 157, fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FES’ and the Utilities’ Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that are held in various trusts.

103

Level 2 – Pricing inputs are either directly or indirectly observable in the market as of the reporting date, other than quoted prices in active markets included in Level 1. FES’ and the Utilities’ Level 2 assets and liabilities consist primarily of investments in debt securities held in various trusts and commodity forwards. Additionally, Level 2 includes those financial instruments that are valued using models or other valuation methodologies based on assumptions that are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Instruments in this category include non-exchange-traded derivatives such as forwards and certain interest rate swaps.

Level 3 – Pricing inputs include inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. FES and the Utilities develop their view of the future market price of key commodities through a combination of market observation and assessment (generally for the short term) and fundamental modeling (generally for the longer term). Key fundamental electricity model inputs are generally directly observable in the market or derived from publicly available historic and forecast data. Some key inputs reflect forecasts published by industry leading consultants who generally employ similar fundamental modeling approaches. Fundamental model inputs and results, as well as the selection of consultants, reflect the consensus of appropriate management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. The Level 3 instruments of JCP&L, Met-Ed and Penelec consist of NUG contracts.

FES and the Utilities utilize market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. FES and the Utilities primarily apply the market approach for recurring fair value measurements using the best information available. Accordingly, FES and the Utilities maximize the use of observable inputs and minimize the use of unobservable inputs.

The following table sets forth FES’ and the Utilities’ financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of December 31, 2008. As required by SFAS 157, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FES’ and the Utilities’ assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Level 1 - Assets								Level 1 - Liabilities
	(In millions)								(In millions)
	Derivatives		Nuclear Decommissioning Trusts(1)		Other Investments		Total		Derivatives		NUG Contracts(2)		Total
FES	$	-	$	290	$	-	$	290	$	25	$	-	$	25
OE		-		18		-		18		-		-		-
JCP&L		-		67		-		67		-		-		-
Met-Ed		-		104		-		104		-		-		-
Penelec		-		58		-		58		-		-		-
	Level 2 - Assets								Level 2 - Liabilities
	(In millions)								(In millions)
	Derivatives		Nuclear Decommissioning Trusts(1)		Other Investments		Total		Derivatives		NUG Contracts(2)		Total
FES	$	12	$	744	$	-	$	756	$	28	$	-	$	28
OE		-		98		-		98		-		-		-
TE		-		73		-		73		-		-		-
JCP&L		7		74		181		262		-		-		-
Met-Ed		14		121		-		135		-		-		-
Penelec		7		57		117		181		-		-		-
	Level 3 - Assets								Level 3 - Liabilities
	(In millions)								(In millions)
	Derivatives		Nuclear Decommissioning Trusts(1)		NUG Contracts(2)		Total		Derivatives		NUG Contracts(2)		Total
JCP&L	$	-	$	-	$	14	$	14	$	-	$	532	$	532
Met-Ed		-		-		300		300		-		150		150
Penelec		-		-		120		120		-		84		84

(1) Balance excludes $4 million of net receivables, payables and accrued income.

(2) NUG contract assets and liabilities are subject to regulatory accounting.

104

The determination of the above fair value measures takes into consideration various factors required under SFAS 157. These factors include nonperformance risk, including counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of nonperformance risk was immaterial in the fair value measurements.

Exchange-traded derivative contracts, which include some futures and options, are generally based on unadjusted quoted market prices in active markets and are classified within Level 1. Forwards, options and swap contracts that are not exchange-traded are classified as Level 2 as the fair values of these items are based on Intercontinental Exchange quotes or market transactions in the OTC markets. In addition, complex or longer-term structured transactions can introduce the need for internally-developed model inputs that may not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is classified as Level 3.

Nuclear decommissioning trusts consist of equity securities listed on active exchanges classified as Level 1 and various debt securities and collective trusts classified as Level 2. Other investments represent the NUG trusts, spent nuclear fuel trusts and rabbi trust investments, which primarily consist of various debt securities and collective trusts classified as Level 2.

The following tables provide a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy during 2008 (in millions):

	JCP&L			Met-Ed			Penelec
Balance as of January 1, 2008	$	(750	)	$	(28	)	$	(25	)
Settlements(1)		232			34			12
Unrealized gains (losses)(1)		-			144			49
Net transfers to (from) Level 3		-			-			-
Balance as of December 31, 2008	$	(518	)	$	150		$	36
Change in unrealized gains (losses) relating to
instruments held as of December 31, 2008	$	-		$	144		$	49
(1)   Changes in the fair value of NUG contracts are completely offset by regulatory assets and do not impact earnings

Under FSP FAS 157-2, “Effective Date of FASB Statement No. 157”, FES and the Utilities deferred until January 1, 2009, the election of SFAS 157 for financial assets and financial liabilities measured at fair value on a non-recurring basis and are currently evaluating the impact of SFAS 157 on those financial assets and financial liabilities.

(D) DERIVATIVES

FES and the Utilities 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 Utilities. 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 Utilities account for derivative instruments on their Consolidated Balance Sheets at 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 hedges was immaterial during 2008.

105

FES’ net deferred losses of $25 million included in AOCL as of December 31, 2008, for derivative hedging activity, as compared to $16 million as of December 31, 2007, resulted from a net $11 million increase related to current hedging activity and a $2 million decrease due to net hedge losses reclassified to earnings during 2008. Based on current estimates, approximately $20 million (after tax) of the net deferred losses on derivative instruments in AOCL as of December 31, 2008 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.

6. LEASES

FES and the Utilities lease certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases.

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 are 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.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion (net after-tax proceeds of approximately $1.2 billion) for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034.  A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates.  The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. This transaction is classified as an operating lease under GAAP for FES and FirstEnergy.

Effective October 16, 2007 CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO and FGCO assumed all of CEI’s and TE’s obligations arising under those leases. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCO’s leasehold interests under its July 13, 2007 Bruce Mansfield Unit 1 sale and leaseback transaction, to a newly formed wholly-owned subsidiary on December 17, 2007.  The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE remain primarily liable on the 1987 leases and related agreements. FGCO remains primarily liable on the 2007 leases and related agreements, and FES remains primarily liable as a guarantor under the related 2007 guarantees, as to the lessors and other parties to the respective agreements. These assignments terminate automatically upon the termination of the underlying leases.

During the second quarter of 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant and approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. In addition, NGC purchased 158.5 MW of lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2. The Ohio Companies continue to lease these MW under their respective sale and leaseback arrangements and the related lease debt remains outstanding.

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, 2008 are summarized as follows:

106

	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
2008
Operating leases
Interest element	$	110	$	77	$	1	$	23	$	3	$	2	$	1
Other		63		69		4		42		5		2		3
Capital leases
Interest element		1		-		-		-		-		-		-
Other(1)		8		-		1		-		-		-		-
Total rentals	$	182	$	146	$	6	$	65	$	8	$	4	$	4
2007
Operating leases
Interest element	$	30	$	83	$	24	$	38	$	3	$	2	$	1
Other		15		62		38		63		5		2		4
Capital leases
Interest element		-		-		-		-		-		-		-
Other		-		-		1		-		-		-		-
Total rentals	$	45	$	145	$	63	$	101	$	8	$	4	$	5
2006
Operating leases
Interest element	$	-	$	87	$	26	$	41	$	3	$	2	$	1
Other		-		58		48		68		4		1		3
Capital leases
Interest element		-		-		-		-		-		-		-
Other		-		1		1		-		-		-		-
Total rentals	$	-	$	146	$	75	$	109	$	7	$	3	$	4
(1)   Includes $5 million in 2008 of wind purchased power agreements classified as capital leases in accordance with EITF 01-8.

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 PNBV and Shippingport arrangements effectively reduce lease costs related to those transactions (see Note 7).

The future minimum capital lease payments as of December 31, 2008 are as follows:

Capital Leases	FES		OE		CEI
	(In millions)
2009	$	6	$	1	$	1
2010		6		-		1
2011		6		1		1
2012		5		-		1
2013		5		1		1
Years thereafter		24		5		5
Total minimum lease payments		52		8		10
Executory costs		-		-		-
Net minimum lease payments		52		8		10
Interest portion		8		3		7
Present value of net minimum
lease payments		44		5		3
Less current portion		5		1		1
Noncurrent portion	$	39	$	4	$	2

107

The future minimum operating lease payments as of December 31, 2008 are as follows:

Operating Leases	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
2009	$	176	$	145	$	4	$	64	$	8	$	4	$	5
2010		177		141		-		62		4		2		1
2011		172		141		-		62		4		2		1
2012		215		141		-		62		4		2		1
2013		224		142		-		62		3		2		-
Years thereafter		2,320		441		-		203		50		34		1
Total minimum lease payments	$	3,284	$	1,151	$	4	$	515	$	73	$	46	$	9

FirstEnergy has been notified by the lessor of certain vehicle and equipment leases of its election to terminate the lease arrangements effective November 2009. FirstEnergy is currently pursuing replacement lease arrangements with alternative lessors. In the event that replacement lease arrangements are not secured, FES and the Utilities would be required to purchase the vehicles and equipment under lease at their aggregate unamortized value of approximately $100 million upon termination of the leases.

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 unamortized above-market lease liability for Beaver Valley Unit 2 of $310 million as of December 31, 2008, of which $37 million is classified as current, is being amortized by TE on straight-line basis through the end of the lease term in 2017. Effective October 16, 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. The unamortized above-market lease liability for the Bruce Mansfield Plant of $353 million as of December 31, 2008, of which $46 million is classified as current, is being 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 Utilities 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.

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 company’s net exposure to loss based upon the casualty value provisions mentioned above:

	Maximum Exposure		Discounted Lease Payments, net		Net Exposure
	(in millions)
FES	$	1,349	$	1,182	$	167
OE		778		574		204
CEI		713		81		632
TE		713		419		294

See Note 6 for a discussion of CEI’s and TE’s assignment of their leasehold interests in the Bruce Mansfield Plant to FGCO.

108

Power Purchase Agreements

In accordance with FIN 46R, FES and the Utilities 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 Utilities and the contract price for power is correlated with the plant’s 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, its maximum exposure to loss relates primarily to the above-market costs it incurs 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, 2008 are shown in the following table:

	2008			2007			2006
	(In millions)
JCP&L		$	84		$	90		$	81
Met-Ed			61			56			60
Penelec			33			30			29

8. TAXES

Income Taxes

FES and the Utilities 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, 2008 are shown below:

109

PROVISION FOR INCOME TAXES	FES			OE			CEI			TE			JCP&L			Met-Ed			Penelec
	(In millions)
2008
Currently payable-
Federal	$	156		$	79		$	119		$	46		$	101		$	5		$	(34	)
State		20			4			6			-			34			6			(3	)
		176			83			125			46			135			11			(37	)
Deferred, net-
Federal		109			22			16			(12	)		9			47			84
State		12			(2	)		(2	)		(4	)		4			4			12
		121			20			14			(16	)		13			51			96
Investment tax credit amortization		(4	)		(4	)		(2	)		-			-			(1	)		(1	)
Total provision for income taxes	$	293		$	99		$	137		$	30		$	148		$	61		$	58
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

FES and the Utilities are 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.

110

The following tables provide a reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes for the three years ended December 31, 2008.

	FES			OE			CEI			TE			JCP&L			Met-Ed			Penelec
	(In millions)
2008
Book income before provision for income taxes	$	800		$	310		$	421		$	105		$	335		$	149		$	146
Federal income tax expense at statutory rate	$	280		$	109		$	147		$	37		$	117		$	52		$	51
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits		(4	)		(4	)		(2	)		-			-			(1	)		(1	)
State income taxes, net of federal tax benefit		21			1			2			(2	)		25			7			5
Manufacturing deduction		(15	)		(3	)		(8	)		(2	)		-			-			-
Other, net		11			(4	)		(2	)		(3	)		6			3			3
Total provision for income taxes	$	293		$	99		$	137		$	30		$	148		$	61		$	58
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

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Accumulated deferred income taxes as of December 31, 2008 and 2007 are as follows:

	FES			OE			CEI			TE			JCP&L			Met-Ed			Penelec
	(In millions)
AS OF DECEMBER 31, 2008
Property basis differences	$	434		$	494		$	428		$	172		$	436		$	275		$	329
Regulatory transition charge		-			40			29			4			190			29			-
Customer receivables for future income taxes		-			22			1			-			24			49			48
Deferred customer shopping incentive		-			-			151			-			-			-			-
Deferred MISO/PJM transmission costs		-			11			7			7			-			137			4
Other regulatory assets - RCP		-			121			100			32			-			-			-
Deferred sale and leaseback gain		(438	)		(45	)		-			-			(10	)		(12	)		-
Nonutility generation costs		-			-			-			-			-			30			(82	)
Unamortized investment tax credits		(23	)		(5	)		(5	)		(2	)		(2	)		(6	)		(5	)
Unrealized losses on derivative hedges		(15	)		-			-			-			(1	)		(1	)		-
Pension and other postretirement obligations		(68	)		(94	)		(47	)		(25	)		(90	)		(72	)		(89	)
Lease market valuation liability		(124	)		-			-			(122	)		-			-			-
Oyster Creek securitization (Note 10(C))		-			-			-			-			137			-			-
Nuclear decommissioning activities		14			2			-			13			(34	)		(65	)		(55	)
Deferred gain for asset sales - affiliated companies		-			41			27			9			-			-			-
Allowance for equity funds used during construction		-			20			1			-			-			-			-
All other		(48	)		46			12			(9	)		39			24			20
Net deferred income tax liability (asset)	$	(268	)	$	653		$	704		$	79		$	689		$	388		$	170
AS OF DECEMBER 31, 2007
Property basis differences	$	275		$	484		$	404		$	173		$	439		$	266		$	319
Regulatory transition charge		-			70			77			26			235			60			-
Customer receivables for future income taxes		-			22			1			-			14			49			62
Deferred customer shopping incentive		-			34			142			13			-			-			-
Deferred MISO/PJM transmission costs		-			20			12			9			-			97			13
Other regulatory assets - RCP		-			92			71			30			-			-			-
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	)
Unrealized losses on derivative hedges		(10	)		-			-			-			(1	)		(1	)		-
Pension and other postretirement obligations		(21	)		8			(15	)		(17	)		20			1			(18	)
Lease market valuation liability		(148	)		-			-			(135	)		-			-			-
Oyster Creek securitization (Note 10(C))		-			-			-			-			149			-			-
Nuclear decommissioning activities		142			7			-			11			(48	)		(57	)		(65	)
Deferred gain for asset sales - affiliated companies		-			45			30			10			-			-			-
Allowance for equity funds used during construction		-			21			-			-			-			-			-
All other		(37	)		33			11			(13	)		14			19			17
Net deferred income tax liability (asset)	$	(277	)	$	781		$	726		$	103		$	800		$	439		$	211

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

As of January 1, 2007, the total amount of unrecognized tax benefits for FES and the Utilities was $59 million (see table below for amounts included for FES and the Utilities) and recorded a cumulative effect adjustment (OE - $0.6 million, CEI - $0.2 million and FES - $0.5 million) to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions.

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A reconciliation of the change in the unrecognized tax benefits for the years 2008 and 2007 are as follows:

	FES			OE			CEI			TE			JCP&L			Met-Ed			Penelec
	(In millions)
Balance as of January 1, 2008	$	14		$	(12	)	$	(17	)	$	(1	)	$	38		$	24		$	16
Increase for tax positions related to the    current year		-			1			-			-			-			-			-
Increase for tax positions related to    prior years		1			1			-			-			6			5			9
Decrease  for tax positions of    prior years		(10	)		(14	)		(8	)		(3	)		(2	)		(1	)		(1	)
Decrease for settlement		-			(6	)		(1	)		-			-			-			-
Balance as of December 31, 2008	$	5		$	(30	)	$	(26	)	$	(4	)	$	42		$	28		$	24

	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, 2008, FES and the Utilities expect that $44 million of the unrecognized benefits will be resolved within the next twelve months and are included in the captions “Prepayments and other” and  “Accrued taxes,” with the remaining amount included in “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-
Prepayments and other	$	-	$	(52	)	$	(33	)	$	(9	)	$	-	$	-	$	-
Accrued taxes		-		-			-			-			26		13		11
Non-Current-
Other non-current liabilities		5		22			7			5			16		15		13
Net liabilities (assets)	$	5	$	(30	)	$	(26	)	$	(4	)	$	42	$	28	$	24

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 Utilities 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 Utilities for the three years ended December 31, 2008 and the cumulative net interest payable (receivable) as of December 31, 2008 and 2007:

	Net Interest Expense (Income)												Net Interest Payable
	For the Years Ended												(Receivable)
	December 31,												As of December 31,
	2008				2007				2006				2008				2007
	(In millions)												(In millions)
FES		$	-			$	-			$	1			$	1			$	2
OE			(4	)			1				1				(9	)			(5	)
CEI			(2	)			(1	)			1				(7	)			(3	)
TE			-				-				1				(1	)			-
JCP&L			1				1				(2	)			11				10
Met-Ed			1				2				-				6				5
Penelec			2				-				(1	)			6				4

FES and the Utilities 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 2001-2008. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audit for years 2004-2006 were completed in the third quarter of 2008 and several items are under appeals. The IRS began auditing the year 2007 in February 2007 and the year 2008 in February 2008 under its Compliance Assurance Process program. Both audits are expected to close before December 2009. 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 Utilities’ financial condition or results of operations.

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On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity (see Note 6). This transaction generated tax capital gains of approximately $815 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)).

FES and Penelec have pre-tax net operating loss carryforwards for state and local income tax purposes. These losses expire as follows:

Expiration Period	FES		Penelec
	(In millions)
2009-2013	$	2	$	-
2014-2018		1		-
2019-2023		27		216
2024-2028		38		17
	$	68	$	233

General Taxes

Details of general taxes for the three years ended December 31, 2008 are shown below:

	FES		OE			CEI		TE		JCP&L		Met-Ed			Penelec
	(In millions)
2008
Kilowatt-hour excise	$	1	$	97		$	70	$	30	$	51	$	-		$	-
State gross receipts		16		17			-		-		-		79			70
Real and personal property		53		61			67		19		5		3			2
Social security and unemployment		14		9			6		3		10		5			6
Other		4		2			-		-		1		(1	)		2
Total general taxes	$	88	$	186		$	143	$	52	$	67	$	86		$	80
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

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 replaced 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 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.

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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 (the PUCO, the FERC, the 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. 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.

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 Utilities 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 ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst 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 the NERC, ReliabilityFirst 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 result in the imposition of financial penalties and thus 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, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and a final report is expected in early 2009. FES and the Utilities currently do not expect any material adverse financial impact as a result of these audits.

(B) OHIO

On January 4, 2006, the PUCO issued an order authorizing 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 twenty-five-year period through distribution rates. 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” and remanded the matter to the PUCO for further consideration. 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. On January 9, 2008, the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs incurred during 2008, which was approximately $185 million. 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 $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the deferred fuel costs was also addressed in the Ohio Companies’ comprehensive ESP filing, which was subsequently withdrawn on December 22, 2008, and also as a part of the stipulation and recommendation which was attached to the amended application for an ESP, both as described below.

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On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. During the evidentiary hearings and filing of briefs, the PUCO Staff decreased their recommended revenue increase to a range of $117 million to $135 million. On January 21, 2009, the PUCO granted the Ohio Companies’ application to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million).  These increases went into effect for OE and TE on January 23, 2009, and will go into effect for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009.

On May 1, 2008, Governor Strickland signed SB221, which became effective on July 31, 2008. The bill requires all utilities to file an ESP with the PUCO, which must contain a proposal for the supply and pricing of retail generation. A utility may also file an MRO with the PUCO, in which it would have to prove the following objective market criteria: 1) the utility or its transmission service affiliate belongs to a FERC approved RTO, or there is comparable and nondiscriminatory access to the electric transmission grid; 2) the RTO has a market-monitor function and the ability to mitigate market power or the utility’s market conduct, or a similar market monitoring function exists with the ability to identify and monitor market conditions and conduct; and 3) a published source of information is available publicly or through subscription that identifies pricing information for traded electricity products, both on- and off-peak, scheduled for delivery two years into the future.

On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and MRO. The MRO filing outlined a CBP for providing retail generation supply if the ESP is not approved and implemented. The CBP would use a “slice-of-system” approach where suppliers bid on tranches (approximately 100 MW) of the Ohio Companies’ total customer load. If the Ohio Companies proceed with the MRO option, successful bidders (including affiliates) would be required to post independent credit requirements and could be subject to significant collateral calls depending upon power price movement. The PUCO denied the MRO application on November 26, 2008.  The Ohio Companies filed an application for rehearing on December 23, 2008, which the PUCO granted on January 21, 2009, for the purpose of further consideration of the matter.

The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. On December 19, 2008, the PUCO significantly modified and approved the ESP as modified.  On December 22, 2008, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application as allowed by the terms of SB221.  The Ohio Companies further notified the PUCO that, pursuant to SB221, the Ohio Companies would continue their current rate plan in effect and filed tariffs to continue those rates.

On December 31, 2008, the Ohio Companies conducted a CBP, using an RFP format administered by an independent third party, for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. Four qualified wholesale bidders were selected, including FES, for 97% of the tranches offered in the RFP. The average winning bid price was equivalent to a retail rate of 6.98 cents per kilowatt-hour. Subsequent to the RFP, the remaining 3% of the Ohio Companies’ wholesale energy and capacity needs were obtained through a bilateral contract with the lowest bidder in the RFP procurement. The power supply obtained through the foregoing processes provides generation service to the Ohio Companies’ retail customers who choose not to shop with alternative suppliers.

Following comments by other parties on the Ohio Companies’ December 22, 2008, filing which continued the current rate plan, the PUCO issued an Order on January 7, 2009, that prevented OE and TE from collecting RTC and discontinued the collection of two fuel riders for the Ohio Companies.  The Ohio Companies filed an application for rehearing on January 9, 2009, and also filed an application for a new fuel rider to recover the increased costs for purchasing power during the period January 1, 2009 through March 31, 2009. On January 14, 2009, the PUCO approved the Ohio Companies’ request for the new fuel rider, subject to further review, allowed current recovery of those costs for OE and TE, and allowed CEI to collect a portion of those costs currently and defer the remainder. The PUCO also ordered the Ohio Companies to file additional information in order for it to determine that the costs incurred are prudent and whether the recovery of such costs is necessary to avoid a confiscatory result.  The Ohio Companies filed an application for rehearing on that order on January 26, 2009. The applications for rehearing remain pending and the Ohio Companies are unable to predict the ultimate resolution of these issues.

116

On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies and further ordered that a conference be held on February 5, 2009 to discuss the Staff’s proposal. The Ohio Companies, PUCO Staff, and other parties participated in that conference, and in a subsequent conference held on February 17, 2009. Following discussions with the Staff and other parties regarding the Staff’s proposal, on February 19, 2009, the Ohio Companies filed an amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties representing a diverse range of interests, which substantially reflected the terms as proposed by the Staff as modified through the negotiations of the parties. Specifically, the stipulated ESP provides that generation will be provided by FES at the average wholesale rate of the RFP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers and that for the period of June 1, 2009 through May 31, 2011, retail generation prices will be based upon the outcome of a descending clock CBP on a slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of any increase resulting from this CBP process by authorizing deferral of related purchased power costs, subject to specified limits. The proposed ESP further provides that the Ohio Companies will not seek a base distribution rate increase with an effective date before January 1, 2012, that CEI will agree to write-off approximately $215 million of its Extended RTC balance, and that the Ohio Companies will collect a delivery service improvement rider at an overall average rate of $.002 per kWh for the period of April 1, 2009 through December 31, 2011. If the Stipulated ESP is approved, one-time after-tax charges associated with implementing the ESP would be approximately $11.3 million for OE, $145.7 million for CEI (including the CEI Extended RTC balance) and $3.5 million for TE. The proposed ESP also addresses a number of other issues, including but not limited to, rate design for various customer classes, resolution of the prudence review described above and the collection of deferred costs that were approved in prior proceedings. On February 19, 2009, the PUCO attorney examiner issued an order setting this matter for hearing to begin on February 25, 2009.

(C) PENNSYLVANIA

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement 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 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. If FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.

On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both companies are expected to conclude by the end of February 2009. The TSCs include a component from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. As part of the 2008 state budget negotiations, the Alternative Energy Investment Act was enacted in July 2008 creating a $650 million alternative energy fund to increase the development and use of alternative and renewable energy, improve energy efficiency and reduce energy consumption.

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On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. The bill addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters and alternative energy. Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its guidelines for the filing of utilities’ energy efficiency and peak load reduction plans.

Major provisions of the legislation include:

· power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a mix of long-term and short-term contracts and spot market purchases;

· the competitive procurement process must be approved by the PPUC and may include auctions, RFPs, and/or bilateral agreements;

· utilities must provide for the installation of smart meter technology within 15 years;

· a minimum reduction in peak demand of 4.5% by May 31, 2013;

· minimum reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and

· an expanded definition of alternative energy to include additional types of hydroelectric and biomass facilities.

Legislation addressing rate mitigation and the expiration of rate caps was not enacted in 2008 but may be considered in the legislative session which began in January 2009. While the form and impact of such legislation is uncertain, several legislators and the Governor have indicated their intent to address these issues in 2009.

On September 25, 2008, Met-Ed and Penelec filed a Voluntary Prepayment Plan with the PPUC that would provide an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010 that would earn interest at 7.5% and be used to reduce electric rates in 2011 and 2012. Met-Ed, Penelec, OCA and OSBA have reached a settlement agreement on the Voluntary Prepayment Plan and have jointly requested that the PPUC approve the settlement. The ALJ issued a decision on January 29, 2009, recommending approval and adoption of the settlement without modification.

On February 20, 2009, Met-Ed and Penelec filed a generation procurement plan covering the period January 1, 2011 through May 31, 2013, with the PPUC. The companies’ plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. Met-Ed and Penelec have requested PPUC approval of their plan by October 2009.

(D) NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of December 31, 2008, the accumulated deferred cost balance totaled approximately $220 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. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set.

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On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of 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 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. A public hearing on these proposed rules was held on April 23, 2008 and comments from interested parties were submitted by May 19, 2008.

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

The EMP was issued on October 22, 2008, establishing five major goals:

· maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020;

· reduce peak demand for electricity by 5,700 MW by 2020;

· meet 30% of the state’s electricity needs with renewable energy by 2020;

· examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and

· invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey.

The EMP will be followed by appropriate legislation and regulation as necessary. At this time, JCP&L cannot determine the impact, if any, the EMP may have on its operations.

In support of the New Jersey Governor’s Economic Assistance and Recovery Plan, JCP&L announced its intent to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. An estimated $40 million will be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. Approximately $34 million will be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million will be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million will be spent on energy efficiency programs that will complement those currently being offered. Completion of the projects is dependent upon regulatory approval for full recovery of the costs associated with plan implementation.

(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. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered 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 is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.

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PJM Transmission Rate Design

On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding 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. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, AEP appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.

The FERC’s 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 FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce the costs of future transmission to be recovered 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 FERC’s Trial Staff, and was certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.

Post Transition Period Rate Design

The 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 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 the FERC’s 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.

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 the 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, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit.

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Interconnection Agreement with AMP-Ohio

On May 29, 2008, TE filed with the FERC a proposed Notice of Cancellation effective midnight December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio protested this filing. TE also filed a Petition for Declaratory Order seeking a FERC ruling, in the alternative if cancellation is not accepted, of TE's right to file for an increase in rates effective January 1, 2009, for power provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a pleading agreeing that TE may seek an increase in rates, but arguing that any increase is limited to the cost of generation owned by TE affiliates. On August 18, 2008, the FERC issued an order that suspended the cancellation of the Agreement for five months, to become effective on June 1, 2009, and established expedited hearing procedures on issues raised in the filing and TE’s Petition for Declaratory Order. On October 14, 2008, the parties filed a settlement agreement and mutual notice of cancellation of the Interconnection Agreement effective midnight December 31, 2008. On October 24, 2008 the presiding judge certified the settlement agreement as uncontested and on December 22, 2008, the FERC issued an order approving the uncontested settlement agreement. This latest action terminates the litigation and the Interconnection Agreement.

Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join MISO. Duquesne’s proposed move would affect numerous FirstEnergy interests, including but not limited to the terms under which FirstEnergy’s Beaver Valley Plant would continue to participate in PJM’s energy markets.  FirstEnergy, therefore, intervened and participated fully in all of the FERC dockets that were related to Duquesne’s proposed move.

In November, 2008, Duquesne and other parties, including FirstEnergy, negotiated a settlement that would, among other things, allow for Duquesne to remain in PJM and provide for a methodology for Duquesne to meet the PJM capacity obligations for the 2011-2012 auction that excluded the Duquesne load.  The settlement agreement was filed on December 10, 2008 and approved by the FERC in an order issued on January 29, 2009.  The MISO opposed the settlement agreement pending resolution of exit fees alleged to be owed by Duquesne.  The FERC did not resolve this issue in its order.

Complaint against PJM RPM Auction

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act.  On September 19, 2008, the FERC denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’ request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report.  On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program.  PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted.  Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments.  On January 15, 2009, the Chief Judge issued an order terminating settlement talks. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement.

On October 20, 2008, the RPM Buyers filed a request for rehearing of the FERC’s September 19, 2008 order. The FERC has not yet ruled on the rehearing request.

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 Power, 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 believes the proposal promotes a mechanism that will result in 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. Comments on the filing were filed on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.

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On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on these compliance filings is not expected to delay the June 1, 2009, start date for MISO Resource Adequacy.

FES Sales to Affiliates

On October 24, 2008, FES, on its own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies in January 2009 pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. On December 23, 2008, the FERC issued an order granting the waiver request and the Ohio Companies made the required compliance filing on December 30, 2008.

On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and Waverly effective November 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be supplied by FES in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the default or failure of supply of their committed resources. Prices for the power provided by FES were not changed in the Third Restated Partial Requirements Agreement.

10. CAPITALIZATION

(A) RETAINED EARNINGS (ACCUMULATED DEFICIT)

There are no restrictions on retained earnings for payment of cash dividends on OE’s, CEI’s, TE’s, 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, 2008, Penelec had retained earnings available to pay common stock dividends of $66 million, net of amounts restricted under its first mortgage indenture. Met-Ed had an accumulated deficit of $51 million as of December 31, 2008, and is therefore currently precluded from making cash dividend distributions to FirstEnergy.

(B) PREFERRED AND PREFERENCE STOCK

The Utilities’ 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

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No preferred shares or preference shares are currently outstanding. The following table details the change in preferred shares outstanding for OE, TE and JCP&L during 2006. No shares were issued in 2007 or 2008.

	Not Subject to
	Mandatory Redemption
				Par or
	Number			Stated
	of Shares			Value
	(Dollars in thousands)
OE
Balance, January 1, 2006		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		-		$	-
TE
Balance, January 1, 2006		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		-		$	-
JCP&L
Balance, January 1, 2006		125,000		$	12,649
Redemptions-
4.00% Series		(125,000	)		(12,649	)
Balance, December 31, 2006		-		$	-

(C) LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS

Securitized Transition Bonds

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

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt JCP&L's Consolidated Balance Sheets. As of December 31, 2008, $369 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 consist 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

FGCO and each of the Utilities, except for JCP&L,  have a first mortgage indenture under which they can issue FMBs secured by a direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property.

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FES and the Utilities 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 in a number of the respective financing arrangements of FirstEnergy, FES, FGCO, NGC and the Utilities. These provisions generally trigger a default in the applicable financing arrangement of an entity if it or any of its significant subsidiaries defaults under another financing arrangement of a certain principal amount, typically $50 million. Although such defaults by any of the Utilities will generally cross-default FirstEnergy financing arrangements containing these provisions, defaults by FirstEnergy will not generally cross-default applicable financing arrangements of any of the Utilities. Defaults by any of FES, FGCO or NGC will generally cross-default to applicable financing arrangements of FirstEnergy and, due to the existence of guarantees by FirstEnergy of certain financing arrangements of FES, FGCO and NGC, defaults by FirstEnergy will generally cross-default FES, FGCO and NGC financing arrangements containing these provisions. Cross-default provisions are not typically found in any of the senior note or FMBs of FirstEnergy or the Utilities.

Based on the amount of FMBs authenticated by the respective mortgage bond trustees through December 31, 2008, the Utilities’ annual sinking fund requirement for all FMBs issued under the various mortgage indentures amounted to $5 million for Penn, $8 million for Met-Ed and $21 million for Penelec. Penn expects to deposit funds with its mortgage bond trustee in 2009 that will then be withdrawn upon the surrender for cancellation of a like principal amount of FMBs, specifically authenticated for such purposes against unfunded property additions or against previously retired FMBs. 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 FMBs or cash to the respective mortgage bond trustees.

As of December 31, 2008, currently payable long-term debt includes variable interest rate PCRBs of $2.0 billion for FES, $100 million for OE, $29 million for Met-Ed and $45 million for Penelec, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds, or if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.

Prior to the third quarter of 2008, FES and the Utilities had not experienced any unsuccessful remarketings of these variable-rate PCRBs. Coincident with recent disruptions in the variable-rate demand bond and capital markets generally, certain of the PCRBs had been tendered by bondholders to the trustee. As of January 31, 2009, all PCRBs that had been tendered were successfully remarketed.

In February 2009, holders of approximately $434 million in principal of LOC-supported PCRBs of NGC were notified that the applicable Wachovia Bank LOCs expire on March 18, 2009. As a result, these PCRBs are subject to mandatory purchase at a price equal to the principal amount, plus accrued and unpaid interest, which FES and NGC expect to fund through short-term borrowings. Subject to market conditions, FES and NGC expect to remarket or refinance these PCRBs during the remainder of 2009.

The sinking fund requirements for FES and the Utilities for FMBs and maturing long-term debt (excluding capital leases) for the next five years are:

Year	FES		OE		CEI		JCP&L		Met-Ed		Penelec
	(In millions)
2009	$	2,020	$	101	$	150	$	29	$	29	$	145
2010		68		65		18		31		100		59
2011		83		1		20		32		-		-
2012		124		1		22		34		-		-
2013		75		2		324		36		150		-

Included in the table above are amounts for the variable interest rate PCRBs described above. The following table classifies the outstanding PCRBs by year, representing the next time the debt holders may exercise their right to tender their PCRBs.

Year	FES		OE		Met-Ed		Penelec
	(In millions)
2009	$	1,979	$	100	$	29	$	45
2010		15		-		-		-
2011		25		-		-		-
2012		56		-		-		-

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Obligations to repay certain PCRBs are secured by several series of FMBs. Certain PCRBs are entitled to the benefit of irrevocable bank LOCs of $2.1 billion as of December 31, 2008, or noncancelable municipal bond insurance of $39 million as of December 31, 2008, to pay principal of, or interest on, the applicable PCRBs. To the extent that drawings are made under the LOCs or the policies, FGCO, NGC and the Utilities are entitled to a credit against their obligation to repay those bonds. FGCO, NGC and the Utilities pay annual fees of 0.35% to 1.70% of the amounts of the LOCs to the issuing banks and are obligated to reimburse the banks or insurers, as the case may be, for any drawings thereunder. The insurers hold FMBs as security for such reimbursement obligations. These amounts and percentages for FES and the Utilities are as follows:

	FES			OE			Met-Ed			Penelec
	In millions
Amounts
LOCs	$	1,916	*	$	101		$	29		$	45
Insurance Policies		-			1			14			24
Fees
LOCs	0.35% to 0.90		%		1.70	%		0.85	%		0.85	%
* Includes LOC of $490 million issued for FirstEnergy on behalf of NGC

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 Utilities 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 Utilities have recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47.

The ARO liabilities for FES, OE and TE primarily relate to the 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 decommissioning of the TMI-2 nuclear generating facility. FES and the Utilities use an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs.

FES and the Utilities maintain nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. The fair values of the decommissioning trust assets as of December 31, 2008 and 2007 were as follows:

	2008		2007
	(In millions)
FES	$	1,034	$	1,333
OE		117		127
TE		74		67
JCP&L		143		176
Met-Ed		226		287
Penelec		115		138

FIN 47 provides accounting standards for conditional retirement obligations associated with tangible long-lived assets, requiring recognition of the fair value of a liability for an ARO in the period in which it is incurred if a reasonable estimate can be identified. FIN 47 states that anobligation exists even though there may be uncertainty about timing or method of settlement andfurther clarifies SFAS 143, stating that the uncertainty surrounding the timing and method of settlement when settlement is conditional on a future event occurring should be reflected in the measurement of the liability, not in the recognition of the liability. Accounting for conditional ARO under FIN 47 is the same as described above for SFAS 143.

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The following table describes the changes to the ARO balances during 2008 and 2007.

ARO Reconciliation	FES			OE			CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Balance as of January 1, 2007	$	760		$	88		$	2	$	27	$	84	$	151	$	77
Liabilities settled		(1	)		-			-		-		-		-		-
Accretion		51			6			-		1		6		10		5
Balance as of December 31, 2007		810			94			2		28		90		161		82
Liabilities settled		(2	)		-			-		-		-		-		-
Accretion		55			5			-		2		5		10		5
Revisions in estimated
cash flows		-			(18	) (1)		-		-		-		-		-
Balance as of December 31, 2008	$	863		$	81		$	2	$	30	$	95	$	171	$	87
(1)   OE revised the estimated cash flows associated with the retired Gorge and Toronto plants based on an agreement to remediate asbestos at the sites within one year.

12. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT

FirstEnergy, FES and the Utilities are parties to a $2.75 billion five-year revolving credit facility. FirstEnergy has the ability to request an increase in the total commitments available under this facility up to a maximum of $3.25 billion, subject to the discretion of each lender to provide additional commitments. Commitments under the facility are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.  The annual facility fee is 0.125%

The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of December 31, 2008:

	Revolving				Regulatory and
	Credit Facility				Other Short-Term
Borrower	Sub-Limit				Debt Limitations
	(In millions)
FES		$	1,000			$	-	(1)
OE			500				500
Penn			50				39	(2)
CEI			250	(3)			500
TE			250	(3)			500
JCP&L			425				428	(2)
Met-Ed			250				300	(2)
Penelec			250				300	(2)

(1)	No regulatory approvals, statutory or charter limitations applicable.
(2)	Excluding amounts which may be borrowed under the regulated companies’ money pool.
(3)	Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s.

The regulated companies also have the ability to borrow from each other and FirstEnergy to meet their short-term working capital requirements. A similar but separate arrangement exists among the unregulated companies. FESC administers these two money pools and tracks FirstEnergy’s surplus funds and those of the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2008 was 2.93% for the regulated companies’ money pool and 2.87% for the unregulated companies’ money pool.

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The Utilities, 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 commitment by company are shown in the following table. There were no outstanding borrowings as of December 31, 2008.

Subsidiary Company	Parent Company	Commitment		Annual Facility Fee		Maturity
	(In millions)
OES Capital, Incorporated	OE	$	170	0.20	%	February 22, 2010
Centerior Funding Corporation	CEI	200		0.20		February 22, 2010
Penn Power Funding LLC	Penn	25		0.60		December 18, 2009
Met-Ed Funding LLC	Met-Ed	80		0.60		December 18, 2009
Penelec Funding LLC	Penelec	75		0.60		December 18, 2009
		$	550

The weighted average interest rates on short-term borrowings outstanding as of December 31, 2008 and 2007 were as follows:

	2008			2007
FES		1.08	%		5.23	%
OE(1)		-			4.80	%
CEI		1.77	%		5.10	%
TE		1.46	%		5.04	%
JCP&L		1.46	%		5.04	%
Met-Ed		0.92	%		5.17	%
Penelec		0.95	%		5.04	%

(1) In 2008, OE’s short-term borrowings consisted of noninterest-bearing notes related to its investment in certain low-income housing limited partnerships.

13. COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A) NUCLEAR INSURANCE

The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $12.5 billion (assuming 104 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $300 million; and (ii) $12.2 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $118 million (but not more than $18 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s maximum potential assessment under these provisions would be $470 million (OE-$40 million, NGC-$408 million, and TE-$22 million) per incident but not more than $70 million (OE-$6 million, NGC-$61 million, and TE-$3 million) in any one year for each incident.

In addition to the public liability insurance provided pursuant to the Price-Anderson Act, FirstEnergy has also obtained insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of Nuclear Electric Insurance Limited (NEIL) which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $2.0 billion (OE-$168 million, NGC-$1.7 billion, TE-$89 million) for replacement power costs incurred during an outage after an initial 20-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy’s present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $18 million (OE-$1 million, NGC-$16 million, and TE-$1 million).

FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the operating company for each plant. Under these arrangements, up to $2.8 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. FirstEnergy pays annual premiums for this coverage and is liable for retrospective assessments of up to approximately $61 million (OE-$6 million, NGC-$52 million, TE-$2 million, Met Ed, Penelec and JCP&L-$1 million in total) during a policy year.

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FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of FirstEnergy’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by FirstEnergy’s insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs.

(B) GUARANTEES AND OTHER ASSURANCES

FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ book of business as of December 31, 2008, and forward prices as of that date, FES had $103 million outstanding in margining accounts. Under a hypothetical adverse change in forward prices (15% decrease in prices), FES would be required to post an additional $98 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post significantly higher amounts for margining.

In July 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 (see Notes 6 and 14). The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.

On October 8, 2008, to enhance their liquidity position in the face of the turbulent credit and bond markets, FirstEnergy, FES and FGCO entered into a $300 million secured term loan facility with Credit Suisse. Under the facility, FGCO is the borrower and FES and FirstEnergy are guarantors. Generally, the facility is available to FGCO until October 7, 2009, with a minimum borrowing amount of $100 million and maturity 30 days from the date of the borrowing. This facility is currently unused.

Also in October 2008, FirstEnergy negotiated with the banks that have issued irrevocable direct pay LOCs in support of its outstanding variable interest rate PCRBs to extend the respective reimbursement obligations of the applicable FirstEnergy subsidiary obligors in the event that such LOCs are drawn upon. FirstEnergy’s subsidiaries currently have approximately $2.1 billion variable interest rate PCRBs outstanding (FES - $1.9 billion, OE - $100 million, Met-Ed - - $29 million and Penelec - $45 million). The LOCs supporting these PCRBs may be drawn upon to pay the purchase price to bondholders that have exercised the right to tender their PCRBs for mandatory purchase. A total of approximately $972 million of LOCs that previously required reimbursement within 30 days or less of a draw under the applicable LOC have now been modified to extend the reimbursement obligations to six months or June 2009, as applicable.

(C) ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FES and the Utilities with regard to air and water quality and other environmental matters. The effects of compliance on FES and the Utilities with regard to environmental matters could have a material adverse effect on their earnings and competitive position to the extent that they compete 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 and the Utilities 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 Utilities’ determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

Clean Air Act Compliance

FES is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $37,500 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 CAA. FES has disputed those alleged violations based on its CAA 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 emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.

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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.

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 and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s 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 was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, 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. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $506 million for 2009-2010 (with $414 million expected to be spent in 2009). This amount excludes the potential AQC expenditures related to Burger Units 4 and 5 described below. On September 8, 2008, the Environmental Enforcement Section of the DOJ sent a letter to OE regarding its view that the company was not in compliance with the Sammis NSR Litigation consent decree because the installation of an SNCR at Eastlake Unit 5 was not completed by December 31, 2006. However, the DOJ acknowledged that stipulated penalties could not apply under the terms of the Sammis NSR Litigation consent decree because Eastlake Unit 5 was idled on December 31, 2006 pending installation of the SNCR and advised that it had exercised its discretion not to seek any other penalties for this alleged non-compliance. OE disputed the DOJ's interpretation of the consent decree in a letter dated September 22, 2008. Although the Eastlake Unit 5 issue is no longer active, OE filed a dispute resolution petition on October 23, 2008, with the United States District Court for the Southern District of Ohio, due to potential impacts on its compliance decisions with respect to Burger Units 4 and 5. On December 23, 2008, OE withdrew its dispute resolution petition and subsequently filed a motion to extend the date (from December 31, 2008 to April 15, 2009), under the Sammis NSR Litigation consent decree, to elect for Burger Units 4 and 5 to permanently shut down those units by December 31, 2010, or to repower them or to install flue gas desulfurization (FGD) by later dates. On January 30, 2009, the Court issued an order extending the election date from December 31, 2008 to March 31, 2009.

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 revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.  On December 10, 2008, the EPA announced it would not finalize this proposed changes to the NSR.

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 CAA, 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 18, 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. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.

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On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR 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 NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, but the Court has yet to rule on Connecticut’s Motion. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986.  Met-Ed is unable to predict the outcome of this matter.  The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.

On June 11, 2008, the EPA issued a Notice and Finding of Violation to MEW alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. MEW is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from MEW is disputed. Penelec is unable to predict the outcome of this matter.

On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an ACO modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. FGCO intends to fully comply with the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter.

On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.

National Ambient Air Quality Standards

In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR.  On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. The future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

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Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the 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 petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the United States moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the United States’ petition and denied the industry group’s petition. Accordingly, the EPA could 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. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule.  It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was 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.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration had 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. Also, in an April 16, 2008 speech, former President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. 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. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity in the United States comes from renewable sources by 2012, and 25% by 2025; and implementing an economy-wide cap-and-trade program to reduce GHG emissions 80% by 2050.

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 Environment and Public Works Committee has 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 CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting input from the public on the effects of climate change and the potential ramifications of regulation of CO2 under the CAA.

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

Clean Water Act

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

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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 EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review one significant aspect of the Second Circuit Court’s opinion which is whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures.  Oral argument before the Supreme Court occurred on December 2, 2008 and a decision is anticipated during the first half of 2009. FES is studying various control options and their costs and effectiveness. Depending on the results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

The U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007.  FGCO is unable to predict the outcome of this matter.

Regulation of Hazardous Waste

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

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of December 31, 2008, FirstEnergy had approximately $1.7 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry 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 Utilities 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, 2008, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $90 million (JCP&L - $64 million, CEI - - $1 million, TE - $1 million and FirstEnergy Corp. - $24 million) have been accrued through December 31, 2008. Included in the total are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

(D) OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

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

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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 and a case management conference with the presiding Judge was held on June 13, 2008. At that conference, the plaintiffs stated their intent to drop their efforts to create a class-wide damage model and, instead of dismissing the class action, expressed their desire for a bifurcated trial on liability and damages. The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario. Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure.JCP&L has received the plaintiffs’ proposed plan of action, and intends to file its objection to the proposed plan, and also file a renewed motion to decertify the class. JCP&L is defending this action but is unable to predict the outcome. No liability has been accrued as of December 31, 2008.

On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours, and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. In a letter dated January 30, 2009, the NERC submitted a written “Notice of Request for Information” (NOI) to JCP&L. The NOI asked for additional factual details about the December 9 event, which JCP&L provided in its response. JCP&L is not able to predict what actions, if any, the NERC may take in response to JCP&L's NOI submittal.

Nuclear Plant Matters

On May 14, 2007, the Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (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 Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC has conducted the employee training required by the confirmatory order and a consultant has performed follow-up reviews to ensure the effectiveness of that training. The NRC continues to monitor FENOC’s compliance with all the commitments made in the confirmatory order.

In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.

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Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FES' and the Utilities’ normal business operations pending against them. The other potentially material items not otherwise discussed above are described below.

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs also sought 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 opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. Plaintiffs appealed the Court’s denial of the motion for certification as a class action which the Ohio Court of Appeals (7th District) denied on December 11, 2008. The period to file a notice of appeal to the Ohio Supreme Court has expired.

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. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. The Court has yet to render its decision. JCP&L recognized a liability for the potential $16 million award in 2005.

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

FES and the Utilities accrue legal 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. If it were ultimately determined that FES and the Utilities have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on their financial condition, results of operations and cash flows.

14.  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 fully and unconditionally guaranteed all of FGCO’s obligations under each of the leases.  The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty. This transaction is classified as an operating lease under GAAP for FES and a financing for FGCO.

The consolidating statements of income for the three years ended December 31, 2008, consolidating balance sheets as of December 31, 2008, and December 31, 2007, and condensed consolidating statements of cash flows for the three years ended December 31, 2008, for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved (see Note 6). The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
For the Year Ended December 31, 2008	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	4,470,112		$	2,275,451		$	1,204,534		$	(3,431,744	)	$	4,518,353
EXPENSES:
Fuel		16,322			1,171,993			126,978			-			1,315,293
Purchased power from affiliates		3,417,126			14,618			101,409			(3,431,744	)		101,409
Purchased power from non-affiliates		778,882			-			-			-			778,882
Other operating expenses		116,972			416,723			502,096			48,757			1,084,548
Provision for depreciation		5,986			119,763			111,529			(5,379	)		231,899
General taxes		19,260			46,153			22,591			-			88,004
Total expenses		4,354,548			1,769,250			864,603			(3,388,366	)		3,600,035
OPERATING INCOME		115,564			506,201			339,931			(43,378	)		918,318
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		449,167			(3,366	)		(35,665	)		(431,116	)		(20,980	)
Interest expense to affiliates		(314	)		(20,342	)		(9,173	)		-			(29,829	)
Interest expense - other		(24,674	)		(95,926	)		(56,486	)		65,404			(111,682	)
Capitalized interest		142			39,934			3,688			-			43,764
Total other income (expense)		424,321			(79,700	)		(97,636	)		(365,712	)		(118,727	)
INCOME BEFORE INCOME TAXES		539,885			426,501			242,295			(409,090	)		799,591
INCOME TAXES		33,475			155,100			90,247			14,359			293,181
NET INCOME	$	506,410		$	271,401		$	152,048		$	(423,449	)	$	506,410

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING 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 affiliates		3,038,786			186,415			73,844			(3,064,955	)		234,090
Purchased power from non-affiliates		764,090			-			-			-			764,090
Other operating expenses		161,797			352,856			514,389			11,997			1,041,039
Provision for depreciation		2,269			99,741			92,239			(1,337	)		192,912
General taxes		20,953			41,456			24,689			-			87,098
Total expenses		4,014,064			1,623,414			823,056			(3,054,295	)		3,406,239
OPERATING INCOME		331,726			358,752			238,970			(10,660	)		918,788
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		341,978			4,210			14,880			(308,192	)		52,876
Interest expense to affiliates		(1,320	)		(48,536	)		(15,645	)		-			(65,501	)
Interest expense - other		(9,503	)		(59,412	)		(39,458	)		16,174			(92,199	)
Capitalized interest		35			14,369			5,104			-			19,508
Total other income (expense)		331,190			(89,369	)		(35,119	)		(292,018	)		(85,316	)
INCOME BEFORE INCOME TAXES		662,916			269,383			203,851			(302,678	)		833,472
INCOME TAXES		134,052			90,801			77,467			2,288			304,608
NET INCOME	$	528,864		$	178,582		$	126,384		$	(304,966	)	$	528,864

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING 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 affiliates		2,804,110			180,759			80,239			(2,808,107	)		257,001
Purchased power from non-affiliates		590,491			-			-			-			590,491
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

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
As of December 31, 2008	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	-	$	39	$	-	$	-		$	39
Receivables-
Customers		86,123		-		-		-			86,123
Associated companies		363,226		225,622		113,067		(323,815	)		378,100
Other		991		11,379		12,256		-			24,626
Notes receivable from associated companies		107,229		21,946		-		-			129,175
Materials and supplies, at average cost		5,750		303,474		212,537		-			521,761
Prepayments and other		76,773		35,102		660		-			112,535
		640,092		597,562		338,520		(323,815	)		1,252,359
PROPERTY, PLANT AND EQUIPMENT:
In service		134,905		5,420,789		4,705,735		(389,525	)		9,871,904
Less - Accumulated provision for depreciation		13,090		2,702,110		1,709,286		(169,765	)		4,254,721
		121,815		2,718,679		2,996,449		(219,760	)		5,617,183
Construction work in progress		4,470		1,441,403		301,562		-			1,747,435
		126,285		4,160,082		3,298,011		(219,760	)		7,364,618
INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,033,717		-			1,033,717
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		3,596,152		-		-		(3,596,152	)		-
Other		1,913		59,476		202		-			61,591
		3,598,065		59,476		1,096,819		(3,596,152	)		1,158,208
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		24,703		476,611		-		(233,552	)		267,762
Lease assignment receivable from associated companies		-		71,356		-		-			71,356
Goodwill		24,248		-		-		-			24,248
Property taxes		-		27,494		22,610		-			50,104
Unamortized sale and leaseback costs		-		20,286		-		49,646			69,932
Other		59,642		59,674		21,743		(44,625	)		96,434
		108,593		655,421		44,353		(228,531	)		579,836
	$	4,473,035	$	5,472,541	$	4,777,703	$	(4,368,258	)	$	10,355,021
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	5,377	$	925,234	$	1,111,183	$	(16,896	)	$	2,024,898
Short-term borrowings-
Associated companies		1,119		257,357		6,347		-			264,823
Other		1,000,000		-		-		-			1,000,000
Accounts payable-
Associated companies		314,887		221,266		250,318		(314,133	)		472,338
Other		35,367		119,226		-		-			154,593
Accrued taxes		8,272		60,385		30,790		(19,681	)		79,766
Other		61,034		136,867		13,685		36,853			248,439
		1,426,056		1,720,335		1,412,323		(313,857	)		4,244,857
CAPITALIZATION:
Common stockholder's equity		2,944,423		1,832,678		1,752,580		(3,585,258	)		2,944,423
Long-term debt and other long-term obligations		61,508		1,328,921		469,839		(1,288,820	)		571,448
		3,005,931		3,161,599		2,222,419		(4,874,078	)		3,515,871
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,026,584			1,026,584
Accumulated deferred income taxes		-		-		206,907		(206,907	)		-
Accumulated deferred investment tax credits		-		39,439		23,289		-			62,728
Asset retirement obligations		-		24,134		838,951		-			863,085
Retirement benefits		22,558		171,619		-		-			194,177
Property taxes		-		27,494		22,610		-			50,104
Lease market valuation liability		-		307,705		-		-			307,705
Other		18,490		20,216		51,204		-			89,910
		41,048		590,607		1,142,961		819,677			2,594,293
	$	4,473,035	$	5,472,541	$	4,777,703	$	(4,368,258	)	$	10,355,021

138

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 assets		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
	$	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 and other long-term obligations		-		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
	$	3,162,511	$	4,452,888	$	4,092,883	$	(3,286,018	)	$	8,422,264

139

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2008	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
NET CASH PROVIDED FROM OPERATING ACTIVITIES	$	40,791		$	350,986		$	478,047		$	(16,896	)	$	852,928
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt		-			353,325			265,050			-			618,375
Equity contributions from parent		280,000			675,000			175,000			(850,000	)		280,000
Short-term borrowings, net		701,119			18,571			-			(18,931	)		700,759
Redemptions and repayments-
Long-term debt		(2,955	)		(293,349	)		(183,132	)		16,896			(462,540	)
Short-term borrowings, net		-			-			(18,931	)		18,931			-
Common stock dividend payment		(43,000	)		-			-			-			(43,000	)
Other		-			(3,107	)		(2,040	)		-			(5,147	)
Net cash provided from financing activities		935,164			750,440			235,947			(833,104	)		1,088,447
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(43,244	)		(1,047,917	)		(744,468	)		-			(1,835,629	)
Proceeds from asset sales		-			23,077			-			-			23,077
Sales of investment securities held in trusts		-			-			950,688			-			950,688
Purchases of investment securities held in trusts		-			-			(987,304	)		-			(987,304	)
Loans repayments from (loans to) associated companies		(83,457	)		(21,946	)		69,012			-			(36,391	)
Investment in subsidiary		(850,000	)		-			-			850,000			-
Other		744			(54,601	)		(1,922	)		-			(55,779	)
Net cash used for investing activities		(975,957	)		(1,101,387	)		(713,994	)		850,000			(1,941,338	)
Net change in cash and cash equivalents		(2	)		39			-			-			37
Cash and cash equivalents at beginning of year		2			-			-			-			2
Cash and cash equivalents at end of year	$	-		$	39		$	-		$	-		$	39

140

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 contributions 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		-			(1,048,647	)		(494,070	)		6,306			(1,536,411	)
Short-term borrowings, net		-			(783,599	)		-			325,278			(458,321	)
Common stock dividend payment		(117,000	)		-			-			-			(117,000	)
Other		-			(3,474	)		(1,725	)		-			(5,199	)
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 repayments from associated companies		441,966			-			292,896			-			734,862
Investment in subsidiary		(700,000	)		-			-			700,000			-
Other		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	��

141

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		-			565,395			591,515			-			1,156,910
Short-term borrowings, net		-			46,402			-			-			46,402
Redemptions and repayments-
Long-term debt		-			(539,395	)		(591,515	)		-			(1,130,910	)
Common stock dividend payment		(8,454	)		-			(12,765	)		12,765			(8,454	)
Other		-			(3,738	)		(3,161	)		-			(6,899	)
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

142

15. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 141(R) – “Business Combinations”

In December 2007, the FASB issued SFAS 141(R), which: (i) requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction; (ii) establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and (iii) 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. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FES and the Utilities that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in deferred tax valuation allowances and income tax uncertainties made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. Under SFAS 141(R), adjustments to the acquired entity’s deferred tax assets and uncertain tax position balances occurring outside the measurement period will be recorded as a component of income tax expense, rather than goodwill.The impact of the application of this Standard in periods after implementation will be dependent upon the nature of acquisitions at that time.

SFAS 160 - “Non-controlling 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 financial statements of FES or the Utilities.

SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”

In March 2008, the FASB issued SFAS 161 that enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. The FASB believes that additional required disclosure of the fair values of derivative instruments and their gains and losses in a tabular format will provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. This Statement also requires cross-referencing within the footnotes to help users of financial statements locate important information about derivative instruments. The Statement is effective for reporting periods beginning after November 15, 2008. FES expects this Standard to increase its disclosure requirements for derivative instruments and hedging activities.

EITF Issue No. 08-6 – “Equity Method Investment Accounting Considerations”

In November 2008, the FASB issued EITF 08-6, which clarifies how to account for certain transactions involving equity method investments. It provides guidance in determining the initial carrying value of an equity method investment, accounting for a change in an investment from equity method to cost method, assessing the impairment of underlying assets of an equity method investment, and accounting for an equity method investee’s issuance of shares. This statement is effective for transactions occurring in fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is not permitted. The impact of the application of this Standard in periods after implementation will be dependent upon the nature of future investments accounted for under the equity method.

FSP SFAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”

In December 2008, the FASB issued Staff Position (FSP) SFAS 132(R)-1, which provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This FSP is effective for fiscal years ending after December 15, 2009. FES and the Utilities expect this Staff Position to increase their disclosure requirements for postretirement benefit plan assets.

143

16.  SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)

The following summarizes certain consolidated operating results by quarter for 2008 and 2007.

						Income (Loss)
						From Continuing
				Operating		Operations
				Income		Before		Income		Net
Three Months Ended		Revenues		(Loss)		Income Taxes		Taxes		Income
		(In millions)
FES
	March 31, 2008	$	1,099.1	$	175.7	$	147.8	$	57.8	$	90.0
	March 31, 2007		1,018.2		188.7		164.9		62.4		102.5
	June 30, 2008		1,071.3		142.2		115.4		47.3		68.1
	June 30, 2007		1,068.7		263.8		239.1		87.7		151.4
	September 30,2008		1,241.6		288.8		278.9		93.2		185.7
	September 30,2007		1,170.1		272.1		248.4		93.7		154.7
	December 31, 2008		1,106.4		311.6		257.5		94.9		162.6
	December 31, 2007		1,068.0		194.2		181.1		60.8		120.3
OE
	March 31, 2008	$	652.6	$	77.1	$	70.8	$	26.9	$	43.9
	March 31, 2007		625.6		65.4		71.4		17.4		54.0
	June 30, 2008		609.6		76.1		70.5		21.7		48.8
	June 30, 2007		596.8		70.8		73.2		27.6		45.6
	September 30,2008		702.3		100.0		101.0		28.5		72.5
	September 30,2007		668.8		82.0		82.3		34.1		48.2
	December 31, 2008		637.3		80.8		68.0		21.5		46.5
	December 31, 2007		600.3		73.1		71.6		22.2		49.4
CEI
	March 31, 2008	$	437.3	$	110.8	$	88.2	$	30.3	$	57.9
	March 31, 2007		440.8		115.5		98.3		34.8		63.5
	June 30, 2008		434.4		123.4		100.4		33.8		66.6
	June 30, 2007		449.5		128.6		111.0		42.1		68.9
	September 30,2008		524.1		159.9		136.4		43.0		93.4
	September 30,2007		529.1		154.4		133.3		54.6		78.7
	December 31, 2008		420.1		120.5		96.3		29.7		66.6
	December 31, 2007		403.5		113.7		97.2		31.9		65.3
TE
	March 31, 2008	$	211.7	$	26.1	$	25.1	$	8.1	$	17.0
	March 31, 2007		240.5		40.3		37.0		11.1		25.9
	June 30, 2008		221.5		30.9		28.7		7.4		21.3
	June 30, 2007		240.3		40.8		37.3		15.4		21.9
	September 30,2008		251.1		45.1		43.4		12.2		31.2
	September 30,2007		269.7		47.5		43.5		18.4		25.1
	December 31, 2008		211.2		10.8		7.5		2.1		5.4
	December 31, 2007		213.4		28.8		27.2		8.8		18.4

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, 2008	$	400.3	$	45.6	$	38.9	$	16.7	$	22.2
	March 31, 2007		370.3		57.9		55.2		23.6		31.6
	June 30, 2008		392.0		37.8		32.7		12.9		19.8
	June 30, 2007		361.7		38.0		34.3		14.8		19.5
	September 30,2008		455.5		45.1		38.3		16.3		22.0
	September 30,2007		410.6		43.8		39.4		14.7		24.7
	December 31, 2008		405.2		46.1		39.0		15.0		24.0
	December 31, 2007		367.9		45.3		34.9		15.2		19.7
Penelec
	March 31, 2008	$	395.5	$	56.0	$	39.7	$	18.3	$	21.4
	March 31, 2007		355.9		65.7		56.0		24.3		31.7
	June 30, 2008		351.4		44.2		30.4		12.0		18.4
	June 30, 2007		331.4		44.5		33.9		14.4		19.5
	September 30,2008		389.8		46.6		31.7		9.1		22.6
	September 30,2007		353.4		45.8		33.4		10.4		23.0
	December 31, 2008		376.9		57.7		44.0		18.2		25.8
	December 31, 2007		361.3		48.4		33.6		14.9		18.7
JCP&L
	March 31, 2008	$	794.2	$	86.9	$	62.4	$	28.4	$	34.0
	March 31, 2007		683.7		89.9		71.0		32.7		38.3
	June 30, 2008		834.7		97.4		74.4		31.5		42.9
	June 30, 2007		780.0		110.2		89.5		39.7		49.8
	September 30,2008		1,102.6		157.7		131.7		55.8		75.9
	September 30,2007		1,033.2		143.3		122.1		46.3		75.8
	December 31, 2008		740.8		92.5		66.7		32.5		34.2
	December 31, 2007		746.9		76.4		52.6		30.4		22.2

145