FirstEnergy (FE) 10-Q 2008 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C.  20549

FORM 10-Q

(Mark One)

[X]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2008

OR

[  ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.
333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
333-145140-01	FIRSTENERGY SOLUTIONS CORP.	31-1560186
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402
1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-3583	THE TOLEDO EDISON COMPANY	34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-3141	JERSEY CENTRAL POWER & LIGHT COMPANY	21-0485010
	(A New Jersey Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-3522	PENNSYLVANIA ELECTRIC COMPANY	25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer,” “accelerated filer” and “smaller reporting company" in Rule 12b-2 of the Exchange Act.

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

Smaller Reporting Company (  ) N/A

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

	OUTSTANDING
CLASS	AS OF November 6, 2008
FirstEnergy Corp., $0.10 par value	304,835,407
FirstEnergy Solutions Corp., no par value	7
Ohio Edison Company, no par value	60
The Cleveland Electric Illuminating Company, no par value	67,930,743
The Toledo Edison Company, $5 par value	29,402,054
Jersey Central Power & Light Company, $10 par value	14,421,637
Metropolitan Edison Company, no par value	859,500
Pennsylvania Electric Company, $20 par value	4,427,577

FirstEnergy Corp. is the sole holder of FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company common stock.

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

OMISSION OF CERTAIN INFORMATION

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

Forward-Looking Statements: This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or 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 rulemaking process on the Ohio Companies’ ESP and MRO filings,

·   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 FirstEnergy’s regulated utilities to collect transition and other charges or to recover increased transmission costs,

·   maintenance costs being higher than anticipated,

·   other legislative and regulatory changes, revised environmental requirements, including possible GHG emission regulations,

·   the impact of the U.S. Court of Appeals’ July 11, 2008 decision to vacate 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 Air Quality Compliance Plan (including that such amounts could be higher than anticipated) or levels of emission reductions related to the Consent Decree resolving the 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 ESP and MRO proceedings as well as the distribution rate cases and the generation supply plan filing for the Ohio Companies and the successful resolution of the issues remanded to the PUCO by the Ohio Supreme Court regarding the RSP and RCP, including the recovery of deferred fuel costs),

·   Met-Ed’s and Penelec’s transmission service charge filings with the PPUC as well as the resolution of the Petitions for Review filed with the Commonwealth Court of Pennsylvania with respect to the transition rate plan for Met-Ed and Penelec,

·   the continuing availability of generating units and their ability to operate at or near full capacity,

·   the 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 the registrants’ nuclear decommissioning trusts, pension trusts and other trust funds, and cause FirstEnergy 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, and

·   the risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors.

The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on the registrants’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. Also, a security rating is not a recommendation to buy, sell or hold securities, and it may be subject to revision or withdrawal at any time and each such rating should be evaluated independently of any other rating. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events or otherwise.

TABLE OF CONTENTS

		Pages
Glossary of Terms		iii-v
Part I.     Financial Information
Items 1. and 2. - Financial Statements and Management’s Discussion and Analysis ofFinancial Condition and Results of Operations.
FirstEnergy Corp.
	Management's Discussion and Analysis of Financial Condition and
	Results of Operations	1-46
	Report of Independent Registered Public Accounting Firm	47
	Consolidated Statements of Income	48
	Consolidated Statements of Comprehensive Income	49
	Consolidated Balance Sheets	50
	Consolidated Statements of Cash Flows	51
FirstEnergy Solutions Corp.
	Management's Narrative Analysis of Results of Operations	52-54
	Report of Independent Registered Public Accounting Firm	55
	Consolidated Statements of Income and Comprehensive Income	56
	Consolidated Balance Sheets	57
	Consolidated Statements of Cash Flows	58
Ohio Edison Company
	Management's Narrative Analysis of Results of Operations	59-60
	Report of Independent Registered Public Accounting Firm	61
	Consolidated Statements of Income and Comprehensive Income	62
	Consolidated Balance Sheets	63
	Consolidated Statements of Cash Flows	64
The Cleveland Electric Illuminating Company
	Management's Narrative Analysis of Results of Operations	65-66
	Report of Independent Registered Public Accounting Firm	67
	Consolidated Statements of Income and Comprehensive Income	68
	Consolidated Balance Sheets	69
	Consolidated Statements of Cash Flows	70
The Toledo Edison Company
	Management's Narrative Analysis of Results of Operations	71-73
	Report of Independent Registered Public Accounting Firm	74
	Consolidated Statements of Income and Comprehensive Income	75
	Consolidated Balance Sheets	76
	Consolidated Statements of Cash Flows	77

i

TABLE OF CONTENTS (Cont'd)

Jersey Central Power & Light Company		Pages
	Management's Narrative Analysis of Results of Operations	78-79
	Report of Independent Registered Public Accounting Firm	80
	Consolidated Statements of Income and Comprehensive Income	81
	Consolidated Balance Sheets	82
	Consolidated Statements of Cash Flows	83
Metropolitan Edison Company
	Management's Narrative Analysis of Results of Operations	84-85
	Report of Independent Registered Public Accounting Firm	86
	Consolidated Statements of Income and Comprehensive Income	87
	Consolidated Balance Sheets	88
	Consolidated Statements of Cash Flows	89
Pennsylvania Electric Company
	Management's Narrative Analysis of Results of Operations	90-91
	Report of Independent Registered Public Accounting Firm	92
	Consolidated Statements of Income and Comprehensive Income	93
	Consolidated Balance Sheets	94
	Consolidated Statements of Cash Flows	95
Combined Management’s Discussion and Analysis of Registrant Subsidiaries		96-111
Combined Notes to Consolidated Financial Statements		112-147
Item 3. Quantitative and Qualitative Disclosures About Market Risk.		148
Item 4. Controls and Procedures – FirstEnergy.		148
Item 4T.          Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.		148
Part II.    Other Information
Item 1. Legal Proceedings.		149
Item 1A.         Risk Factors.		149
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.		149
Item 6. Exhibits.		150

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, Incorporated, owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
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
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies	Met-Ed, Penelec and Penn
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak	A joint venture between FirstEnergy Ventures Corp. and Boich Companies, that owns mining and coal transportation operations near Roundup, Montana, formerly known as Bull Mountain
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
Utilities	OE, CEI, TE, JCP&L, Met-Ed and 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, Inc.
AOCL	Accumulated Other Comprehensive Loss
ARB	Accounting Research Bulletin
ARO	Asset Retirement Obligation
ASM	Ancillary Services Market
BGS	Basic Generation Service
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CBP	Competitive Bid Process
CO2	Carbon Dioxide
DFI	Demand for Information
DOJ	United States Department of Justice
DRA	Division of Ratepayer Advocate
EIS	Energy Independence Strategy
EITF	Emerging Issues Task Force
EMP	Energy Master Plan
EPA	United States 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"

iii

GLOSSARY OF TERMS, Cont’d.

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
FTR	Financial Transmission Rights
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
LIBOR	London Interbank Offered Rate
LOC	Letter of Credit
MEIUG	Met-Ed Industrial Users Group
MEW	Mission Energy Westside, Inc.
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
MRO	Market Rate Offer
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
NYMEX	New York Mercantile Exchange
OCA	Office of Consumer Advocate
OTC	Over the Counter
OVEC	Ohio Valley Electric Corporation
PCRB	Pollution Control Revenue Bond
PICA	Penelec Industrial Customer Alliance
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PSA	Power Supply Agreement
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RECB	Regional Expansion Criteria and Benefits
RFP	Request for Proposal
RPM	Reliability Pricing Model
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Service
SB221	Amended Substitute Senate Bill 221
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
SFAS	Statement of Financial Accounting Standards
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”

iv

GLOSSARY OF TERMS, Cont’d.

SFAS 142	SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS 143	SFAS No. 143, “Accounting for Asset Retirement Obligations”
SFAS 157	SFAS No. 157, “Fair Value Measurements”
SFAS 159	SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”
SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
TSC	Transmission Service Charge
VIE	Variable Interest Entity

v

PART I. FINANCIAL INFORMATION

ITEMS 1. AND 2. FINANCIAL STATEMENTS AND MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

Net income in the third quarter of 2008 was $471 million, or basic earnings of $1.55 per share of common stock ($1.54 diluted), compared with net income of $413 million, or basic earnings of $1.36 per share of common stock ($1.34 diluted) in the third quarter of 2007. Net income in the first nine months of 2008 was $1.01billion, or basic earnings of $3.32per share of common stock ($3.29diluted), compared with net income of $1.04 billion, or basic earnings of $3.39 per share of common stock ($3.35 diluted) in the first nine months of 2007.

	Three Months			Nine Months
Change in Basic Earnings Per Share	Ended			Ended
From Prior Year Periods	September 30			September 30
Basic Earnings Per Share – 2007	$	1.36		$	3.39
Gain on non-core asset sales – 2008/2007		(0.04	)		0.02
Litigation settlement – 2008		-			0.03
Saxton decommissioning regulatory asset – 2007		-			(0.05	)
Trust securities impairment		(0.05	)		(0.09	)
Revenues		0.57			1.36
Fuel and purchased power		(0.34	)		(1.16	)
Depreciation and amortization		(0.02	)		(0.07	)
Deferral of new regulatory assets		(0.10	)		(0.23	)
Investment Income – decommissioning trusts   and corporate-owned life insurance		0.04			(0.05	)
Income tax adjustments		0.12			0.12
Other expense reductions		0.01			0.02
Reduced common shares outstanding		-			0.03
Basic Earnings Per Share – 2008	$	1.55		$	3.32

Recent Market Developments

In response to the recent unprecedented volatility in the capital and credit markets, FirstEnergy continues to assess its exposure to counterparty credit risk, its access to funds in the capital and credit markets, and market-related changes in the value of its postretirement benefit trusts, nuclear decommissioning trusts and other investments. FirstEnergy has taken several  steps to strengthen its liquidity position and provide additional flexibility to meet its anticipated obligations and those of its subsidiaries. While FirstEnergy believes its existing sources of liquidity will continue to be available to meet its anticipated obligations, management is reviewing its 2009 plans to determine what adjustments should be made to operating and capital budgets in response to the economic climate to reduce the need for external sources of capital. Although this process is not yet complete, management expects that FirstEnergy's capital expenditures will be reduced from the levels previously anticipated; however, it expects to continue to meet commitments for required capital projects and necessary operational expenditures.

Liquidity

FirstEnergy has access to more than $4 billion of liquidity, of which approximately $1.9 billion was available as of October 31, 2008. FirstEnergy and its subsidiaries have approximately $404 million available under a $2.75 billion revolving credit facility, with no one financial institution having more than 7.3% of the total commitment. An additional $1.1 billion was available through other commitments including: bank credit facilities totaling $420 million; a $300 million term loan with Credit Suisse, discussed below; and $550 million of accounts receivable financing facilities. FirstEnergy had $456 million of cash and cash equivalents as of October 31, 2008.

FirstEnergy’s currently payable long-term debt includes approximately $2.1 billion of variable-rate PCRBs. The interest rates on these PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory repurchase prior to their maturity with the purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings under irrevocable direct pay LOCs. Prior to September 18, 2008, FirstEnergy had not experienced any unsuccessful remarketings of these variable-rate PCRBs.

1

Coincident with recent disruptions in the variable-rate demand bond and capital markets generally, certain of the PCRBs have been tendered by bondholders to the trustee. As of October 31, 2008, $72.5 million of the PCRBs, all of which are backed by Wachovia Bank LOCs, had been tendered and not yet successfully remarketed. Of these, draws on the applicable LOCs were made for $72.4 million, all of which Wachovia honored. The reimbursement agreements between the subsidiary obligors and Wachovia require reimbursement of outstanding LOC draws by March 2009.

As a further safeguard in the event of future draws on these LOCs, in early October 2008 FirstEnergy negotiated with the banks that have issued the LOCs to extend the term of the respective reimbursement obligations. Approximately $902 million of LOCs that previously required reimbursement of LOC draws within 30 days or less were modified to extend the reimbursement obligations to six months or June 2009, as applicable.

FirstEnergy also enhanced its liquidity position during this period of turmoil in the credit and capital markets by securing, on October 8, 2008, 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 with repayment due 30 days after the borrowing date subject to extension at the end of each quarter until two days after the release of results of operations. Advances under the facility are not available for re-borrowing after they are repaid.

Access to the capital markets and costs of financing are influenced by the ratings of the securities of FirstEnergy and its subsidiaries. On August 1, 2008, S&P changed its outlook for FirstEnergy and its subsidiaries from “negative” to “stable.” Moody’s outlook for FirstEnergy and its subsidiaries remains “stable.” The credit ratings of FirstEnergy or its subsidiaries also govern the collateral provisions of certain contract guarantees. Subsequent to the occurrence of a credit rating downgrade to below investment grade or a “material adverse event,” the immediate posting of cash collateral may be required. As of September 30, 2008, FirstEnergy’s maximum exposure under these collateral provisions was $573 million, consisting of $64 million due to “material adverse event” contractual clauses and $509 million due to a below investment grade credit rating. Stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase this amount to $648 million, consisting of $58 million due to “material adverse event” contractual clauses and $590 million due to a below investment grade credit rating. FirstEnergy’s revolving credit facility does not contain provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in these credit ratings although a change in credit rating could increase FirstEnergy’s cost of borrowing. FirstEnergy does not anticipate current market conditions to result in any events that will result in posting additional collateral or that will impact its ability to remain in compliance with its debt covenants.

Long-Term Financing

On October 20, 2008, OE issued $300 million of FMBs, comprised of $275 million 8.25% Series of 2008 due 2038 and $25 million 8.25% Series of 2008 due 2018. OE will use the net proceeds from these offerings to fund capital expenditures and for other general corporate purposes. CEI, TE and Met-Edeachhave regulatory authority to issue up to $300 million of long-term debt, and requests are pending before the NJBPU and PPUC for authority to issue up to an aggregate $400 million of additional utility long-term debt. FirstEnergy intends to execute these long-term financings as it deems appropriate and as market conditions permit.

Counterparty Credit Risk

FirstEnergy and its subsidiaries are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations or the potential non-performance of counterparties to deliver contracted commodities or services at the contracted price. FirstEnergy routinely performs counterparty risk evaluations including monitoring of credit default spreads of counterparties, monitors portfolio trends and uses collateral and contract provisions to mitigate exposure. Recent market events including, but not limited to, the default of Lehman have resulted in a more stringent approach to counterparty credit evaluations resulting in a decrease in the number of approved counterparties. FirstEnergy’s subsidiaries have long-term power and coal contracts with certain counterparties that, in the event of the counterparty’s default, would likely be replaced with contracts having less favorable terms that may negatively impact financial condition and results of operations. FirstEnergy has reviewed its insurance coverage and believes that the availability and cost of liability, property, nuclear risk and other forms of insurance have not been materially impacted by recent events, but will continue to monitor the events and ratings of the companies which provide insurance coverage for FirstEnergy and its subsidiaries.

Investments

Despite recent declines in the value of FirstEnergy’s pension plan investments, contributions to the plan will not be required in 2009. The overall actual investment return as of October 31, 2008 was a loss of 25.4% compared to an assumed 9% positive return. Based on an 8% discount rate assumption, if the ultimate return for 2008 was to remain at a loss of 25.4%, 2009 pre-tax net periodic pension expense would be approximately $145 million, an increase of approximately $180 million compared to the year 2008. If the ultimate return for 2008 was to remain at a loss of 25.4%, FirstEnergy would also not be required to make contributions in 2010. However, if assets were to decline an additional 1% from October 31, 2008 through the end of 2008, contributions of approximately $65 million would be required in 2010.

2

This information does not consider any actions management may take to mitigate the impact of the asset return shortfalls, including changes in the amount and timing of future contributions. The actuarial assumptions used in the determination of pension and postretirement benefit costs are interrelated and changes in other assumptions could have the impact of offsetting all or a portion of the potential increase in benefit costs set forth above.

Nuclear decommissioning trust funds have been established to satisfy NGC’s and the Utilities’ nuclear decommissioning obligations. As of September 30, 2008, approximately 47% of the funds were invested in equity securities and 53% were invested in fixed income securities, with limitations related to concentration and investment grade ratings.

The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses 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. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts. Nuclear decommissioning trust securities impairments totaled $63 million in the first nine months of 2008. FirstEnergy does not expect to make additional cash contributions to the nuclear decommissioning trusts in 2009, other than the required annual TMI-2 trust contribution that is collected through customer rates. However, should the trust funds continue to experience declines in market value, FirstEnergy may be required to take measures, such as providing financial guarantees through letters of credit or parental guarantees or making additional contributions to the trusts to ensure that the trusts are adequately funded and meet minimum NRC funding requirements.

In connection with the decommissioning of TMI-2, Met-Ed, Penelec and JCP&L make a combined annual contribution of approximately $13 million. In connection with the 2005 intra-system generation asset transfer, NGC is required to contribute $80 million to the trust by May 2010. See Note 15 to the Notes to Consolidated Financial Statements within FirstEnergy’s 2007 Annual Report on Form 10-K for additional information regarding the intra-system generation asset transfer.

Economic and Operational Risks

Results in the third quarter of 2008 continued to reflect some adverse effects on the demand for electricity as a result of current economic conditions – particularly with respect to the automotive industry. This condition is expected to continue into 2009 with potentially wider application among the Utilities’ customers. FirstEnergy expects to see the impact of slower economic growth in both sales and distribution revenues. Earlier in the year, FirstEnergy enhanced its collection processes with respect to current customer billings and customer deposits. While these efforts may have a mitigating effect, FirstEnergy expects that there could be resulting increases in uncollectible customer accounts in future periods. In addition, the margin on wholesale and retail generation sales may be reduced as a result of lower demand and the resulting downward pressure on power prices.

Regulatory Matters

Ohio Legislative Process

On July 31, 2008, the Ohio Companies filed both an ESP and MRO with the PUCO. A PUCO decision on the MRO was required by statute within 90 days of the filing and is required on the ESP within 150 days. Under the ESP, new rates would be effective for retail customers on January 1, 2009. Evidentiary hearings concluded on October 31, 2008 and no further hearings are scheduled. The parties are required to submit initial briefs by November 21, 2008, with all reply briefs due by December 12, 2008.

Under the MRO alternative, the Ohio Companies propose to procure generation supply through a CBP. The MRO would be implemented if the ESP is not approved by the PUCO or is changed and not accepted by the Ohio Companies. On September 16, 2008, the PUCO staff filed testimony and evidentiary hearings were held. The PUCO failed to act on October 29, 2008 as required under the statute. The Ohio Companies are unable to predict the outcome of this proceeding.

In July and August 2008, the PUCO staff issued three sets of proposed rules for comment to implement portions of SB221. Written comments and reply comments on the three sets of proposed rules were filed during the third quarter of 2008. Following the comment period, the PUCO considers the input from stakeholders before adopting the final rules. The rules are then subject to review by the Joint Committee on Agency Rule Review, which conducts a 65-day review process. The rules become effective 10 days following the Committee’s review. On September 17, 2008, the PUCO issued a final order adopting the first set of rules. A PUCO order adopting the second set of rules was issued on November 5, 2008.

RCP Fuel Remand

On August 8, 2008, the Ohio Companies submitted a filing to suspend the procedural schedule in their application to recover their 2006-2007 deferred fuel costs and associated carrying charges, as the ESP filing contains a proposal addressing the recovery of these deferred fuel costs. On August 25, 2008, the PUCO ordered that the evidentiary hearing scheduled for September 29, 2008, would be held at a later date. A revised case schedule has yet to be issued.

3

Pennsylvania Legislative Process

On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which becomes 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; and 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.

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, request for proposals, 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.

Penn’s Interim Default Service Supply

On October 21, 2008, Penn held its third RFP to procure default service for residential customers for the period June 2009 through May 2010. A fourth RFP for the remainder of residential customers’ load for the period June 2009 through May 2010 is scheduled for January 2009. The results of the four RFPs will be averaged and adjusted for the line losses, administrative fees and gross receipts tax, and will be reflected in Penn’s new default service rates.

Met-Ed and Penelec Rate Cases

Several parties to the Met-Ed and Penelec 2006 rate case proceeding filed Petitions for Review with the Commonwealth Court of Pennsylvania in 2007, asking the Court to review the PPUC’s determination on several issues including: the recovery of transmission costs (including congestion); the transmission deferral; consolidated tax savings; the requested generation increase; and recovery of universal service costs from only the residential rate class. The Commonwealth Court issued its decision on November 7, 2008, which affirmed the PPUC's January 11, 2007 order in all respects, including the deferral and recovery of transmission and congestion related costs.

Met-Ed and Penelec Prepayment Plan

On September 25, 2008, Met-Ed and Penelec filed a voluntary prepayment plan with the PPUC. The plan offers qualified residential and small business customers the option to gradually phase-in future generation price increases by making modest prepayments during the next two years, before rate caps expire at the end of 2010. Each month, customers who elect to participate would prepay an amount equal to approximately 9.6% of their electric bill. Prepayments would earn 7.5% interest and be applied to customers’ billings in 2011 and 2012. Met-Ed and Penelec requested that the PPUC approve the plan by mid-December 2008.

Solar Renewable Energy

On September 30, 2008, JCP&L filed a proposal in response to an NJBPU directive addressing solar project development in the State of New Jersey. Under the proposal, JCP&L would enter into long-term agreements to buy and sell Solar Renewable Energy Certificates (SREC) to provide a stable basis for financing solar generation projects. An SREC represents the solar energy attributes of one megawatt-hour of generation from a solar generation facility that has been certified by the NJBPU Office of Clean Energy. Under this proposal JCP&L would solicit SRECs to satisfy approximately 60%, 50%, and 40% of the incremental SREC purchases needed in its service territory through 2010, 2011 and 2012, respectively, to meet the Renewable Portfolio Standards adopted by the NJBPU in 2006. A schedule for further NJBPU proceedings has not yet been set.

4

New Jersey Energy Master Plan

On October 22, 2008, the Governor of New Jersey released the details of New Jersey’s EMP, which includes goals to reduce energy consumption by a minimum of 20% by 2020, reduce peak demand by 5,700 MW by 2020, meet 30% of the state's electricity needs with renewable energy by 2020, and examine smart grid technology. The EMP outlines a series of goals and action items to meet set targets, while also continuing to develop the clean energy industry in New Jersey. The Governor will establish a State Energy Council to implement the recommendations outlined in the plan.

Operational Matters

Record Generation Output

FirstEnergy set a new quarterly generation output record of 22.2 million megawatt-hours during the third quarter of 2008, a 3.2% increase over the previous record established in the third quarter of 2006. This generation record reflects a quarterly all-time high for the nuclear fleet.

September Windstorm

On September 14, 2008, the remnants of Hurricane Ike swept through Ohio and western Pennsylvania and produced unexpectedly high winds, reaching nearly 80 mph. More than one million customers of OE, CEI, Penn and Penelec were affected by the windstorm, which produced the largest storm-related outage in the history of any of those companies. Storm expenses totaled approximately $30 million, of which $19 million was recognized as capital and $11 million as O&M expense.  

FIRSTENERGY’S BUSINESS

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

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

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

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

5

RESULTS OF OPERATIONS

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

	Three Months Ended September 30,							Nine Months Ended September 30,
						Increase							Increase
	2008		2007			(Decrease)		2008		2007			(Decrease)
	(In millions, except per share data)
Net Income
By Business Segment:
Energy delivery services	$	283	$	269		$	14	$	655	$	695		$	(40	)
Competitive energy services		164		148			16		317		388			(71	)
Ohio transitional generation services		19		16			3		62		69			(7	)
Other and reconciling adjustments*		5		(20	)		25		(24)		(111	)		87
Total	$	471	$	413		$	58	$	1,010	$	1,041		$	(31	)
Basic Earnings Per Share	$	1.55	$	1.36		$	0.19	$	3.32	$	3.39		$	(0.07	)
Diluted Earnings Per Share	$	1.54	$	1.34		$	0.20	$	3.29	$	3.35		$	(0.06	)

* Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, and elimination of intersegment transactions.

Summary of Results of Operations – Third Quarter 2008 Compared with Third Quarter 2007

Financial results for FirstEnergy's major business segments in the third quarter of 2008 and 2007 were as follows:

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
Third Quarter 2008 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	2,487		$	381		$	781		$	-		$	3,649
Other		170			79			32			(26	)		255
Internal		-			786			-			(786	)		-
Total Revenues		2,657			1,246			813			(812	)		3,904
Expenses:
Fuel		-			356			-			-			356
Purchased power		1,248			221			623			(786	)		1,306
Other operating expenses		430			285			110			(31	)		794
Provision for depreciation		99			67			-			2			168
Amortization of regulatory assets		263			-			28			-			291
Deferral of new regulatory assets		(76	)		-			18			-			(58	)
General taxes		169			26			1			5			201
Total Expenses		2,133			955			780			(810	)		3,058
Operating Income		524			291			33			(2	)		846
Other Income (Expense):
Investment income		48			13			1			(22	)		40
Interest expense		(102	)		(44	)		(1	)		(45	)		(192	)
Capitalized interest		1			13			-			1			15
Total Other Expense		(53	)		(18	)		-			(66	)		(137	)
Income Before Income Taxes		471			273			33			(68	)		709
Income taxes		188			109			14			(73	)		238
Net Income	$	283		$	164		$	19		$	5		$	471

6

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
Third Quarter 2007 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	2,340		$	338		$	716		$	-		$	3,394
Other		180			32			7			28			247
Internal		-			806			-			(806	)		-
Total Revenues		2,520			1,176			723			(778	)		3,641
Expenses:
Fuel		2			325			-			-			327
Purchased power		1,114			229			631			(806	)		1,168
Other operating expenses		436			264			80			(24	)		756
Provision for depreciation		102			51			-			9			162
Amortization of regulatory assets		279			-			9			-			288
Deferral of new regulatory assets		(82	)		-			(25	)		-			(107	)
General taxes		166			26			1			4			197
Total Expenses		2,017			895			696			(817	)		2,791
Operating Income		503			281			27			39			850
Other Income (Expense):
Investment income		58			5			-			(33	)		30
Interest expense		(120	)		(44	)		-			(39	)		(203	)
Capitalized interest		3			5			-			1			9
Total Other Expense		(59	)		(34	)		-			(71	)		(164	)
Income Before Income Taxes		444			247			27			(32	)		686
Income taxes		175			99			11			(12	)		273
Net Income	$	269		$	148		$	16		$	(20	)	$	413
Changes Between Third Quarter 2008 and
Third Quarter 2007 Financial Results
Increase (Decrease)
Revenues:
External
Electric	$	147		$	43		$	65		$	-		$	255
Other		(10	)		47			25			(54	)		8
Internal		-			(20	)		-			20			-
Total Revenues		137			70			90			(34	)		263
Expenses:
Fuel		(2	)		31			-			-			29
Purchased power		134			(8	)		(8	)		20			138
Other operating expenses		(6	)		21			30			(7	)		38
Provision for depreciation		(3	)		16			-			(7	)		6
Amortization of regulatory assets		(16	)		-			19			-			3
Deferral of new regulatory assets		6			-			43			-			49
General taxes		3			-			-			1			4
Total Expenses		116			60			84			7			267
Operating Income		21			10			6			(41	)		(4	)
Other Income (Expense):
Investment income		(10	)		8			1			11			10
Interest expense		18			-			(1	)		(6	)		11
Capitalized interest		(2	)		8			-			-			6
Total Other Expense		6			16			-			5			27
Income Before Income Taxes		27			26			6			(36	)		23
Income taxes		13			10			3			(61	)		(35	)
Net Income	$	14		$	16		$	3		$	25		$	58

7

Energy Delivery Services – Third Quarter 2008 Compared with Third Quarter 2007

Net income increased $14 million to $283 million in the third quarter of 2008 compared to $269 million in the third quarter of 2007, primarily due to increased revenues partially offset by higher purchased power costs.

Revenues –

The increase in total revenues resulted from the following sources:

	Three Months
	Ended September 30,				Increase
Revenues by Type of Service	2008		2007		(Decrease)
	(In millions)
Distribution services	$	1,100	$	1,104	$	(4	)
Generation sales:
Retail		986		942		44
Wholesale		286		207		79
Total generation sales		1,272		1,149		123
Transmission		241		219		22
Other		44		48		(4	)
Total Revenues	$	2,657	$	2,520	$	137

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

Electric Distribution KWH Deliveries
Residential	(1.9)	%
Commercial	(1.1)	%
Industrial	(4.1)	%
Total Distribution KWH Deliveries	(2.3)	%

The decrease in electric distribution deliveries to residential and commercial customers was primarily due to reduced weather-related usage during the third quarter of 2008 compared to the same period of 2007, as cooling degree days decreased 8.1%. In the industrial sector, a decrease in deliveries to automotive and related manufacturers (23%) and refining customers (15%) was partially offset by an increase in usage by steel customers (4%). The reduction in distribution sales volume was partially offset by an increase in unit prices from the previous year.

The following table summarizes the price and volume factors contributing to the $123 million increase in generation revenues in the third quarter of 2008 compared to the third quarter of 2007:

Sources of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 1.9 % decrease in sales volumes	$	(18	)
Change in prices		62
		44
Wholesale:
Effect of 2.4% decrease in sales volumes		(5	)
Change in prices		84
		79
Net Increase in Generation Revenues	$	123

The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in Penn’s, Penelec’s and JCP&L’s service territories and the weather-related impacts described above. The increase in retail generation prices during the third quarter of 2008 was due to higher generation rates for JCP&L resulting from the New Jersey BGS auction process and an increase in NUGC rates authorized by the NJBPU. The increase in wholesale prices reflected higher spot market prices for PJM market participants.

8

Transmission revenues increased $22 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the annual update to their TSC riders, which became effective June 1, 2008. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred with no material effect on current period earnings (see Outlook – State Regulatory Matters – Pennsylvania).

Expenses –

The increases in revenues discussed above were offset by a $116 million increase in expenses due to the following:

· Purchased power costs were $134million higher in the third quarter of 2008 due to higher unit costs and a decrease in the amount of NUG costs deferred. The increased unit costs reflected the effect of higher JCP&L costs resulting from the BGS auction process. JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. The following table summarizes the sources of changes in purchased power costs:

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	146
Change due to decreased volumes		(45	)
		101
Purchases from FES:
Change due to decreased unit costs		(6	)
Change due to decreased volumes		(10	)
		(16	)
Decrease in NUG costs deferred		49
Net Increase in Purchased Power Costs	$	134

· Other operating expenses decreased $6 million due primarily to the net effects of the following:

-   an increase in storm-related costs (including labor) of $9 million;

-   an increase in other labor expenses of $3 million primarily due to increased hiring since the third quarter of 2007 as a result of the segment’s workforce initiatives;

-   a $7 million increase in costs allocated to capital projects;

-   reduced vegetation management expenses of $5 million;  and

-   a $4million decrease in uncollectible expense.

· Amortization of regulatory assets decreased by $16 million due primarily to the full recovery of certain regulatory assets since the third quarter of 2007.

· The deferral of new regulatory assets during the third quarter of 2008 was $6 million lower primarily due to a reduction in the amount of deferred distribution costs.

                ·   Depreciation expense decreased $3million due to a change in estimate for the asset retirement obligation for OE’s retired Toronto and Gorge plants.

                ·   General taxes increased $3 million due to higher gross receipts and property taxes.

9

Other Expense –

Other expense decreased $6million in the third quarter of 2008 primarily due to lower interest expense (net of capitalized interest) of $16million due to redemptions of pollution control notes and term notes. Lower investment income of $10million, resulting from the repayment of notes receivable from affiliates since the third quarter of 2007, partially offset the interest expense reduction.

Competitive Energy Services – Third Quarter 2008 Compared with Third Quarter 2007

Net income for this segment was $164million in the third quarter of 2008 compared to $148 million in the same period in 2007. The $16 million increase in net income reflects an increase in gross generation margin and investment income partially offset by higher operating costs.

Revenues –

Total revenues increased $70million in the third quarter of 2008 due to higher non-affiliated generation sales and transmission revenues, partially offset by reduced volumes on affiliated generation sales.

The net increase in total revenues resulted from the following sources:

	Three Months Ended
	September 30,				Increase
Revenues By Type of Service	2008		2007		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	171	$	189	$	(18	)
Wholesale		210		149		61
Total Non-Affiliated Generation Sales		381		338		43
Affiliated Generation Sales		786		806		(20	)
Transmission		47		26		21
Other		32		6		26
Total Revenues	$	1,246	$	1,176	$	70

The lower retail revenues resulted from decreased sales in the PJM market due primarily to lower contract renewals for commercial and industrial customers. Higher non-affiliated wholesale revenues resulted from the effect of increased generation available for sale to that market as total generation output increased by 6.4% from the third quarter of 2007. An increase in prices for non-affiliated wholesale sales, reflecting higher capacity prices, also contributed to the revenue increase.

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

Source of Change in Non-Affiliated Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 14.2% decrease in sales volumes	$	(27	)
Change in prices		9
		(18	)
Wholesale:
Effect of 28.8% increase in sales volumes		43
Change in prices		18
		61
Net Increase in Non-Affiliated Generation Revenues	$	43

10

Source of Change in Affiliated Generation Revenues	Increase (Decrease)
	(In millions)
Ohio Companies:
Effect of 3.6% decrease in sales volumes	$	(22	)
Change in prices		19
		(3	)
Pennsylvania Companies:
Effect of 5.9% decrease in sales volumes		(11	)
Change in prices		(6	)
		(17	)
Net Decrease in Affiliated Generation Revenues	$	(20	)

The decreased affiliated company generation revenues were due to reduced volumes partially offset by higher unit prices for the Ohio Companies. The higher unit prices reflected increases in the Ohio Companies’ retail generation rates. The reduction in PSA sales volume to the Ohio and Pennsylvania Companies was due to the milder weather and industrial sales changes discussed above and reduced default service requirements in Penn’s service territory as a result of its RFP process (see Outlook – State Regulatory Matters – Pennsylvania).

Transmission revenues increased $21 million due primarily to an increase in transmission prices in the MISO and PJM markets. Other revenues increased by $26 million due to NGC’s purchase of certain lessor equity interests in the sale and leaseback of Perry and Beaver Valley Unit 2 that continue to be leased to OE and TE.

Expenses -

Total expenses increased $60 million in the third quarter of 2008 due to the following factors:

       ·   Fossil fuel costs increased $50 million due to higher unit prices and increased generation volumes. The increased unit prices primarily reflect higher western coal transportation costs (including surcharges for increased diesel fuel prices) in the third quarter of 2008. The increase in fossil fuel costs was partially offset by a $25 million adjustment resulting from the annual coal inventory that reduced expense. Nuclear fuel expense increased $6 million due to increased generation;

· Purchased power costs decreased $8 million due to reduced volume requirements partially offset by higher market prices;

       ·   Other operating expenses were $21 million higher due primarily to a $13 million charge associated with a cancelled fossil project, an increase in nuclear operating costs of $5 million and a $5 million increase in uncollectible expense, partially offset by a $5 million reduction in transmission expense.

· Higher depreciation expense of $16 million was due to the assignment of the Bruce Mansfield Plant leasehold interests to FGCO and NGC’s purchase of certain lessor equity interests in the sale and leaseback of Perry and Beaver Valley Unit 2.

Other Expense –

Total other expense in the third quarter of 2008 was $16million lower than the third quarter of 2007, primarily due to a $9 million increase in net earnings from nuclear decommissioning trust investments and higher capitalized interest of $8 million due to a higher level of fossil capital projects in progress.

Ohio Transitional Generation Services – Third Quarter 2008 Compared with Third Quarter 2007

Net income for this segment increased to $19million in the third quarter of 2008 from $16 million in the same period of 2007. Higher generation revenues were partially offset by higher operating expenses and lower deferrals of new regulatory assets.

11

Revenues –

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

	Three Months Ended
	September 30,
Revenues by Type of Service	2008		2007		Increase
	(In millions)
Generation sales:
Retail	$	675	$	622	$	53
Wholesale		4		3		1
Total generation sales		679		625		54
Transmission		134		98		36
Total Revenues	$	813	$	723	$	90

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

Source of Change in Retail Generation Revenues	Increase (Decrease)
	(In millions)
Effect of 3.1% decrease in sales volumes	$	(19	)
Change in prices		72
Total Increase in Retail Generation Revenues	$	53

The decrease in generation sales volume was primarily due to lower weather-related usage in the third quarter of 2008 compared to the same period of 2007, partially offset by reduced customer shopping. In the industrial sector, a decrease in generation sales to automotive and related manufacturers (23%) and refining customers (15%) was partially offset by an increase in usage by steel customers (2%). The percentage of generation services provided by alternative suppliers to total sales delivered by the Ohio Companies in their service areas decreased to 15.2% in the third quarter of 2008 from 15.5% in the same period in 2007. Average prices increased primarily due to an increase in the Ohio Companies’ fuel cost recovery rider that became effective in January 2008.

Increased transmission revenue resulted from a PUCO-approved transmission tariff increase that became effective July 1, 2008, and higher MISO transmission revenue.

Expenses -

Purchased power costs were $8million lower in the third quarter of 2008 due primarily to reduced volume requirements. The factors contributing to the net decrease are summarized in the following table:

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to decreased unit costs	$	(1	)
Change due to decreased volumes		(3	)
		(4	)
Purchases from FES:
Change due to increased unit costs		19
Change due to decreased volumes		(23	)
		(4	)
Net Decrease in Purchased Power Costs	$	(8	)

The decrease in purchase volumes from FES was due to the lower retail generation sales requirements described above. The higher unit costs reflect the increases in the Ohio Companies’ retail generation rates, as provided for under the PSA with FES.

Other operating expenses increased $30 million due primarily to higher MISO transmission-related expenses. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.

12

The deferral of new regulatory assets decreased by $43 million and the amortization of regulatory assets increased $19 million in the third quarter of 2008 as compared to the same period in 2007. MISO transmission deferrals and RCP fuel deferrals each decreased as more transmission and generation costs were recovered from customers through PUCO-approved riders.

Other – Third Quarter 2008 Compared with Third Quarter 2007

Financial results from other operating segments and reconciling items resulted in a $25 million increase in FirstEnergy’s net income in the third quarter of 2008 compared to the same period in 2007. The increase resulted primarily from income tax benefits associated with the settlement of tax positions taken on federal returns in prior years, and from lower taxes payable upon filing the 2007 federal income tax return in 2008 compared to the amount initially estimated last year. The income tax benefits were partially offset by the absence of the gain from the sale of First Communications ($13 million, net of taxes) in 2007.

Summary of Results of Operations – First Nine Months of 2008 Compared with the First Nine Months of 2007

Financial results for FirstEnergy's major business segments in the first nine months of 2008 and 2007 were as follows:

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Nine Months 2008 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	6,567		$	994		$	2,142		$	-		$	9,703
Other		484			170			61			8			723
Internal		-			2,266			-			(2,266	)		-
Total Revenues		7,051			3,430			2,203			(2,258	)		10,426
Expenses:
Fuel		1			999			-			-			1,000
Purchased power		3,228			648			1,766			(2,266	)		3,376
Other operating expenses		1,288			906			268			(87	)		2,375
Provision for depreciation		309			179			-			12			500
Amortization of regulatory assets		747			-			48			-			795
Deferral of new regulatory assets		(274	)		-			13			-			(261	)
General taxes		491			82			4			19			596
Total Expenses		5,790			2,814			2,099			(2,322	)		8,381
Operating Income		1,261			616			104			64			2,045
Other Income (Expense):
Investment income		133			(1	)		1			(60	)		73
Interest expense		(305	)		(116	)		(1	)		(137	)		(559	)
Capitalized interest		2			30			-			4			36
Total Other Expense		(170	)		(87	)		-			(193	)		(450	)
Income Before Income Taxes		1,091			529			104			(129	)		1,595
Income taxes		436			212			42			(105	)		585
Net Income	$	655		$	317		$	62		$	(24	)	$	1,010

13

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Nine Months 2007 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	6,148		$	973		$	1,942		$	-		$	9,063
Other		507			116			26			11			660
Internal		-			2,210			-			(2,210	)		-
Total Revenues		6,655			3,299			1,968			(2,199	)		9,723
Expenses:
Fuel		4			883			-			-			887
Purchased power		2,834			578			1,712			(2,210	)		2,914
Other operating expenses		1,255			839			218			(57	)		2,255
Provision for depreciation		301			153			-			23			477
Amortization of regulatory assets		765			-			20			-			785
Deferral of new regulatory assets		(299	)		-			(100	)		-			(399	)
General taxes		486			81			3			19			589
Total Expenses		5,346			2,534			1,853			(2,225	)		7,508
Operating Income		1,309			765			115			26			2,215
Other Income (Expense):
Investment income		190			13			1			(111	)		93
Interest expense		(347	)		(144	)		(1	)		(101	)		(593	)
Capitalized interest		7			13			-			1			21
Total Other Expense		(150	)		(118	)		-			(211	)		(479	)
Income Before Income Taxes		1,159			647			115			(185	)		1,736
Income taxes		464			259			46			(74	)		695
Net Income	$	695		$	388		$	69		$	(111	)	$	1,041
Changes Between First Nine Months 2008
and First Nine Months 2007
Financial Results Increase (Decrease)
Revenues:
External
Electric	$	419		$	21		$	200		$	-		$	640
Other		(23	)		54			35			(3	)		63
Internal		-			56			-			(56	)		-
Total Revenues		396			131			235			(59	)		703
Expenses:
Fuel		(3	)		116			-			-			113
Purchased power		394			70			54			(56	)		462
Other operating expenses		33			67			50			(30	)		120
Provision for depreciation		8			26			-			(11	)		23
Amortization of regulatory assets		(18	)		-			28			-			10
Deferral of new regulatory assets		25			-			113			-			138
General taxes		5			1			1			-			7
Total Expenses		444			280			246			(97	)		873
Operating Income		(48	)		(149	)		(11	)		38			(170	)
Other Income (Expense):
Investment income		(57	)		(14	)		-			51			(20	)
Interest expense		42			28			-			(36	)		34
Capitalized interest		(5	)		17			-			3			15
Total Other Expense		(20	)		31			-			18			29
Income Before Income Taxes		(68	)		(118	)		(11	)		56			(141	)
Income taxes		(28	)		(47	)		(4	)		(31	)		(110	)
Net Income	$	(40	)	$	(71	)	$	(7	)	$	87		$	(31	)

14

Energy Delivery Services – First Nine Months of 2008 Compared to First Nine Months of 2007

Net income decreased $40 million to $655 million in the first nine months of 2008 compared to $695 million in the first nine months of 2007, primarily due to increased operating expenses and lower investment income partially offset by higher revenues.

Revenues –

The increase in total revenues resulted from the following sources:

	Nine Months Ended
	September 30,				Increase
Revenues by Type of Service	2008		2007		(Decrease)
	(In millions)
Distribution services	$	2,974	$	2,996	$	(22	)
Generation sales:
Retail		2,548		2,417		131
Wholesale		758		489		269
Total generation sales		3,306		2,906		400
Transmission		633		595		38
Other		138		158		(20	)
Total Revenues	$	7,051	$	6,655	$	396

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

Electric Distribution KWH Deliveries
Residential	(1.3)	%
Commercial	(0.5)	%
Industrial	(1.8)	%
Total Distribution KWH Deliveries	(1.2)	%

The decrease in electric distribution deliveries to residential and commercial customers was primarily due to lower weather-related usage during the first nine months of 2008 compared to the same period of 2007, as cooling degree days decreased by 9.0% and heating degree days decreased by 2.6%. In the industrial sector, a decrease in deliveries to automotive and related manufacturers (16%) and refining customers (2%) was partially offset by an increase in usage by steel customers (5%).

The following table summarizes the price and volume factors contributing to the $400 million increase in generation revenues in the first nine months of 2008 compared to the same period of 2007:

	Increase
Sources of Change in Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 2.2% decrease in sales volumes	$	(54	)
Change in prices		185
		131
Wholesale:
Effect of 2.8% increase in sales volumes		14
Change in prices		255
		269
Net Increase in Generation Revenues	$	400

The decrease in retail generation sales volumes reflected an increase in customer shopping in Penn’s, Penelec’s, and JCP&L’s service territories and the weather-related impacts described above. The increase in retail generation prices during the first nine months of 2008 was due to higher generation rates for JCP&L resulting from the New Jersey BGS auction process and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market. The increase in wholesale prices reflected higher spot market prices for PJM market participants.

Transmission revenues increased $38 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of transmission cost recovery and the annual update to their TSC riders, which became effective June 1, 2008. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred with no material effect on current period earnings (see Outlook – State Regulatory Matters – Pennsylvania).

15

Expenses –

The net increases in revenues discussed above were more than offset by a $444 million increase in expenses due to the following:

· Purchased power costs were $394million higher in the first nine months of 2008 due to higher unit costs and a decrease in the amount of NUG costs deferred. The increased unit costs primarily reflected the effect of higher JCP&L costs resulting from the BGS auction process. JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. The following table summarizes the sources of changes in purchased power costs:

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	369
Change due to decreased volumes		(83	)
		286
Purchases from FES:
Change due to decreased unit costs		(12	)
Change due to decreased volumes		(1	)
		(13	)
Decrease in NUG costs deferred		121
Net Increase in Purchased Power Costs	$	394

· Other operating expenses increased $33million due to the net effects of:

-   an increase of $17million for costs (including labor) associated with three major storms experienced in FirstEnergy’s service territories in the first nine months of 2008.

-   an increase in other labor expenses of $19million primarily due to an increase in the number of employees in the first nine months of 2008 compared to 2007 as a result of the segment’s workforce initiatives.

· Amortization of regulatory assets decreased $18 million due primarily to the complete recovery of certain regulatory assets for JCP&L since the third quarter of 2007.

· The deferral of new regulatory assets during the first nine months of 2008 was $25 million lower primarily due to the absence of the one-time deferral in 2007 of decommissioning costs related to the Saxton nuclear research facility.

     ·   Higher depreciation expense of $8 million resulted from additional capital projects placed in service since the third quarter of 2007.

      ·   General taxes increased $5 million due to higher gross receipts and property taxes.

Other Expense –

Other expense increased $20 million in the first nine months of 2008 compared to 2007 primarily due to lower investment income of $57million, resulting primarily from the repayment of notes receivable from affiliates since the third quarter of 2007, partially offset by lower interest expense (net of capitalized interest) of $37 million.

Competitive Energy Services – First Nine Months of 2008 Compared to First Nine Months of 2007

Net income for this segment was $317 million in the first nine months of 2008 compared to $388 million in the same period in 2007. The $71 million reduction in net income reflects a decrease in gross generation margin and higher other operating costs, which were partially offset by lower interest expense.

16

Revenues –

Total revenues increased $131million in the first nine months of 2008 compared to the same period in 2007. This increase primarily resulted from higher unit prices on affiliated generation sales to the Ohio Companies and increased non-affiliated wholesale sales, partially offset by lower retail sales.

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

	Nine Months Ended
	September 30,				Increase
Revenues by Type of Service	2008		2007		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	485	$	547	$	(62	)
Wholesale		509		426		83
Total Non-Affiliated Generation Sales		994		973		21
Affiliated Generation Sales		2,266		2,210		56
Transmission		113		71		42
Other		57		45		12
Total Revenues	$	3,430	$	3,299	$	131

The lower retail revenues resulted from decreased sales in the PJM market, partially offset by increased sales in the MISO market. The decrease in PJM retail sales is primarily the result of lower contract renewals for commercial and industrial customers. The increase in MISO retail sales is primarily the result of capturing more shopping customers in Penn’s service territory, partially offset by lower customer usage. Higher non-affiliated wholesale revenues resulted from higher capacity prices and increased sales volumes in PJM, partially offset by decreased sales volumes in MISO.

The increased affiliated company generation revenues were due to higher unit prices for the Ohio Companies partially offset by lower unit prices for the Pennsylvania Companies and decreased sales volumes to all affiliates. The higher unit prices reflected increases in the Ohio Companies’ retail generation rates. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the overall price to decline. The reduction in PSA sales volume to the Ohio and Pennsylvania Companies was due to the milder weather and industrial sales changes discussed above and reduced default service requirements in Penn’s service territory as a result of its RFP process (see Outlook – State Regulatory Matters – Pennsylvania).

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

	Increase
Source of Change in Non-Affiliated Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 13.2% decrease in sales volumes	$	(73	)
Change in prices		11
		(62	)
Wholesale:
Effect of 4.6% increase in sales volumes		19
Change in prices		64
		83
Net Increase in Non-Affiliated Generation Revenues	$	21
	Increase
Source of Change in Affiliated Generation Revenues	(Decrease)
	(In millions)
Ohio Companies:
Effect of 1.7% decrease in sales volumes	$	(28	)
Change in prices		97
		69
Pennsylvania Companies:
Effect of 0.2% decrease in sales volumes		(1	)
Change in prices		(12	)
		(13	)
Net Increase in Affiliated Generation Revenues	$	56

Transmission revenues increased $42 million due primarily to higher transmission rates in MISO and PJM.

17

Expenses -

Total expenses increased $280 million in the first nine months of 2008 due to the following factors:

       ·   Fossil fuel costs increased $133 million due to higher unit prices ($135 million) partially offset by lower generation volume ($2 million). The increased unit prices primarily reflect higher western coal transportation costs, increased rates for existing eastern coal contracts and emission allowance costs in the first nine months of 2008. The increase in fossil fuel costs was partially offset by a $25 million adjustment resulting from the annual coal inventory that reduced expense. Nuclear fuel expense was $8 million higher as nuclear generation increased in the first nine months of 2008.

· Purchased power costs increased $70 million due primarily to higher spot market prices, partially offset by reduced volume requirements.

· Nuclear operating costs increased $21 million in the first nine months of 2008 due to an additional refueling outage in 2008 compared with the 2007 period.

       ·   Fossil operating costs were $20 million higher due to a cancelled fossil project ($13 million), planned maintenance outages in 2008, employee benefits and reduced gains from emission allowance sales.

       ·   Other operating expenses increased $26 million due primarily to the assignment of CEI’s and TE’s leasehold interests in the Bruce Mansfield Plant to FGCO in the fourth quarter of 2007 ($26 million) and higher employee benefit costs during the first nine months of 2008 ($14 million), partially offset by lower transmission expense ($16 million).

· Higher depreciation expenses of $26 million were due to the assignment of the Bruce Mansfield Plant leasehold interests to FGCO and NGC’s purchase of certain lessor equity interests in the sale and leaseback of Perry and Beaver Valley Unit 2.

       ·   Higher general taxes of $1 million resulted from higher property taxes.

Other Expense –

Total other expense in the first nine months of 2008 was $31million lower than the first nine months of 2007, principally due to a decline in interest expense (net of capitalized interest) of $45 million from the repayment of notes payable to affiliates since the third quarter of 2007, partially offset by a $14 million decrease in net earnings from nuclear decommissioning trust investments due primarily to securities impairments resulting from market declines during the first nine months of 2008.

Ohio Transitional Generation Services – First Nine Months of 2008 Compared to First Nine Months of 2007

Net income for this segment decreased to $62million in the first nine months of 2008 from $69 million in the same period of 2007. Higher operating expenses, primarily for purchased power, and a decrease in the deferral of new regulatory assets were partially offset by higher generation revenues.

Revenues –

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

	Nine Months Ended
	September 30
Revenues by Type of Service	2008		2007		Increase
	(In millions)
Generation sales:
Retail	$	1,868	$	1,712	$	156
Wholesale		9		7		2
Total generation sales		1,877		1,719		158
Transmission		319		248		71
Other		7		1		6
Total Revenues	$	2,203	$	1,968	$	235

18

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

Source of Change in Generation Revenues	Increase
	(In millions)
Retail:
Effect of 1.4% decrease in sales volumes	$	(24	)
Change in prices		180
Total Increase in Retail Generation Revenues	$	156

The decrease in generation sales volume in the first nine months of 2008 was primarily due to milder weather and reduced customer shopping. Cooling degree days in OE’s, CEI’s and TE’s service territories for the first nine months of 2008 decreased by 23.3%, 7.3% and 15.0%, respectively, while heating degree days were relatively unchanged from the previous year. In the industrial sector, a decrease in generation sales to automotive and related manufacturers (16%) and refining customers (2%) was partially offset by an increase in usage by steel customers (1%). The percentage of generation services provided by alternative suppliers to total sales delivered by the Ohio Companies in their service areas decreased to 14.6% in the first nine months of 2008 from 15.1% in the same period in 2007. Average prices increased primarily due to an increase in the Ohio Companies’ fuel cost recovery riders that became effective in January 2008.

Increased transmission revenue resulted from PUCO-approved transmission tariff increases that became effective July 1, 2007 and July 1, 2008. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.

Expenses -

Purchased power costs were $54 million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the net increase are summarized in the following table:

	Increase
Source of Change in Purchased Power	(Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to decreased unit costs	$	(3	)
Change due to decreased volumes		(13	)
		(16	)
Purchases from FES:
Change due to increased unit costs		98
Change due to decreased volumes		(28	)
		70
Net Increase in Purchased Power Costs	$	54

The higher unit costs reflect the increases in the Ohio Companies’ retail generation rates, as provided for under the PSA with FES. The decrease in purchase volumes from FES was due to the lower retail generation sales requirements described above.

Other operating expenses increased $50 million due primarily to higher net costs associated with the Ohio Companies’ generation leasehold interests and increased MISO transmission-related expenses. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.

The deferral of new regulatory assets decreased by $113 million and the amortization of regulatory assets increased $28 million in the first nine months of 2008 as compared to the same period in 2007. MISO transmission deferrals and RCP fuel deferrals decreased as more transmission and generation costs were recovered from customers through PUCO-approved riders.

Other – First Nine Months of 2008 Compared to First Nine Months of 2007

Financial results from other operating segments and reconciling items resulted in an $87 million increase in FirstEnergy’s net income in the first nine months of 2008 compared to the same period in 2007. The increase resulted primarily from a $19 million after-tax gain from the sale of telecommunication assets, a $10 million after-tax gain from the settlement of litigation relating to formerly-owned international assets, a $33 million reduction of interest expense associated with the revolving credit facility, and income tax adjustments associated with the favorable settlement of tax positions taken on federal returns in prior years. This increase was partially offset by the absence of the gain from the sale of First Communications ($13 million, net of taxes) in 2007.

19

CAPITAL RESOURCES AND LIQUIDITY

Despite recent unprecedented volatility in the capital markets, FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During the remainder of 2008 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

FirstEnergy and certain of its subsidiaries have access to $2.75 billion of short-term financing under a revolving credit facility which expires in August 2012. A total of 25 banks participate in the facility, with no one bank having more than 7.3% of the total commitments. As of September 30, 2008, FirstEnergy had $420 million of bank credit facilities in addition to the $2.75 billion revolving credit facility. On October 8, 2008, FirstEnergy obtained a new $300 million secured term loan facility with Credit Suisse to reinforce its liquidity in light of the unprecedented disruptions in the credit markets. On October 20, 2008, OE issued $300 million of FMBs to fund its capital expenditures and for other general corporate purposes. In addition, an aggregate of $550 million of accounts receivable financing facilities through the Ohio and Pennsylvania Companies may be accessed to meet working capital requirements and for other general corporate purposes. FirstEnergy’s available liquidity as of October 31, 2008, is described in the following table:

Company	Type	Maturity	Commitment	Available
			(In millions)
FirstEnergy(1)	Revolving	Aug. 2012	$2,750	404
FirstEnergy and FES	Revolving	May 2009	300	300
FirstEnergy	Bank lines	Various(2)	120	20
FGCO	Term loan	Oct. 2009(3)	300	300
Ohio and Pennsylvania Companies	A/R financing	Various(4)	550	445
		Subtotal:	$4,020	$1,469
		Cash:	-	456
		Total:	$4,020	$1,925

(1)FirstEnergy Corp. and subsidiary borrowers.

(2)$100 million matures November 30, 2009; $20 million uncommitted line of credit with no maturity date.

(3)Drawn amounts are payable within 30 days and may not be reborrowed.

(4)$370 million matures March 21, 2009; $180 million matures December 19, 2008 with an extension requested

 pending state regulatory approval of replacement facility.

In early October 2008, FirstEnergy took steps to further enhance its liquidity position by negotiating with the banks that have issued irrevocable direct pay LOCs in support of its outstanding variable interest rate PCRBs ($2.1 billion as of September 30, 2008) to extend the respective reimbursement obligations of the applicable FirstEnergy subsidiary obligors in the event that such LOCs are drawn upon. As discussed below, 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. As a result of these negotiations, a total of approximately $902 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.  The LOCs for FirstEnergy’s variable interest rate PCRBs were issued by seven banks, as summarized in the following table:

	Aggregate LOC
	Amount(5)			Reimbursements of
LOC Bank	(In millions)		LOC Termination Date	LOC Draws Due
Barclays Bank(1)	$	149	June 2009	June 2009
Bank of America(1) (2)		101	June 2009	June 2009
The Bank of Nova Scotia(1)		255	Beginning June 2010	Shorter of 6 months or LOC termination date
The Royal Bank of Scotland(1)		131	June 2012	6 months
KeyBank(1) (3)		266	June 2010	6 months
Wachovia Bank		648	March 2009	March 2009
Barclays Bank(4)		528	Beginning December 2010	30 days
PNC Bank		70	Beginning December 2010	5 days
Total	$	2,148

(1)Due dates for reimbursements of LOC draws for these banks were extended in October 2008 from 30

days or less to the dates indicated.

(2)Supported by 2 participating banks, with each having 50% of the total commitment.

(3)Supported by 4 participating banks, with the LOC bank having 62% of the total commitment.

(4)Supported by 17 participating banks, with no one bank having more than 14% of the total commitment.

(5)Includes approximately $22 million of applicable interest coverage.

20

As of September 30, 2008, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($2.4 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debt as of September 30, 2008 included the following:

Currently Payable Long-term Debt
		(In millions)
PCRBs supported by bank LOCs (1)	$	2,126
CEI FMBs (2)		125
CEI secured PCRBs (2)		82
Penelec unsecured notes (3)		100
NGC collateralized lease obligation bonds (4)		37
Sinking fund requirements (5)		39
	$	2,509

(1) Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.

(2) Redeemed in October 2008.

(3) Matures in April 2009.

(4) $4 million payable in the fourth quarter of 2008.

(5) $9 million payable in the fourth quarter of 2008.

Changes in Cash Position

FirstEnergy's primary source of cash required for continuing operations as a holding company is cash from the operations of its subsidiaries. In the first nine months of 2008, FirstEnergy received $748 million of cash dividends from its subsidiaries and paid $503 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by the subsidiaries of FirstEnergy.

During the nine months ended September 30, 2008, net cash provided from operating and financing activities was $1.4 billion and $914 million, respectively and net cash used for investing activities was $2.3 billion. As of September 30, 2008, FirstEnergy had $181 million of cash and cash equivalents compared with $129 million as of December 31, 2007. Cash and cash equivalents consist of unrestricted, highly liquid instruments with an original or remaining maturity of three months or less. As of September 30, 2008, approximately $132 million of cash and cash equivalents consisted of temporary overnight investments. The major sources of changes in these balances are summarized below.

Cash Flows from Operating Activities

FirstEnergy's consolidated net cash from operating activities is provided primarily by its energy delivery services and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $1.4 billion and $1.2 billion in the first nine months of 2008 and 2007, respectively, as summarized in the following table:

	Nine Months Ended
	September 30,
Operating Cash Flows	2008			2007
	(In millions)
Net income	$	1,010		$	1,041
Non-cash charges		1,008			358
Pension trust contribution		-			(300	)
Working capital and other		(590	)		111
	$	1,428		$	1,210

Net cash provided from operating activities increased by $218 million in the first nine months of 2008 compared to the first nine months of 2007 primarily due to the absence of a $300 million pension trust contribution in 2007 and a $650 million increase in non-cash charges, partially offset by a $701 million decrease from working capital and other changes and a $31 million decrease in net income (see Results of Operations above).

21

The increase in non-cash charges is primarily due to lower deferrals of new regulatory assets and purchased power costs and higher deferred income taxes. The deferral of new regulatory assets decreased primarily as a result of the Ohio Companies’ transmission and fuel recovery riders that became effective in July 2007 and January 2008, respectively, and the absence of the deferral of decommissioning costs related to the Saxton nuclear research facility in the first quarter of 2007. Lower deferrals of purchased power costs reflected a decrease in NUG costs deferred. The change in deferred income taxes is primarily due to additional tax depreciation as provided for under the Economic Stimulus Act of 2008, the settlement of tax positions taken on federal returns in prior years, and the absence of deferred income tax impacts related to the Bruce Mansfield Unit 1 sale and leaseback transaction in 2007. The changes in working capital and other primarily resulted from higher fossil fuel inventories and increased tax payments, partially offset by a change in the collection of receivables.

Cash Flows from Financing Activities

In the first nine months of 2008, cash provided from financing activities was $914 million compared to cash used of $1.4 billion in the first nine months of 2007. The increase was due to higher short-term borrowings primarily for capital expenditures for environmental compliance and to fund a number of strategic acquisitions, including the Fremont Plant ($275 million), Signal Peak ($125 million), and the purchase of lessor equity interests in Beaver Valley Unit 2 and Perry ($438 million). The absence of the repurchase of common stock in the first nine months of 2007 also contributed to the increase in the 2008 period. The following table summarizes security issuances and redemptions or repurchases during the nine months ended September 30, 2008, and 2007.

	Nine Months Ended
Securities Issued or	September 30,
Redeemed / Repurchased	2008		2007
	(In millions)
New issues
Pollution control notes	$	611	$	-
Unsecured notes		20		1,100
	$	631	$	1,100
Redemptions / Repurchases
First mortgage bonds	$	1	$	287
Pollution control notes		534		4
Senior secured notes		23		203
Unsecured notes		175		153
Common stock		-		918
	$	733	$	1,565

FirstEnergy had approximately $2.4 billion of short-term indebtedness as of September 30, 2008 compared to approximately $903 million as of December 31, 2007.

As described above, FirstEnergy and its subsidiaries, FES and FGCO entered into a new $300 million secured term loan facility with Credit Suisse in October 2008. 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 a maturity of 30 days from the date of the borrowing. Once repaid, borrowings may not be re-borrowed.

As of September 30, 2008, the Ohio Companies and Penn had the aggregate capability to issue approximately $3.6 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $448 million, $457 million and $120 million, respectively, as of September 30, 2008. On June 19, 2008, FGCO established an FMB indenture. Based upon its net earnings and available bondable property additions as of September 30, 2008, FGCO had the capability to issue $3.1 billion of additional FMB under the terms of that indenture. Met-Ed and Penelec had the capability to issue secured debt of approximately $363 million and $310 million, respectively, under provisions of their senior note indentures as of September 30, 2008.

On September 22, 2008, FirstEnergy and the Utilities filed an automatically effective shelf registration statement with the SEC for an unspecified number and amount of securities to be offered thereon. The shelf registration provides FirstEnergy the flexibility to issue and sell various types of securities, including common stock, preferred stock, debt securities, warrants, share purchase contracts, and share purchase units. The Utilities may utilize the shelf registration statement to offer and sell unsecured, and in some cases, secured debt securities.

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As discussed above, on October 20, 2008, OE issued and sold under the shelf registration statement $300 million of FMBs, comprised of $275 million 8.25% Series of 2008 due 2038 and $25 million 8.25% Series of 2008 due 2018. The net proceeds from this offering will be used to fund capital expenditures and for other general corporate purposes. This issuance reduces OE’s capability to issue additional FMB under the terms of its mortgage indenture described above.

As of September 30, 2008, FirstEnergy’s currently payable long-term debt includes approximately $2.1 billion (FES - $1.9 billion, OE - $156 million, Met-Ed - $29 million and Penelec - - $45 million) of variable interest rate PCRBs, 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 September 2008, FirstEnergy 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 have been tendered by bondholders to the trustee. As of October 31, 2008, $72.5 million of the PCRBs, all of which are backed by Wachovia Bank LOCs, had been tendered and not yet successfully remarketed. Of these, draws on the applicable LOCs were made for $72.4 million, all of which Wachovia honored. The reimbursement agreements between the subsidiary obligors and Wachovia require reimbursement of outstanding LOC draws by March 2009.

FirstEnergy and certain of its subsidiaries are party to a $2.75 billion revolving credit facility (included in the borrowing capability table above). FirstEnergy has the capability 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 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 September 30, 2008:

	Revolving			Regulatory and
	Credit Facility			Other Short-Term
Borrower	Sub-Limit			Debt Limitations
	(In millions)
FirstEnergy	$	2,750		$	-	(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)
FES		1,000			-	(1)
ATSI		-	(4)		50

(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.

 (4)  The borrowing sub-limit for ATSI may be increased up to $100 million by delivering

  notice to the administrative agent that either (i) ATSI has senior unsecured debt

  ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guarantee

  ATSI’s obligations of such borrower under the facility.

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The revolving credit facility described above, combined with $720 million of additional credit facilities ($620 million available as of October 31, 2008) and an aggregate $550 million of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn ($445 million available as of October 31, 2008), are available to provide liquidity to meet working capital requirements and for other general corporate purposes for FirstEnergy and its subsidiaries.

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

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of September 30, 2008, FirstEnergy’s and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy	59.6	%
OE	46.0	%
Penn	19.2	%
CEI	55.8	%
TE	44.5	%
JCP&L	31.0	%
Met-Ed	43.7	%
Penelec	50.1	%
FES	56.6	%

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

FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first nine months of 2008 was 3.13% for the regulated companies’ money pool and 3.09% for the unregulated companies’ money pool.

FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. The following table displays FirstEnergy’s, FES’ and the Utilities’ securities ratings as of November 5, 2008. On August 1, 2008, S&P changed its outlook for FirstEnergy and its subsidiaries from “negative” to “stable.” On November 5, 2008, S&P raised its senior unsecured rating on OE, Penn, CEI and TE to BBB from BBB-. Moody’s outlook for FirstEnergy and its subsidiaries remains “stable.”

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

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Cash Flows from Investing Activities

Net cash flows used in investing activities resulted principally from property additions. Additions for the energy delivery services segment primarily include expenditures related to transmission and distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for the nine months ended September 30, 2008, and 2007 by business segment:

Summary of Cash Flows Provided from	Property
(Used for) Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Nine Months Ended September 30, 2008
Energy delivery services	$	(621	)	$	33		$	(3	)	$	(591	)
Competitive energy services(1)		(1,430	)		(13	)		(121	)		(1,564	)
Other(2)		(106	)		57			(54	)		(103	)
Inter-Segment reconciling items		(20	)		(12	)		-			(32	)
Total	$	(2,177	)	$	65		$	(178	)	$	(2,290	)
Nine Months Ended September 30, 2007
Energy delivery services	$	(609	)	$	6		$	(2	)	$	(605	)
Competitive energy services		(462	)		1,311			2			851
Other		(6	)		(4	)		1			(9	)
Inter-Segment reconciling items		(50	)		(15	)		-			(65	)
Total	$	(1,127	)	$	1,298		$	1		$	172
(1)Other investing activities include approximately $82 million in restricted funds to redeem outstanding debt in the fourth quarter of 2008. (2)Other investing activities include approximately $64 million in cash investments for the equity interest in Signal Peak.

Net cash used for investing activities was $2.3 billion in the first nine months of 2008 compared to net cash provided from investing activities of $172 million in the first nine months of 2007. The change was principally due to a $1.1 billion increase in property additions and the absence of $1.3 billion of proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction in the third quarter of 2007. The increased property additions reflected the acquisitions described above and higher planned air quality control system expenditures in the first nine months of 2008.

During the remaining three months of 2008, capital requirements for property additions and capital leases are expected to be approximately $555 million, including $88 million for nuclear fuel. As of September 30, 2008, FirstEnergy had additional requirements of approximately $138 million for maturing long-term debt during the remainder of 2008, of which $125 million was redeemed in October 2008. These cash requirements are expected to be satisfied from a combination of internal cash, short-term credit arrangements and funds raised in the capital markets.

FirstEnergy's capital spending for the period 2008-2012 is expected to be approximately $7.6 billion (excluding nuclear fuel, the purchase of nuclear sale and leaseback lessor equity interests, and the acquisition of Signal Peak), of which approximately $2.1 billion applies to 2008. Investments for additional nuclear fuel during the 2008-2012 period are estimated to be approximately $1.2 billion, of which about $167 million applies to 2008. During the same periods, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $892 million and $111 million, respectively, as the nuclear fuel is consumed.

While FirstEnergy believes its existing sources of liquidity will continue to be available to meet its anticipated obligations, management is reviewing its 2009 plans to determine what adjustments should be made to operating and capital budgets in response to the economic climate to reduce the need for external sources of capital. Management plans to reassess the economic value of discretionary projects; however, it expects to continue to meet commitments for required capital projects and necessary operational expenditures.Although this process is not yet complete, management expects that FirstEnergy's capital expenditures will be reduced from the levels previously anticipated.

GUARANTEES AND OTHER ASSURANCES

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

As of September 30, 2008, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.2 billion, as summarized below:

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	Maximum
Guarantees and Other Assurances	Exposure
	(In millions)
FirstEnergy Guarantees of Subsidiaries
Energy and Energy-Related Contracts (1)	$	408
LOC (long-term debt) – interest coverage (2)		6
Other (3)		503
		917
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts		86
LOC (long-term debt) – interest coverage (2)		11
FES’ guarantee of FGCO’s sale and leaseback obligations		2,591
		2,688
Surety Bonds		94
LOC (long-term debt) – interest coverage (2)		5
LOC (non-debt) (4)(5)		463
		562
Total Guarantees and Other Assurances	$	4,167

  (1) Issued for open-ended terms, with a 10-day termination right by FirstEnergy.

  (2) Reflects the interest coverage portion of LOCs issued in support of floating-rate PCRBs with various maturities. The principal amount of floating-rate PCRBs of $2.1 billion is reflected as debt on FirstEnergy’s consolidated balance sheets.

  (3) Includes guarantees of $300 million for OVEC obligations and $80 million for nuclear decommissioning funding assurances.

  (4) Includes $38 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility.

  (5) Includes approximately $291 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE.

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

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade to below investment grade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of September 30, 2008, FirstEnergy's maximum exposure under these collateral provisions was $573 million as shown below:

Collateral Provisions	FES		Utilities		Total
	(in millions)
Credit rating downgrade to   below investment grade	$	216	$	293	$	509
Material adverse event		56		8		64
Total	$	272	$	301	$	573

Additionally, stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase the total potential amount to $648 million, consisting of $58 million due to “material adverse event” contractual clauses and $590 million due to a below investment grade credit rating.

FES, through potential participation in utility sponsored competitive power procurement processes (including those of affiliates) or through forward hedging transactions and as a consequence of future power price movements, could be required to post significantly higher collateral to support its power transactions.

26

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

OFF-BALANCE SHEET ARRANGEMENTS

FES and the Ohio Companies have obligations that are not included on FirstEnergy’s Consolidated Balance Sheets related to sale and leaseback arrangements involving the Bruce Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, decreased to $1.8 billion as of September 30, 2008, from $2.3 billion as of December 31, 2007, due primarily to NGC’s purchase of certain lessor equity interests in Perry Unit 1 and Beaver Valley Unit 2 (see Note 9).

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

MARKET RISK INFORMATION

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

Commodity Price Risk

FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The changes in the fair value of commodity derivative contracts related to energy production during the three months and nine months ended September 30, 2008 are summarized in the following table:

	Three Months									Nine Months
Increase (Decrease) in the Fair Value	Ended September 30, 2008									Ended September 30, 2008
of Derivative Contracts	Non-Hedge			Hedge			Total			Non-Hedge			Hedge			Total
	(In millions)
Change in the Fair Value of
Commodity Derivative Contracts:
Outstanding net liability at beginning of period	$	(616	)	$	(37	)	$	(653	)	$	(713	)	$	(26	)	$	(739	)
Additions/change in value of existing contracts		23			33			56			(10	)		9			(1	)
Settled contracts		18			(6	)		12			148			7			155
Outstanding net liability at end of period (1)		(575	)		(10	)		(585	)		(575	)		(10	)		(585	)
Non-commodity Net Assets at End of Period:
Interest rate swaps (2)		-			-			-			-			-			-
Net Liabilities - Derivative Contracts at End of Period	$	(575	)	$	(10	)	$	(585	)	$	(575	)	$	(10	)	$	(585	)
Impact of Changes in Commodity Derivative Contracts(3)
Income Statement effects (pre-tax)	$	(1	)	$	-		$	(1	)	$	-		$	-		$	-
Balance Sheet effects:
Other comprehensive income (pre-tax)	$	-		$	27		$	27		$	-		$	16		$	16
Regulatory assets (net)	$	(42	)	$	-		$	(42	)	$	(138	)	$	-		$	(138	)

(1) Includes $575 million in non-hedge commodity derivative contracts (primarily with NUGs) that are offset by a regulatory asset.

(2) Interest rate swaps are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements below).

(3) Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

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Derivatives are included on the Consolidated Balance Sheet as of September 30, 2008 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	-		$	14		$	14
Other liabilities		-			(26	)		(26	)
Non-Current-
Other deferred charges		28			3			31
Other non-current liabilities		(603	)		(1	)		(604	)
Net liabilities	$	(575	)	$	(10	)	$	(585	)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 5). Sources of information for the valuation of commodity derivative contracts as of September 30, 2008 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2008(1)		2009		2010		2011		2012		Thereafter		Total
	(In millions)
Prices actively quoted(2)	$	(2)	$	(5)	$	(1)	$	-	$	-	$	-	$	(8)
Other external sources(3)		(58)		(182)		(151)		(106)		-		-		(497)
Prices based on models		-		-		-		-		(32)		(48)		(80)
Total(4)	$	(60)	$	(187)	$	(152)	$	(106)	$	(32)	$	(48)	$	(585)

(1)     For the last quarter of 2008.

(2)     Represents exchange traded NYMEX futures and options.

(3)     Primarily represents contracts based on broker and Intercontinental Exchange quotes.

(4)     Includes $575 million in non-hedge commodity derivative contracts (primarily with NUGs) that are offset by a regulatory asset.

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of September 30, 2008. Based on derivative contracts held as of September 30, 2008, an adverse 10% change in commodity prices would decrease net income by approximately $1 million during the next 12 months.

Interest Rate Swap Agreements - Fair Value Hedges

FirstEnergy historically utilized fixed-for-floating interest rate swap agreements as part of its effort to manage interest rate risk associated with its debt portfolio. In order to reduce counterparty exposure and lessen variable debt exposure under the current market conditions, FirstEnergy unwound its remaining interest rate swaps. During the first nine months of 2008, FirstEnergy received $3 million to terminate interest rate swaps with an aggregate notional value of $250 million. As of September 30, 2008, FirstEnergy had no outstanding interest rate swaps hedging the current debt portfolio.

Forward Starting Swap Agreements - Cash Flow Hedges

FirstEnergy utilizes forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 2008 and 2009, and anticipated variable-rate, short-term debt. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury and LIBOR rates between the date of hedge inception and the date of the debt issuance. FirstEnergy considers counterparty credit and nonperformance risk in its hedge assessments and continues to expect the forward-starting swaps to be effective in protecting against the risk of changes in future interest payments. During the first nine months of 2008, FirstEnergy entered into forward swaps with an aggregate notional value of $950 million and terminated forward swaps with an aggregate notional value of $750million. FirstEnergy paid $16 million in cash related to the terminations, $5 million of which was deemed ineffective and recognized in current period earnings. The remaining effective portion will be recognized over the terms of the associated future debt. As of September 30, 2008, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $600 million and an aggregate fair value of $(0.2) million.

28

	September 30, 2008						December 31, 2007
	Notional		Maturity		Fair		Notional		Maturity		Fair
Forward Starting Swaps	Amount		Date		Value		Amount		Date		Value
	(In millions)
Cash flow hedges	$	100		2009	$	-	$	-		2009	$	-
		100		2010		-		-		2010		-
		-		2015		-		25		2015		(1	)
		350		2018		-		325		2018		(1	)
		50		2020		-		50		2020		(1	)
	$	600			$	-	$	400			$	(3	)

Equity Price Risk

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its subsidiaries’ employees. The plans provide defined benefits based on years of service and compensation levels. The benefit plan assets and obligations of FirstEnergy are remeasured annually using a December 31 measurement date. Reductions in plan assets from investment losses will result in a decrease to the plans’ funded status and a decrease in common stockholders’ equity upon actuarial revaluation of the plan on January 1, 2009.

As of December 31, 2007, FirstEnergy’s pension plan was overfunded, and, therefore, FirstEnergy will not be required to make any contributions in 2009 for the 2008 plan year. The overall actual investment return as of October 31, 2008 was a loss of 25.4% compared to an assumed 9% positive return. Based on an 8% discount rate assumption, if the ultimate return for 2008 was to remain at a loss of 25.4%, 2009 pre-tax net periodic pension expense would be approximately $145 million, an increase of approximately $180 million compared to the year 2008. If the ultimate return for 2008 were to remain at a loss of 25.4%, FirstEnergy would not be required to make contributions in 2010. However, if the assets were to decline an additional 1% from October 31, 2008 through the end of 2008, contributions of approximately $65 million would be required in 2010.

This information does not consider any actions management may take to mitigate the impact of the asset return shortfalls, including changes in the amount and timing of future contributions. The actuarial assumptions used in the determination of pension and postretirement benefit costs are interrelated and changes in other assumptions could have the impact of offsetting all or a portion of the potential increase in benefit costs set forth above.

Nuclear decommissioning trust funds have been established to satisfy NGC’s and the Utilities’ nuclear decommissioning obligations. As of September 30, 2008, approximately 47% of the funds were invested in equity securities and 53% were invested in fixed income securities, with limitations related to concentration and investment grade ratings. The equity securities are carried at their market value of approximately $879 million as of September 30, 2008. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $88 million reduction in fair value as of September 30, 2008. The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses 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. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts. Nuclear decommissioning trust securities impairments totaled $63 million in the first nine months of 2008. FirstEnergy does not expect to make additional cash contributions to the nuclear decommissioning trusts in 2009, other than the required annual TMI-2 trust contribution that is collected through customer rates. However, should the trust funds continue to experience declines in market value, FirstEnergy may be required to take measures, such as providing financial guarantees through letters of credit or parental guarantees or making additional contributions to the trusts to ensure that the trusts are adequately funded and meet minimum NRC funding requirements.

CREDIT RISK

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

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB+ (S&P). As of September 30, 2008, the largest credit concentration was with JPMorgan Chase, which is currently rated investment grade, representing 10.7% of FirstEnergy’s total approved credit risk. Within FirstEnergy’s unregulated energy subsidiaries, 99% of existing credit, net of collateral and reserve, were with investment-grade counterparties as of September 30, 2008.

29

OUTLOOK

State Regulatory Matters

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 certain 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 and ATSI recognize, as regulatory assets, costs which the FERC, the PUCO, the PPUC and the NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $128 million as of September 30, 2008 (JCP&L - $64 million and Met-Ed - $64 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed. The following table discloses regulatory assets by company:

	September 30,		December 31,		Increase
Regulatory Assets*	2008		2007		(Decrease)
	(In millions)
OE	$	621	$	737	$	(116	)
CEI		796		871		(75	)
TE		145		204		(59	)
JCP&L		1,295		1,596		(301	)
Met-Ed		541		495		46
ATSI		35		42		(7	)
Total	$	3,433	$	3,945	$	(512	)

 * Penelec had net regulatory liabilities of approximately $105 million and $74 million as of September 30, 2008 and December 31, 2007, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

Regulatory assets by source are as follows:

	September 30,			December 31,			Increase
Regulatory Assets By Source	2008			2007			(Decrease)
	(In millions)
Regulatory transition costs	$	1,770		$	2,363		$	(593	)
Customer shopping incentives		447			516			(69	)
Customer receivables for future income taxes		247			295			(48	)
Loss on reacquired debt		52			57			(5	)
Employee postretirement benefits		33			39			(6	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(81	)		(115	)		34
Asset removal costs		(207	)		(183	)		(24	)
MISO/PJM transmission costs		397			340			57
Fuel costs - RCP		213			220			(7	)
Distribution costs - RCP		450			321			129
Other		112			92			20
Total	$	3,433		$	3,945		$	(512	)

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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.

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

In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the 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, ReliabilityFirst scheduled a compliance audit of FirstEnergy’s bulk-power system within the PJM region in October 2008. FirstEnergy currently does not expect any material adverse financial impact as a result of these audits.

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 to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 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 is addressed in the Ohio Companies’ comprehensive ESP filing, as described below. If the recovery of the deferred fuel costs is not resolved in the ESP, or in the event the MRO is implemented, recovery of the deferred fuel costs will be resolved in the proceeding that was instituted with the PUCO on February 8, 2008, as referenced above.

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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. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. 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. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $58 million of interest costs deferred through September 30, 2008 ($0.12 per share of common stock). The Ohio Companies’ electric distribution rate request is addressed in their comprehensive ESP filing, as described below.

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. A utility also may file an MRO in which it would have to prove the following objective market criteria:

·   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;

·   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

·   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 outlines a CBP that would be implemented if the ESP is not approved by the PUCO. Under SB221, a PUCO ruling on the ESP filing is required within 150 days and an MRO decision is required within 90 days. The ESP proposes to phase in new generation rates for customers beginning in 2009 for up to a three-year period and would resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. Major provisions of the ESP include:

·   a phase-in of new generation rates for up to a three-year period, whereby customers would receive a 10% phase-in credit; related costs (expected to approximate $429 million in 2009, $488 million in 2010 and $553 million in 2011) would be deferred for future collection over a period not to exceed 10 years;

·   a reconcilable rider to recover fuel transportation cost surcharges in excess of $30 million in 2009, $20 million in 2010 and $10 million in 2011;

·   generation rate adjustments to recover any increase in fuel costs in 2011 over fuel costs incurred in 2010 for FES’ generation assets used to support the ESP;

·   generation rate adjustments to recover the costs of complying with new requirements for certain renewable energy resources, new taxes and new environmental laws or new interpretations of existing laws that take effect after January 1, 2008 and exceed $50 million during the plan period;

·   an RCP fuel rider to recover the 2006 and 2007 deferred fuel costs and carrying charges (described above) over a period not to exceed 25 years;

·   the resolution of outstanding issues pending in the Ohio Companies’ distribution rate case (described above), including annual electric distribution rate increases of $75 million for OE, $34.5 million for CEI and $40.5 million for TE. The new distribution rates would be effective January 1, 2009, for OE and TE and May 1, 2009 for CEI, with a commitment to maintain distribution rates through 2013. CEI also would be authorized to defer $25 million in distribution-related costs incurred from January 1, 2009, through April 30, 2009;

·   an adjustable delivery service improvement rider, effective January 1, 2009, through December 31, 2013, to ensure the Ohio Companies maintain and improve customer standards for service and reliability;

·   the waiver of RTC charges for CEI’s customers as of January 1, 2009, which would result in CEI’s write-off of approximately $485 million of estimated unrecoverable transition costs ($1.01 per share of common stock);

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·   the continued recovery of transmission costs, including MISO, ancillary services and congestion charges, through an annually adjusted transmission rider; a separate rider will be established to recover costs incurred annually between May 1st and September 30th for capacity purchases required to meet FERC, NERC, MISO and other applicable standards for planning reserve margin requirements in excess of amounts provided by FES as described in the ESP (the separate application for the recovery of these costs was filed on October 17, 2008);

·   a deferred transmission cost recovery rider effective January 1, 2009, through December 31, 2010 to recover transmission costs deferred by the Ohio Companies in 2005 and accumulated carrying charges through December 31, 2008; a deferred distribution cost recovery rider effective January 1, 2011, to recover distribution costs deferred under the RCP, CEI’s additional $25 million of cost deferrals in 2009, line extension deferrals and transition tax deferrals;

·   the deferral of annual storm damage expenses in excess of $13.9 million, certain line extension costs, as well as depreciation, property tax obligations and post in-service carrying charges on energy delivery capital investments for reliability and system efficiency placed in service after December 31, 2008. Effective January 1, 2014, a rider will be established to collect the deferred balance and associated carrying charges over a 10-year period; and

·   a commitment by the Ohio Companies to invest in aggregate at least $1 billion in capital improvements in their energy delivery systems through 2013 and fund $25 million for energy efficiency programs and $25 million for economic development and job retention programs through 2013.

Evidentiary hearings in the ESP case concluded on October 31, 2008 and no further hearings are scheduled. The parties are required to submit initial briefs by November 21, 2008, with all reply briefs due by December 12, 2008.

The Ohio Companies’ MRO filing outlines a CBP for providing retail generation supply if the ESP is not approved by the PUCO or is changed and not accepted by the Ohio Companies. 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. On September 16, 2008, the PUCO staff filed testimony and evidentiary hearings were held. The PUCO failed to act on October 29, 2008 as required under the statute.  The Ohio Companies are unable to predict the outcome of this proceeding.

The Ohio Companies included an interim pricing proposal as part of their ESP filing, if additional time is necessary for final PUCO approval of either the ESP or MRO. FES will be required to obtain FERC authorization to sell electric capacity or energy to the Ohio Companies under the ESP or MRO, unless a waiver is obtained (see FERC Matters).

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. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC. 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.

Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

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The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the Court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. The Commonwealth Court issued its decision on November 7, 2008, which affirmed the PPUC's January 11, 2007 order in all respects, including the deferral and recovery of transmission and congestion related costs.

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 Met-Ed’s and Penelec’s TSC filings.  In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing the company 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 with hearings for both companies scheduled to begin in January 2009. The TSCs include a component for 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 approval from the PPUC of 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. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. As part of the 2008 state budget negotiations, the Alternative Energy Investment Act was enacted 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 8, 2008, House Bill 2200 as amended, was voted out of the full Senate and adopted by the House. On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which becomes 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.

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, request for proposals, 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;

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·   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.

The current legislative session ends on November 30, 2008, and any pending legislation addressing rate mitigation and the expiration of rate caps not enacted by that time must be re-introduced in order to be considered in the next legislative session which begins 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 next year.

On September 25, 2008, Met-Ed and Penelec filed for Commission approval of a Voluntary Prepayment Plan that would provide an opportunity for residential and small commercial customers to pre-pay an amount, which would earn interest at 7.5%, on their monthly electric bills in 2009 and 2010, to be used to reduce electric rates in 2011 and 2012. Met-Ed and Penelec also intend to file a generation procurement plan for 2011 and beyond with the PPUC later this year or early next year. Met-Ed and Penelec requested that the PPUC approve the Plan by mid-December 2008 and are currently awaiting a decision.

New Jersey

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2008, the accumulated deferred cost balance totaled approximately $210 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.

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. 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. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the first half of 2008.

On April 17, 2008, a draft EMP was released for public comment. The final EMP was issued on October 22, 2008 and establishes 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.

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The final EMP will be followed by appropriate legislation and regulation as necessary. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations or those of JCP&L.

FERC Matters

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. 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 could be issued by the FERC by year-end 2008.  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.

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. 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 are due on November 10, 2008. 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.

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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 is pending before the FERC.

MISO Ancillary Services Market and Balancing Area Consolidation

MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. These markets would permit generators to sell, and load-serving entities to purchase, their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. Numerous parties filed requests for rehearing on March 26, 2008. On June 23, 2008, the FERC issued an order granting in part and denying in part rehearing.

On February 29, 2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor ASM and Consolidated Balancing Authority Initiative Verification plan and status and Real-Time Operations ASM Reversion plan. FERC action on this compliance filing remains pending. On March 26, 2008, MISO submitted a tariff filing in compliance with the FERC’s 30-day directives in the February 25 order. Numerous parties submitted comments and protests on April 16, 2008. The FERC issued an order accepting the revisions pending further compliance on June 23, 2008. On April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s 60-day directives in the February 25 order. FERC action on this compliance filing remains pending. On May 23, 2008, MISO submitted its amended Balancing Authority Agreement. On July 21, 2008, the FERC issued an order conditionally accepting the amended Balancing Authority Agreement and requiring a further compliance filing.  On August 19, 2008, MISO submitted its compliance filing to the FERC.  On July 25, 2008, MISO submitted another Readiness Certification.  The FERC has not yet acted on this submission.  MISO announced on August 26, 2008 that the startup of its market is postponed indefinitely.  MISO commits to make a filing giving at least sixty days notice of the new effective date. The latest announced effective date for market startup is January 6, 2009.

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.  Upon acceptance by the FERC, this filing will terminate the litigation and the Interconnection Agreement, among other effects.

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Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne zone load-serving entities to pay their PJM capacity obligations through May 31, 2011.

FirstEnergy desires to continue to use its Duquesne zone generation resources to serve load in PJM. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification on whether Duquesne-zone generators could participate in PJM’s May 2008 auction for the 2011-2012 planning year. In the order, the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators could contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with the FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction.

The FERC also directed MISO and PJM to resolve the substantive and procedural issues associated with Duquesne’s transition into MISO. As directed, PJM filed thirteen load-serving entity Capacity Payment Agreements and a Capacity Portability Agreement with the FERC. The Capacity Payment Agreements addressed Duquesne Zone load-serving entity obligations through May 31, 2011 with regards to RPM Capacity while the Capacity Portability Agreement addressed operational issues associated with the portability of such capacity. On September 30, 2008, the FERC approved both agreements, subject to conditions, taking notice of many operational and procedural issues brought forth by FirstEnergy and other market participants.

Several issues surrounding Duquesne’s transition into MISO continue to be contested at the FERC. Specifically, Duquesne’s obligation to pay for transmission expansion costs allocated to the Duquesne zone when they were a member of PJM, and other issues in which market participants wish to be held harmless by Duquesne’s transition. FirstEnergy filed for rehearing on these issues on October 3, 2008. Duquesne’s transition into MISO is also contingent upon the start of MISO’s ancillary services market and consolidation of its balancing authorities, currently scheduled for January 6, 2009.

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. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by the FERC that established the RPM. In the complaint, the RPM Buyers request that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On July 11, 2008, PJM filed its answer to the complaint, in which it denied the allegation that the rates are unjust and unreasonable. Also on that date, FirstEnergy filed a motion to intervene. 

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 its progress on contemplating adjustments to the RPM as suggested by the Brattle Group in its report reviewing the RPM. The technical conference will take place in February, 2009. On October 20, 2008, the RPM Buyers filed a request for rehearing of the FERC’s September 19, 2008 order.

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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 purchase 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. Issuance of these orders is not expected to delay the June 1, 2009 start date for MISO Resource Adequacy.

Organized Wholesale Power Markets

The FERC issued a final rule on October 17, 2008, amending its regulations to “improve the operation of organized wholesale electric markets in the areas of: (1) demand response and market pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market-monitoring policies; and (4) the responsiveness of RTOs and ISOs to their customers and other stakeholders.”  The RTOs and ISOs were directed to submit amendments to their respective tariffs to address these market operation improvements.  The final rule directs RTOs to adopt market rules permitting prices to increase during periods of supply shortages and to permit enhanced participation by demand response resources.  It also codifies and defines for the first time the roles and duties of independent market monitors within RTOs.  Finally, it adopts requirements for enhanced access by stakeholders to RTO boards of directors.  RTOs are directed to make compliance filings six months from the effective date of the final rule.  The final rule is not expected to have any material effect on FirstEnergy's operations within MISO and PJM.

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. A ruling by the FERC is expected the week of December 15, 2008.

On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and The Waverly Power and Light Company (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 FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.

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

Clean Air Act Compliance

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

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

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

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, is 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 $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above. 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. Under the Sammis NSR Litigation consent decree, an election to repower by December 31, 2012, install flue gas desulfurization (FGD) by December 31, 2010, or permanently shut down those units by December 31, 2010, is due no later than December 31, 2008. Although FirstEnergy will meet the December 31, 2008 deadline for making an election, one potential compliance option, should FGD be elected, would be to idle Burger Units 4 and 5 on December 31, 2010 pending completion of the FGD installation. Thus, OE is seeking a determination by the Court whether this approach is indeed in compliance with the terms of the Sammis NSR Litigation consent decree. The Court has scheduled a hearing on OE’s dispute resolution petition for November 17, 2008. The outcome of this dispute resolution process could have an impact on the option FirstEnergy ultimately elects with respect to Burger Units 4 and 5.

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On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.

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.  By letter dated October 1, 2008, New Jersey informed the Court of its intent to file an amended complaint. Met-Ed is 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. FGCO complied with the modified schedule and otherwise intends to fully comply with the ACO, 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

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 would have required 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.” The Court ruling also vacated the CAIR regional cap and trade requirements for SO2 and NOX, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. 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 October 21, 2008, the Court ordered the parties who appealed CAIR to file responses to the rehearing petitions by November 5, 2008 and directed them to address (1) whether any party is seeking vacatur of CAIR and (2) whether the Court should stay its vacatur of CAIR until EPA promulgates a revised rule. The future cost of compliance with these regulations may be substantial and will depend on the Court’s ruling on rehearing, as well as the action taken by the EPA or Congress in response to the Court’s ruling.

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. The Supreme Court could grant the EPA’s petition and alter some or all of the lower Court’s decision, or 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. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, 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.

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.

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

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the 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 is scheduled for December 2, 2008. FirstEnergy 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.

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 September 30, 2008, FirstEnergy had approximately $1.9 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 September 30, 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 $94 million (JCP&L - $68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $24 million) have been accrued through September 30, 2008. Included in the total for JCP&L are accrued liabilities of approximately $57 million for environmental remediation of former manufactured gas plants in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

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Other Legal Proceedings

Power Outages and Related Litigation

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

In August 2002, the trial Court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial Court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court 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 September 30, 2008.

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.

44

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint, which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint and oral argument was held on November 5, 2008.

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. FirstEnergy has a strike mitigation plan ready in the event of a strike.

FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 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 FirstEnergy 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 FirstEnergy’s application of this Standard in periods after implementation will be dependent upon acquisitions at that time.

45

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 FirstEnergy’s financial statements.

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. FirstEnergy expects this Standard to increase its disclosure requirements for derivative instruments and hedging activities.

46

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of FirstEnergy Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of September 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2008 and 2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2008

47

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months						Nine Months
	Ended September 30						Ended September 30
	2008			2007			2008			2007
	(In millions, except per share amounts)
REVENUES:
Electric utilities	$	3,469		$	3,242		$	9,247		$	8,619
Unregulated businesses		435			399			1,179			1,104
Total revenues *		3,904			3,641			10,426			9,723
EXPENSES:
Fuel		356			327			1,000			887
Purchased power		1,306			1,168			3,376			2,914
Other operating expenses		794			756			2,375			2,255
Provision for depreciation		168			162			500			477
Amortization of regulatory assets		291			288			795			785
Deferral of new regulatory assets		(58	)		(107	)		(261	)		(399	)
General taxes		201			197			596			589
Total expenses		3,058			2,791			8,381			7,508
OPERATING INCOME		846			850			2,045			2,215
OTHER INCOME (EXPENSE):
Investment income		40			30			73			93
Interest expense		(192	)		(203	)		(559	)		(593	)
Capitalized interest		15			9			36			21
Total other expense		(137	)		(164	)		(450	)		(479	)
INCOME BEFORE INCOME TAXES		709			686			1,595			1,736
INCOME TAXES		238			273			585			695
NET INCOME	$	471		$	413		$	1,010		$	1,041
BASIC EARNINGS PER SHARE OF COMMON STOCK	$	1.55		$	1.36		$	3.32		$	3.39
WEIGHTED AVERAGE NUMBER OF
BASIC SHARES OUTSTANDING		304			304			304			307
DILUTED EARNINGS PER SHARE OF COMMON STOCK	$	1.54		$	1.34		$	3.29		$	3.35
WEIGHTED AVERAGE NUMBER OF
DILUTED SHARES OUTSTANDING		307			307			307			311
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	1.10		$	1.00		$	1.65		$	1.50
* Includes excise tax collections of $115 million and $113 million in the three months ended September 30, 2008 and 2007,
respectively, and $329 million and $322 million in the nine months ended September 2008 and 2007, respectively.
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

48

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
	Three Months						Nine Months
	Ended September 30						Ended September 30
	2008			2007			2008			2007
	(In millions)
NET INCOME	$	471		$	413		$	1,010		$	1,041
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(20	)		(12	)		(60	)		(34	)
Unrealized gain (loss) on derivative hedges		26			(10	)		21			10
Change in unrealized gain on available for sale securities		(100	)		26			(181	)		89
Other comprehensive income (loss)		(94	)		4			(220	)		65
Income tax expense (benefit) related to other
comprehensive income		(34	)		-			(81	)		19
Other comprehensive income (loss), net of tax		(60	)		4			(139	)		46
COMPREHENSIVE INCOME	$	411		$	417		$	871		$	1,087
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

49

FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2008			2007
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	181		$	129
Receivables-
Customers (less accumulated provisions of $31 million and
$36 million, respectively, for uncollectible accounts)		1,383			1,256
Other (less accumulated provisions of $9 million and
$22 million, respectively, for uncollectible accounts)		148			165
Materials and supplies, at average cost		587			521
Prepayments and other		505			159
		2,804			2,230
PROPERTY, PLANT AND EQUIPMENT:
In service		26,141			24,619
Less - Accumulated provision for depreciation		10,714			10,348
		15,427			14,271
Construction work in progress		1,730			1,112
		17,157			15,383
INVESTMENTS:
Nuclear plant decommissioning trusts		1,873			2,127
Investments in lease obligation bonds		674			717
Other		720			754
		3,267			3,598
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,583			5,607
Regulatory assets		3,433			3,945
Pension assets		768			700
Other		550			605
		10,334			10,857
	$	33,562		$	32,068
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	2,509		$	2,014
Short-term borrowings		2,392			903
Accounts payable		744			777
Accrued taxes		253			408
Other		1,149			1,046
		7,047			5,148
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 375,000,000 shares-
304,835,407 outstanding		31			31
Other paid-in capital		5,465			5,509
Accumulated other comprehensive loss		(189	)		(50	)
Retained earnings		3,994			3,487
Total common stockholders' equity		9,301			8,977
Long-term debt and other long-term obligations		8,674			8,869
		17,975			17,846
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,793			2,671
Asset retirement obligations		1,314			1,267
Deferred gain on sale and leaseback transaction		1,035			1,060
Power purchase contract loss liability		603			750
Retirement benefits		914			894
Lease market valuation liability		319			663
Other		1,562			1,769
		8,540			9,074
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 11)
	$	33,562		$	32,068
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
balance sheets.

50

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months
	Ended September 30
	2008			2007
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,010		$	1,041
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		500			477
Amortization of regulatory assets		795			785
Deferral of new regulatory assets		(261	)		(399	)
Nuclear fuel and lease amortization		82			75
Deferred purchased power and other costs		(163	)		(265	)
Deferred income taxes and investment tax credits, net		278			(158	)
Investment impairment		63			16
Deferred rents and lease market valuation liability		(62	)		(41	)
Accrued compensation and retirement benefits		(127	)		(50	)
Stock-based compensation		(74	)		(32	)
Commodity derivative transactions, net		4			5
Gain on asset sales		(43	)		(35	)
Cash collateral		21			(50	)
Pension trust contribution		-			(300	)
Decrease (increase) in operating assets-
Receivables		(117	)		(329	)
Materials and supplies		(34	)		62
Prepayments and other current assets		(264	)		(39	)
Increase (decrease) in operating liabilities-
Accounts payable		(34	)		(15	)
Accrued taxes		(166	)		355
Accrued interest		107			104
Electric service prepayment programs		(58	)		(52	)
Other		(29	)		55
Net cash provided from operating activities		1,428			1,210
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		631			1,100
Short-term borrowings, net		1,489			-
Redemptions and Repayments-
Common stock		-			(918	)
Long-term debt		(733	)		(647	)
Short-term borrowings, net		-			(535	)
Net controlled disbursement activity		6			6
Stock-based compensation tax benefit		24			16
Common stock dividend payments		(503	)		(464	)
Net cash provided from (used for) financing activities		914			(1,442	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(2,177	)		(1,127	)
Proceeds from asset sales		64			37
Proceeds from sale and leaseback transaction		-			1,329
Sales of investment securities held in trusts		1,144			1,010
Purchases of investment securities held in trusts		(1,215	)		(1,126	)
Cash investments		72			48
Restricted funds for debt redemption		(82	)		-
Other		(96	)		1
Net cash provided from (used for) investing activities		(2,290	)		172
Net change in cash and cash equivalents		52			(60	)
Cash and cash equivalents at beginning of period		129			90
Cash and cash equivalents at end of period	$	181		$	30
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an
integral part of these statements.

51

FIRSTENERGY SOLUTIONS CORP.

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

FES’ revenues are primarily from the sale of electricity (provided from FES’ generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR and default service requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and TE to supply each of their default service obligations through 2008, at prices that take into consideration their respective PUCO-authorized billing rates. FES also has a partial requirements wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to supply a portion of each of their respective default service obligations at fixed prices through 2010. The fixed prices under the partial requirements agreement are expected to remain below wholesale market prices during the term of the agreement. 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’ existing contractual obligations to Penn expire on May 31, 2009, but could continue if FES successfully bids in future competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, Maryland and Michigan.

Results of Operations

In the first nine months of 2008, net income decreased to $344million from $409million in the same period in 2007. The decrease in net income was primarily due to higher fuel and other operating expenses, partially offset by lower purchased power costs and higher revenues.

Revenues

Revenues increased by $154million in the first nine months of 2008 compared to the same period of 2007 due to increases in revenues from non-affiliated and affiliated wholesale sales, partially offset by lower retail generation sales. Non-affiliated wholesale revenues increased as a result of higher capacity prices and sales volumes in the PJM market, partially offset by decreased sales volumes in the MISO market. Retail generation sales revenues decreased as a result of decreased sales in the PJM market partially offset by increased sales in the MISO market. Lower sales in the PJM market were primarily due to lower contract renewals for commercial and industrial customers. Increased sales in the MISO market were primarily due to FES capturing more shopping customers in Penn’s service territory, partially offset by lower customer usage.

The increase in affiliated company wholesale sales was due to 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 resulted from the PSA provision, whereby PSA rates reflect the increase in the Ohio Companies’ retail generation rates. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the composite price to decline. The lower PSA sales volumes to the Ohio and Pennsylvania Companies were due to milder weather and decreased default service requirements in Penn’s service territory as a result of its RFP process.

Changes in revenues in the first nine months of 2008 from the same period of 2007 are summarized below:

	Nine  Months Ended
	September 30,				Increase
Revenues by Type of Service	2008		2007		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	485	$	547	$	(62	)
Wholesale		509		426		83
Total Non-Affiliated Generation Sales		994		973		21
Affiliated Generation Sales		2,266		2,210		56
Transmission		113		71		42
Other		39		4		35
Total Revenues	$	3,412	$	3,258	$	154

52

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated generation sales in the first nine months of 2008 compared to the same period last year:

	Increase
Source of Change in Non-Affiliated Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 13.2% decrease in sales volumes	$	(73	)
Change in prices		11
		(62	)
Wholesale:
Effect of 4.6% increase in sales volumes		19
Change in prices		64
		83
Net Increase in Non-Affiliated Generation Revenues	$	21

	Increase
Source of Change in Affiliated Generation Revenues	(Decrease)
	(In millions)
Ohio Companies:
Effect of 1.7% decrease in sales volumes	$	(28	)
Change in prices		97
		69
Pennsylvania Companies:
Effect of 0.2% decrease in sales volumes		(1	)
Change in prices		(12	)
		(13	)
Net Increase in Affiliated Generation Revenues	$	56

Transmission revenue increased $42 million due primarily to higher rates for transmission service in MISO and PJM. Other revenue increased by $34 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 $272 million in the first nine months of 2008 compared with the same period of 2007. The following tables summarize the factors contributing to the changes in fuel and purchased power costs in the first nine months of 2008 from the same period last year:

Source of Change in Fuel Costs	Increase
	(In millions)
Fossil Fuel:
Change due to volume consumed	$	98
Change due to increased unit costs		73
		171
Nuclear Fuel:
Change due to volume consumed		4
Change due to increased unit costs		3
		7
Net Increase in Fuel Costs	$	178

Fossil fuel costs increased $171 million in the first nine months of 2008 as a result of the assignment of CEI’s and TE’s leasehold interest in the Bruce Mansfield Plant to FGCO in October 2007 and higher unit prices due to increased coal transportation costs, increased prices for existing eastern coal contracts and emission allowance costs. The increased fossil fuel costs were partially offset by a $25 million adjustment resulting from the annual coal inventory that reduced expense in the 2008 period. Nuclear fuel expense increased $7 million reflecting higher generation in 2008.

53

Source of Change in Purchased Power Costs	Increase  (Decrease)
	(In millions)
Purchased Power From Non-affiliates:
Change due to volume purchased	$	(121	)
Change due to increased unit costs		192
		71
Purchased Power From Affiliates
Change due to volume purchased		(126	)
Change due to decreased unit costs		(8	)
		(134	)
Net Decrease in Purchased Power Costs	$	(63	)

Purchased power costs decreased as a result of reduced purchases from affiliates, partially offset by increased non-affiliated purchased power 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 PJM partially offset by reduced volumes reflecting lower retail sales requirements and more available generation.

Other operating expenses increased by $132million in the first nine months of 2008 from the same period of 2007 primarily due to lease expenses relating to the assignment of CEI’s and TE’s leasehold interests in the Mansfield Plant to FGCO ($36 million) and the sale and leaseback of Mansfield Unit 1 ($72 million) completed in the second half of 2007. Higher nuclear operating costs were due to an additional refueling outage during the first nine months of 2008 compared with 2007. Higher fossil operating costs were primarily due to a cancelled fossil project ($13 million), additional planned maintenance outages in 2008, employee benefits and reduced gains from excess emission allowance sales.

Depreciation expense increased by $26 million in the first nine months of 2008 primarily due to the assignment of the Mansfield Plant to FGCO described above and NGC’s acquisition of certain lessor equity interest in the sale and leaseback of Perry and Beaver Valley Unit 2.

Other Expense

Other expense decreased by $8million in the first nine months of 2008 from the same period of 2007 primarily as a result of  decreased interest expense (net of capitalized interest), partially offset by lower miscellaneous income. Affiliated interest expense decreased $36 million primarily as a result of reduced loans from the unregulated money pool. Lower miscellaneous income resulted from a $13 million decrease in net earnings from nuclear decommissioning trust investments due primarily to securities impairments and reduced investment income from loans to the unregulated money pool ($15 million).

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.

54

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of FirstEnergy Solutions Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its subsidiaries as of September 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2008 and 2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2008

55

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months						Nine Months
	Ended September 30						Ended September 30
	2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales to affiliates	$	785,681		$	805,372		$	2,266,271		$	2,209,743
Electric sales to non-affiliates		381,483			337,561			994,100			972,591
Other		74,440			27,975			151,627			75,598
Total revenues		1,241,604			1,170,908			3,411,998			3,257,932
EXPENSES:
Fuel		349,946			301,786			982,185			804,201
Purchased power from non-affiliates		221,493			228,755			648,556			577,831
Purchased power from affiliates		15,821			62,508			75,834			209,576
Other operating expenses		279,184			235,033			863,468			731,774
Provision for depreciation		64,633			48,500			170,535			145,030
General taxes		21,736			22,242			64,728			64,870
Total expenses		952,813			898,824			2,805,306			2,533,282
OPERATING INCOME		288,791			272,084			606,692			724,650
OTHER INCOME (EXPENSE):
Miscellaneous income		18,427			12,655			13,449			47,756
Interest expense - affiliates		(8,015	)		(9,641	)		(25,953	)		(61,904	)
Interest expense - other		(32,769	)		(31,794	)		(81,809	)		(70,845	)
Capitalized interest		12,395			5,131			29,599			12,763
Total other expense		(9,962	)		(23,649	)		(64,714	)		(72,230	)
INCOME BEFORE INCOME TAXES		278,829			248,435			541,978			652,420
INCOME TAXES		93,174			93,671			198,245			243,736
NET INCOME		185,655			154,764			343,733			408,684
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(1,821	)		(1,360	)		(5,462	)		(4,080	)
Unrealized gain on derivative hedges		27,277			4,863			15,075			9,451
Change in unrealized gain on available-for-sale securities		(90,198	)		21,263			(159,759	)		80,053
Other comprehensive income (loss)		(64,742	)		24,766			(150,146	)		85,424
Income tax expense (benefit) related to other
comprehensive income		(24,781	)		8,915			(55,497	)		30,474
Other comprehensive income (loss), net of tax		(39,961	)		15,851			(94,649	)		54,950
TOTAL COMPREHENSIVE INCOME	$	145,694		$	170,615		$	249,084		$	463,634
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral part of
these balance sheets.

56

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,		December 31,
	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	2
Receivables-
Customers (less accumulated provisions of $5,840,000 and $8,072,000,
respectively, for uncollectible accounts)		137,126		133,846
Associated companies		263,779		376,499
Other (less accumulated provisions of $6,798,000 and $9,000
respectively, for uncollectible accounts)		22,924		3,823
Notes receivable from associated companies		156,926		92,784
Materials and supplies, at average cost		497,276		427,015
Prepayments and other		179,530		92,340
		1,257,563		1,126,309
PROPERTY, PLANT AND EQUIPMENT:
In service		9,834,662		8,294,768
Less - Accumulated provision for depreciation		4,211,717		3,892,013
		5,622,945		4,402,755
Construction work in progress		1,385,652		761,701
		7,008,597		5,164,456
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		1,145,384		1,332,913
Long-term notes receivable from associated companies		62,900		62,900
Other		40,573		40,004
		1,248,857		1,435,817
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		230,341		276,923
Lease assignment receivable from associated companies		71,356		215,258
Goodwill		24,248		24,248
Property taxes		47,774		47,774
Pension assets		14,764		16,723
Unamortized sale and leaseback costs		57,365		70,803
Other		49,702		43,953
		495,550		695,682
	$	10,010,567	$	8,422,264
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,938,215	$	1,441,196
Short-term borrowings-
Associated companies		311,750		264,064
Other		1,000,000		300,000
Accounts payable-	��
Associated companies		361,447		445,264
Other		163,173		177,121
Accrued taxes		80,719		171,451
Other		217,914		237,806
		4,073,218		3,036,902
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 750 shares-
7 shares outstanding		1,461,541		1,164,922
Accumulated other comprehensive income		46,005		140,654
Retained earnings		1,409,388		1,108,655
Total common stockholder's equity		2,916,934		2,414,231
Long-term debt and other long-term obligations		558,923		533,712
		3,475,857		2,947,943
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		1,035,013		1,060,119
Accumulated deferred investment tax credits		63,968		61,116
Asset retirement obligations		849,475		810,114
Retirement benefits		67,567		63,136
Property taxes		48,095		48,095
Lease market valuation liability		319,129		353,210
Other		78,245		41,629
		2,461,492		2,437,419
COMMITMENTS AND CONTINGENCIES (Note 11)
	$	10,010,567	$	8,422,264
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral
part of these balance sheets.

57

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months
	Ended September 30
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	343,733		$	408,684
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		170,535			145,030
Nuclear fuel and lease amortization		81,950			75,102
Deferred rents and lease market valuation liability		(36,702	)		-
Deferred income taxes and investment tax credits, net		91,082			(381,042	)
Investment impairment		58,173			14,296
Accrued compensation and retirement benefits		(2,110	)		3,414
Commodity derivative transactions, net		3,634			4,913
Gain on asset sales		(11,319	)		(12,105	)
Cash collateral, net		(8,827	)		(19,798	)
Pension trust contribution		-			(64,020	)
Decrease (increase) in operating assets:
Receivables		106,574			(30,172	)
Materials and supplies		(35,498	)		48,123
Prepayments and other current assets		(10,762	)		(5,118	)
Increase (decrease) in operating liabilities:
Accounts payable		(61,035	)		(108,949	)
Accrued taxes		(90,767	)		434,568
Accrued interest		15,420			14,355
Other		(59,948	)		(5,254	)
Net cash provided from operating activities		554,133			522,027
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		537,375			-
Equity contribution from parent		280,000			700,000
Short-term borrowings, net		747,686			-
Redemptions and Repayments-
Common stock		-			(600,000	)
Long-term debt		(460,902	)		(1,110,174	)
Short-term borrowings, net		-			(785,127	)
Common stock dividend payments		(43,000	)		(67,000	)
Net cash provided from (used for) financing activities		1,061,159			(1,862,301	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(1,417,205	)		(482,907	)
Proceeds from asset sales		15,218			12,990
Proceeds from sale and leaseback transaction		-			1,328,919
Sales of investment securities held in trusts		596,291			521,535
Purchases of investment securities held in trusts		(624,899	)		(552,779	)
Loan repayments from (loans to) associated companies, net		(64,142	)		510,307
Restricted funds for debt redemption		(81,640	)		-
Other		(38,915	)		2,209
Net cash provided from (used for) investing activities		(1,615,292	)		1,340,274
Net change in cash and cash equivalents		-			-
Cash and cash equivalents at beginning of period		2			2
Cash and cash equivalents at end of period	$	2		$	2
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are
an integral part of these balance sheets.

58

OHIO EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They provide generation services to those customers electing to retain OE and Penn as their power supplier. OE’s power supply requirements are provided by FES – an affiliated company. Penn purchases power from FES and third-party suppliers through a competitive RFP process.

Results of Operations

In the first nine months of 2008, net income increased to $165 million from $148 million in the same period of 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 $73 million, or 3.9%, in the first nine months of 2008 compared with the same period in 2007, primarily due to increases in retail generation revenues ($51 million) and distribution throughput revenues ($16 million).

Retail generation revenues increased primarily due to higher average prices across all customer classes, partially offset by decreased KWH sales in all sectors. The higher average prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see Regulatory Matters). Milder weather in the first nine months of 2008 primarily caused the lower KWH sales (cooling degree days decreased in OE’s and Penn’s service territories by 23.3% and 21.5%, respectively, from the same period in 2007). Commercial and industrial retail KWH sales were also impacted by increased customer shopping in Penn’s service territory in the first nine months of 2008.

Changes in retail generation sales and revenues in the first nine months of 2008 from the same period in 2007 are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(2.3)	%
Commercial		(2.1)	%
Industrial		(4.4)	%
Decrease in Generation Sales		(2.9)	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	23
Commercial		11
Industrial		17
Increase in Generation Revenues	$	51

Revenues from distribution throughput increased by $16 million in the first nine months of 2008 compared to the same period in 2007 due to higher average unit prices for all customer classes, partially offset by lower KWH deliveries in all sectors. 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.

Changes in distribution KWH deliveries and revenues in the first nine months of 2008 from the same period in 2007 are summarized in the following tables.

59

Distribution KWH Deliveries	Decrease
Residential	(1.8)	%
Commercial	(0.8)	%
Industrial	(2.2)	%
Decrease in Distribution Deliveries	(1.7)	%

Distribution Revenues	Increase
	(In millions)
Residential	$	3
Commercial		7
Industrial		6
Increase in Distribution Revenues	$	16

Expenses

Total expenses increased by $38 million in the first nine months of 2008 from the same period of 2007. The following table presents changes from the prior year by expense category.

Expenses – Changes	Increase (Decrease)
		(In millions)
Purchased power costs	$	(40	)
Other operating costs		(1	)
Provision for depreciation		1
Amortization of regulatory assets		9
Deferral of new regulatory assets		66
General taxes		3
Net Increase in Expenses	$	38

Lower purchased power costs in the first nine months of 2008 primarily reflected the lower retail generation KWH sales, reducing the purchase volumes required. Higher amortization of regulatory assets in the first nine months of 2008 was primarily due to increased amortization of MISO transmission cost deferrals. The decrease in the deferral of new regulatory assets for the first nine months of 2008 was primarily due to lower MISO cost deferrals ($26 million) and lower RCP fuel deferrals ($36 million), as more transmission and generation costs were recovered from customers through PUCO-approved riders. The increase in general taxes for the first nine months of 2008 was primarily due to higher property taxes.

Other Income

Other income decreased $20 million in the first nine months of 2008 as compared with the same period of 2007 primarily due to reductions in interest income on notes receivable from associated companies resulting from principal payments since the third quarter of 2007.

Legal Proceedings

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

60

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Ohio Edison Company:

We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of September 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2008 and 2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2008

61

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
		Three Months						Nine Months
		Ended September 30						Ended September 30
		2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales		$	671,761		$	638,336		$	1,877,300		$	1,802,110
Excise tax collections			30,500			30,472			87,165			89,077
Total revenues			702,261			668,808			1,964,465			1,891,187
EXPENSES:
Purchased power			349,374			364,709			997,609			1,037,200
Other operating costs			146,048			144,869			423,993			424,970
Provision for depreciation			14,997			19,482			57,904			57,440
Amortization of regulatory assets			57,660			53,026			154,054			144,569
Deferral of new regulatory assets			(15,078	)		(41,417	)		(66,390	)		(132,410	)
General taxes			49,255			46,158			144,097			141,296
Total expenses			602,256			586,827			1,711,267			1,673,065
OPERATING INCOME			100,005			81,981			253,198			218,122
OTHER INCOME (EXPENSE):
Investment income			19,323			19,827			45,866			67,803
Miscellaneous income (expense)			(1,089	)		670			(5,180	)		3,362
Interest expense			(17,309	)		(20,311	)		(51,851	)		(62,749	)
Capitalized interest			55			136			324			398
Total other income (expense)			980			322			(10,841	)		8,814
INCOME BEFORE INCOME TAXES			100,985			82,303			242,357			226,936
INCOME TAXES			28,501			34,089			77,122			79,074
NET INCOME			72,484			48,214			165,235			147,862
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirment benefits			(3,994	)		(3,423	)		(11,982	)		(10,270	)
Change in unrealized gain on available-for-sale securities			(9,936	)		2,442			(20,310	)		7,415
Other comprehensive loss			(13,930	)		(981	)		(32,292	)		(2,855	)
Income tax benefit related to other comprehensive loss			(5,105	)		(573	)		(11,931	)		(1,688	)
Other comprehensive loss, net of tax			(8,825	)		(408	)		(20,361	)		(1,167	)
TOTAL COMPREHENSIVE INCOME		$	63,659		$	47,806		$	144,874		$	146,695
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of
these statements.

62

OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,		December 31,
	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	715	$	732
Receivables-
Customers (less accumulated provisions of $6,888,000 and 8,032,000,
respectively, for uncollectible accounts)		268,252		248,990
Associated companies		205,776		185,437
Other (less accumulated provisions of $13,000 and $5,639,000
respectively, for uncollectible accounts)		16,731		12,395
Notes receivable from associated companies		362,695		595,859
Prepayments and other		11,285		10,341
		865,454		1,053,754
UTILITY PLANT:
In service		2,854,174		2,769,880
Less - Accumulated provision for depreciation		1,101,572		1,090,862
		1,752,602		1,679,018
Construction work in progress		41,880		50,061
		1,794,482		1,729,079
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		257,457		258,870
Investment in lease obligation bonds		248,751		253,894
Nuclear plant decommissioning trusts		115,523		127,252
Other		31,441		36,037
		653,172		676,053
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		621,192		737,326
Pension assets		250,762		228,518
Property taxes		65,520		65,520
Unamortized sale and leaseback costs		41,381		45,133
Other		33,820		48,075
		1,012,675		1,124,572
	$	4,325,783	$	4,583,458
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	159,662	$	333,224
Short-term borrowings-
Associated companies		-		50,692
Other		242,449		2,609
Accounts payable-
Associated companies		95,604		174,088
Other		20,902		19,881
Accrued taxes		58,800		89,571
Accrued interest		14,216		22,378
Other		123,177		65,163
		714,810		757,606
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 shares outstanding		1,224,039		1,220,512
Accumulated other comprehensive income		28,025		48,386
Retained earnings		207,512		307,277
Total common stockholder's equity		1,459,576		1,576,175
Long-term debt and other long-term obligations		841,871		840,591
		2,301,447		2,416,766
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		776,042		781,012
Accumulated deferred investment tax credits		14,040		16,964
Asset retirement obligations		79,372		93,571
Retirement benefits		173,297		178,343
Deferred revenues - electric service programs		14,954		46,849
Other		251,821		292,347
		1,309,526		1,409,086
COMMITMENTS AND CONTINGENCIES (Note 11)
	$	4,325,783	$	4,583,458
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral
part of these balance sheets.

63

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months
	Ended September 30
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	165,235		$	147,862
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		57,904			57,440
Amortization of regulatory assets		154,054			144,569
Deferral of new regulatory assets		(66,390	)		(132,410	)
Amortization of lease costs		28,535			28,567
Deferred income taxes and investment tax credits, net		17,267			(29,155	)
Accrued compensation and retirement benefits		(41,190	)		(34,572	)
Pension trust contribution		-			(20,261	)
Decrease (increase) in operating assets-
Receivables		(26,009	)		(70,098	)
Prepayments and other current assets		2,065			(3,542	)
Increase (decrease) in operating liabilities-
Accounts payable		(77,463	)		89,550
Accrued taxes		(27,776	)		(25,734	)
Accrued interest		(8,162	)		(7,277	)
Electric service prepayment programs		(31,895	)		(27,455	)
Other		(1,283	)		9,868
Net cash provided from operating activities		144,892			127,352
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		189,148			-
Redemptions and Repayments-
Common stock		-			(500,000	)
Long-term debt		(175,588	)		(1,190	)
Short-term borrowings, net		-			(64,475	)
Dividend Payments-
Common stock		(265,000	)		(150,000	)
Net cash used for financing activities		(251,440	)		(715,665	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(135,450	)		(109,461	)
Sales of investment securities held in trusts		115,988			31,624
Purchases of investment securities held in trusts		(121,871	)		(36,194	)
Loan repayments from associated companies, net		234,577			685,364
Cash investments		5,143			17,316
Other		8,144			(321	)
Net cash provided from investing activities		106,531			588,328
Net increase (decrease) in cash and cash equivalents		(17	)		15
Cash and cash equivalents at beginning of period		732			712
Cash and cash equivalents at end of period	$	715		$	727
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an
integral part of these statements.

64

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

Results of Operations

Net income in the first nine months of 2008 increased to $218 million from $211 million in the same period of 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 $24 million, or 1.7%, in the first nine months of 2008 compared to the same period of 2007, primarily due to a decrease in wholesale generation revenues ($89million), partially offset by increases in retail generation revenues ($50 million), distribution revenues ($8 million), and transmission revenues ($11 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 the first nine months of 2008 due to higher average unit prices across all customer classes, partially offset by a slight decrease in sales volume in all sectors compared to the same period of 2007. The higher average unit prices were driven by the 2008 fuel cost recovery rider that became effective January 16, 2008 (see Regulatory Matters). Milder weather in the first nine months of 2008, compared to the same period of 2007, primarily caused the decrease in sales volume (heating and cooling degree days decreased 1% and 7%, respectively).

Changes in retail generation sales and revenues in the first nine months of 2008 compared to the same period in 2007 are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(1.2	)%
Commercial		(1.1	)%
Industrial		(1.1	)%
Decrease in Retail Generation Sales		(1.1	)%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	17
Commercial		12
Industrial		21
Increase in Generation Revenues	$	50

Revenues from distribution throughput increased by $8 million in the first nine months of 2008 compared to the same period of 2007 primarily due to higher average unit prices for all customer classes, partially offset by a slight decrease in KWH deliveries in all sectors. 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 the first nine months of 2008 reflected the weather impacts described above.

Changes in distribution KWH deliveries and revenues in the first nine months of 2008 compared to the same period of 2007 are summarized in the following tables.

Distribution KWH Deliveries	Decrease
Residential		(1.5	)%
Commercial		(1.4	)%
Industrial		(1.0	)%
Decrease in Distribution Deliveries		(1.2	)%

65

Distribution Revenues	Increase
	(In millions)
Residential	$	-
Commercial		2
Industrial		6
Increase in Distribution Revenues	$	8

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

Expenses

Total expenses decreased by $19 million in the first nine months of 2008 compared to the same period of 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		15
Other operating costs		(49	)
Provision for depreciation		(1	)
Amortization of regulatory assets		15
Deferral of new regulatory assets		43
General taxes		(2	)
Net Decrease in Expenses	$	(19	)

The absence of fuel costs in the first nine months of 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, partially offset by higher labor costs resulting from storm restoration work performed during the first nine months of 2008. Higher amortization of regulatory assets was primarily due to increased transition cost amortization ($11 million) under the effective interest methodology and increased amortization of MISO transmission cost deferrals ($4 million). The decrease in the deferral of new regulatory assets was primarily due to lower MISO cost deferrals ($19 million) and RCP fuel costs ($25 million), as more transmission and generation costs were recovered from customers through PUCO-approved riders. General taxes decreased primarily due to a $3 million decrease in general tax reserves, partially offset by $1 million increase in commercial activity taxes.

Other Expense

Other expense increased by $13 million in the first nine months of 2008 compared to the same period of 2007 primarily due to lower investment income and miscellaneous income, partially offset by a reduction in interest expense. Lower investment income is primarily the result of principal repayments during 2007 on notes receivable from associated companies. The lower interest expense is primarily due to $489 million in long-term debt redemptions during 2007, partially offset by a new debt issuance of $250 million in March 2007. Miscellaneous income decreased primarily due to reduced life insurance investment values.

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.

66

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of Directors of

The Cleveland Electric Illuminating Company:

We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of September 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2008 and 2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2008

67

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months						Nine Months
	Ended September 30						Ended Septmeber 30
	2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales	$	505,425		$	510,577		$	1,342,327		$	1,366,396
Excise tax collections		18,652			18,514			53,447			53,009
Total revenues		524,077			529,091			1,395,774			1,419,405
EXPENSES:
Fuel		-			12,160			-			39,683
Purchased power		211,445			216,194			590,300			575,520
Other operating costs		66,342			85,114			194,119			243,140
Provision for depreciation		17,677			18,913			54,497			56,094
Amortization of regulatory assets		48,155			42,077			124,936			110,253
Deferral of new regulatory assets		(16,176	)		(37,692	)		(71,443	)		(114,708	)
General taxes		36,722			37,930			109,230			110,922
Total expenses		364,165			374,696			1,001,639			1,020,904
OPERATING INCOME		159,912			154,395			394,135			398,501
OTHER INCOME (EXPENSE):
Investment income		8,390			13,805			25,972			47,816
Miscellaneous income (expense)		(1,114	)		(760	)		(1,319	)		3,197
Interest expense		(31,024	)		(34,423	)		(94,479	)		(107,430	)
Capitalized interest		200			309			584			655
Total other expense		(23,548	)		(21,069	)		(69,242	)		(55,762	)
INCOME BEFORE INCOME TAXES		136,364			133,326			324,893			342,739
INCOME TAXES		42,977			54,610			107,082			131,525
NET INCOME		93,387			78,716			217,811			211,214
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(213	)		1,202			(639	)		3,607
Income tax expense (benefit) related to other comprehensive income		(130	)		356			(239	)		1,068
Other comprehensive income (loss), net of tax		(83	)		846			(400	)		2,539
TOTAL COMPREHENSIVE INCOME	$	93,304		$	79,562		$	217,411		$	213,753
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral
part of these statements.

68

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	237		$	232
Receivables-
Customers (less accumulated provisions of $6,907,000 and $7,540,000
respectively, for uncollectible accounts)		292,735			251,000
Associated companies		122,210			166,587
Other		4,151			12,184
Notes receivable from associated companies		21,682			52,306
Prepayments and other		2,373			2,327
		443,388			484,636
UTILITY PLANT:
In service		2,180,347			2,256,956
Less - Accumulated provision for depreciation		836,058			872,801
		1,344,289			1,384,155
Construction work in progress		44,392			41,163
		1,388,681			1,425,318
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		425,717			463,431
Other		10,260			10,285
		435,977			473,716
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,688,521			1,688,521
Regulatory assets		796,475			870,695
Pension assets		68,548			62,471
Property taxes		76,000			76,000
Other		9,036			32,987
		2,638,580			2,730,674
	$	4,906,626		$	5,114,344
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	207,312		$	207,266
Short-term borrowings-
Associated companies		367,422			531,943
Accounts payable-
Associated companies		124,335			169,187
Other		5,704			5,295
Accrued taxes		70,515			94,991
Accrued interest		37,885			13,895
Other		41,366			34,350
		854,539			1,056,927
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding		878,199			873,536
Accumulated other comprehensive loss		(69,529	)		(69,129	)
Retained earnings		793,238			685,428
Total common stockholder's equity		1,601,908			1,489,835
Long-term debt and other long-term obligations		1,447,718			1,459,939
		3,049,626			2,949,774
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		727,615			725,523
Accumulated deferred investment tax credits		13,442			18,567
Retirement benefits		95,931			93,456
Deferred revenues - electric service programs		9,594			27,145
Lease assignment payable to associated companies		40,827			131,773
Other		115,052			111,179
		1,002,461			1,107,643
COMMITMENTS AND CONTINGENCIES (Note 11)
	$	4,906,626		$	5,114,344
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
Company are an integral part of these balance sheets.

69

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months
	Ended September 30
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	217,811		$	211,214
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		54,497			56,094
Amortization of regulatory assets		124,936			110,253
Deferral of new regulatory assets		(71,443	)		(114,708	)
Deferred rents and lease market valuation liability		-			(46,327	)
Deferred income taxes and investment tax credits, net		4,623			(40,964	)
Accrued compensation and retirement benefits		(3,291	)		2,575
Pension trust contribution		-			(24,800	)
Decrease (increase) in operating assets-
Receivables		43,927			140,359
Prepayments and other current assets		(37	)		661
Increase (decrease) in operating liabilities-
Accounts payable		(44,443	)		(143,210	)
Accrued taxes		(19,613	)		17,301
Accrued interest		23,990			22,360
Electric service prepayment programs		(17,551	)		(16,819	)
Other		4,193			2,996
Net cash provided from operating activities		317,599			176,985
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			247,424
Redemptions and Repayments-
Long-term debt		(508	)		(223,555	)
Short-term borrowings, net		(176,354	)		(59,328	)
Dividend Payments-
Common stock		(110,000	)		(304,000	)
Net cash used for financing activities		(286,862	)		(339,459	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(97,326	)		(100,583	)
Loan repayments from (loans to) associated companies, net		30,624			(13,863	)
Collection of principal on long-term notes receivable		-			220,974
Redemption of lessor notes		37,714			56,177
Other		(1,744	)		(218	)
Net cash provided from (used for) investing activities		(30,732	)		162,487
Net increase in cash and cash equivalents		5			13
Cash and cash equivalents at beginning of period		232			221
Cash and cash equivalents at end of period	$	237		$	234
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
Company are an integral part of these statements.

70

THE TOLEDO EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

Results of Operations

Net income in the first nine months of 2008 decreased to $70million from $73million in the same period of 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 $66million, or 8.8%, in the first nine months of 2008, compared to the same period of 2007, due to lower wholesale generation revenues ($114 million), partially offset by increased retail generation revenues ($37million), distribution revenues ($5million) and transmission revenues ($6 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 $50 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 and is currently selling the 158 MW entitlement from its 18.26% leasehold interest in the unit to NGC. Revenues from PSA sales decreased by $67 million in the first nine months of 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 the first nine months of 2008 due to higher average prices across all customer classes and increased KWH sales to commercial customers compared to the same period of 2007. The higher average prices were driven by the 2008 fuel cost recovery rider that became effective January 16, 2008 (see Regulatory Matters). Sales to residential customers decreased due to milder weather in the first nine months of 2008 (cooling degree days decreased 15% from the same period of 2007). The increase in sales to commercial customers was due to less customer shopping; generation services provided by alternative suppliers as a percentage of total sales delivered in TE’s franchise area decreased by three percentage points. Industrial KWH sales decreased due in part to lower sales to the automotive sector and a maintenance outage undertaken by a large industrial customer during the first nine months of 2008.

Changes in retail electric generation KWH sales and revenues in the first nine months of 2008 from the same period of 2007 are summarized in the following tables.

	Increase
Retail Generation KWH Sales	(Decrease)
Residential		(1.3	)%
Commercial		4.9	%
Industrial		(4.8	)%
Net Decrease in Retail Generation Sales		(2.0	)%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	7
Commercial		11
Industrial		19
Increase in Retail Generation Revenues	$	37

71

Revenues from distribution throughput increased by $5 million in the first nine months of 2008 compared to the same period in 2007 due to higher average unit prices for all customer classes, partially offset by lower KWH deliveries to all sectors. The higher average prices resulted from PUCO-approved transmission rider increases that became effective July 1, 2007 and July 1, 2008. The lower KWH deliveries to residential and commercial customers in the first nine months of 2008 reflected the weather impacts described above. As with the reduction in generation sales, industrial KWH deliveries decreased in part due to lower sales to the automotive sector and a maintenance outage undertaken by a large industrial customer in 2008.

Changes in distribution KWH deliveries and revenues in the first nine months of 2008 from the same period of 2007 are summarized in the following tables.

Distribution KWH Deliveries	Decrease
Residential		(1.8	)%
Commercial		(0.5	)%
Industrial		(4.7	)%
Decrease in Distribution Deliveries		(2.8	)%

Distribution Revenues	Increase
	(In millions)
Residential	$	2
Commercial		2
Industrial		1
Increase in Distribution Revenues	$	5

Expenses

Total expenses decreased $40 million in the first nine months of 2008 from the same period of 2007. The following table presents changes from the prior year by expense category.

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	11
Other operating costs		(76	)
Provision for depreciation		(3	)
Amortization of regulatory assets		3
Deferral of new regulatory assets		23
General taxes		2
Net Decrease in Expenses	$	(40	)

Higher purchased power costs primarily reflected higher unit prices as provided for under the PSA with FES. Other operating costs decreased primarily due to the reversal of the above-market lease liability ($23 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 ($25 million) and other operating costs ($28 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 ($7 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 the first nine months of 2008.

The increase in the amortization of regulatory assets was primarily due to increased amortization of MISO transmission cost deferrals ($5 million), partially offset by lower amortization of transition cost deferrals ($2 million) resulting from reduced distribution deliveries. The change in the deferral of new regulatory assets was primarily due to lower deferred fuel costs ($11 million) and MISO transmission expenses ($7 million), as more generation and transmission costs were recovered from customers through PUCO-approved riders, and lower RCP distribution cost deferrals ($4 million). Higher general taxes primarily reflected increased KWH taxes, property taxes and Ohio commercial activity taxes.

Other Expense

Other expense decreased $6 million in the first nine months of 2008, compared to the same period of 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 the first nine months of 2008, and the redemption of long-term debt ($55 million principal amount) since the third quarter of 2007. The decrease in investment income resulted primarily from principal repayments since the third quarter of 2007 on notes receivable from associated companies and lower interest income from customer accounts receivable financing activity.

72

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.

.

73

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of The Toledo Edison Company:

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of September 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2008 and 2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2008

74

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
		Three Months						Nine Months
		Ended September 30						Ended September 30
		2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales		$	242,866		$	261,736		$	660,888		$	728,429
Excise tax collections			8,239			7,926			23,417			22,026
Total revenues			251,105			269,662			684,305			750,455
EXPENSES:
Purchased power			111,809			112,502			315,957			304,947
Other operating costs			47,010			73,701			143,144			218,961
Provision for depreciation			7,682			9,231			24,648			27,475
Amortization of regulatory assets			31,452			30,460			81,837			79,284
Deferral of new regulatory assets			(5,574	)		(15,645	)		(23,997	)		(47,373	)
General taxes			13,609			11,912			40,591			38,646
Total expenses			205,988			222,161			582,180			621,940
OPERATING INCOME			45,117			47,501			102,125			128,515
OTHER INCOME (EXPENSE):
Investment income			5,580			6,721			17,285			21,255
Miscellaneous expense			(1,529	)		(2,153	)		(4,992	)		(7,309	)
Interest expense			(5,832	)		(8,786	)		(17,445	)		(25,205	)
Capitalized interest			19			220			144			467
Total other expense			(1,762	)		(3,998	)		(5,008	)		(10,792	)
INCOME BEFORE INCOME TAXES			43,355			43,503			97,117			117,723
INCOME TAXES			12,174			18,435			27,614			44,924
NET INCOME			31,181			25,068			69,503			72,799
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits			(64	)		574			(191	)		1,720
Change in unrealized gain on available-for-sale-securities			(247	)		1,946			(767	)		1,656
Other comprehensive income (loss)			(311	)		2,520			(958	)		3,376
Income tax expense (benefit) related to other
comprehensive income			(108	)		902			(294	)		1,193
Other comprehensive income (loss), net of tax			(203	)		1,618			(664	)		2,183
TOTAL COMPREHENSIVE INCOME		$	30,978		$	26,686		$	68,839		$	74,982
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral
part of these statements.

75

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,			December 31,
		2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	24		$	22
Receivables-
Customers			931			449
Associated companies			58,215			88,796
Other (less accumulated provisions of $165,000 and $615,000,
respectively, for uncollectible accounts)			15,810			3,116
Notes receivable from associated companies			111,519			154,380
Prepayments and other			1,421			865
			187,920			247,628
UTILITY PLANT:
In service			860,417			931,263
Less - Accumulated provision for depreciation			402,952			420,445
			457,465			510,818
Construction work in progress			7,626			19,740
			465,091			530,558
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			142,657			154,646
Long-term notes receivable from associated companies			37,308			37,530
Nuclear plant decommissioning trusts			68,438			66,759
Other			1,691			1,756
			250,094			260,691
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			500,576			500,576
Regulatory assets			145,404			203,719
Pension assets			31,059			28,601
Property taxes			21,010			21,010
Other			52,325			20,496
			750,374			774,402
		$	1,653,479		$	1,813,279
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	34		$	34
Accounts payable-
Associated companies			88,769			245,215
Other			3,368			4,449
Notes payable to associated companies			95,203			13,396
Accrued taxes			20,508			30,245
Lease market valuation liability			36,900			36,900
Other			26,415			22,747
			271,197			352,986
CAPITALIZATION:
Common stockholder's equity-
Common stock, $5 par value, authorized 60,000,000 shares -
29,402,054 shares outstanding			147,010			147,010
Other paid-in capital			175,643			173,169
Accumulated other comprehensive loss			(11,270	)		(10,606	)
Retained earnings			185,121			175,618
Total common stockholder's equity			496,504			485,191
Long-term debt and other long-term obligations			303,382			303,397
			799,886			788,588
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			100,872			103,463
Accumulated deferred investment tax credits			6,882			10,180
Lease market valuation liability			282,325			310,000
Retirement benefits			66,201			63,215
Asset retirement obligations			29,715			28,366
Deferred revenues - electric service programs			4,073			12,639
Lease assignment payable to associated companies			30,529			83,485
Other			61,799			60,357
			582,396			671,705
COMMITMENTS AND CONTINGENCIES (Note 11)
		$	1,653,479		$	1,813,279
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company
are an integral part of these balance sheets.

76

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months
	Ended September 30
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	69,503		$	72,799
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		24,648			27,475
Amortization of regulatory assets		81,837			79,284
Deferral of new regulatory assets		(23,997	)		(47,373	)
Deferred rents and lease market valuation liability		(32,918	)		(23,551	)
Deferred income taxes and investment tax credits, net		(4,163	)		(32,530	)
Accrued compensation and retirement benefits		(196	)		3,493
Pension trust contribution		-			(7,659	)
Decrease (increase) in operating assets-
Receivables		29,088			(13,368	)
Prepayments and other current assets		(556	)		224
Increase (decrease) in operating liabilities-
Accounts payable		(157,527	)		9,515
Accrued taxes		(9,737	)		13,588
Accrued interest		4,663			3,444
Electric service prepayment programs		(8,566	)		(7,650	)
Other		(577	)		4,113
Net cash provided from (used for) operating activities		(28,498	)		81,804
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		81,807			37,191
Redemptions and Repayments-
Long-term debt		(26	)		(30,014	)
Dividend Payments-
Common stock		(60,000	)		(120,000	)
Net cash provided from (used for) financing activities		21,781			(112,823	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(44,695	)		(41,573	)
Loan repayments from associated companies, net		42,948			21,438
Collection of principal on long-term notes receivable		135			36,077
Redemption of lessor notes		11,989			14,819
Sales of investment securities held in trusts		28,774			39,260
Purchases of investment securities held in trusts		(31,297	)		(41,717	)
Other		(1,135	)		2,713
Net cash provided from investing activities		6,719			31,017
Net increase (decrease) in cash and cash equivalents		2			(2	)
Cash and cash equivalents at beginning of period		22			22
Cash and cash equivalents at end of period	$	24		$	20
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are
an integral part of these statements.

77

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

Results of Operations

Net income for the first nine months of 2008 decreased to $153million from $164million in the same period in 2007. The decrease was primarily due to higher purchased power costs and other expenses, partially offset by higher revenues and lower amortization of regulatory assets.

Revenues

In the first nine months of 2008, revenues increased $235 million, or 9%, as compared with the same period of 2007. Retail and wholesale generation revenues increased by $147million and $97million, respectively, while distribution revenues decreased by $3 million in the first nine months of 2008.

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. The decreased sales volume was primarily caused by milder weather and customer shopping. In the first nine months of 2008, heating degree days decreased 8.1%as compared to the first nine months of 2007, while cooling degree days were unchanged. Customer shopping in the commercial and industrial customer sectors increased by 3.7 percentage points and 1.3 percentage points, respectively, in the first nine months of 2008.

Changes in retail generation KWH sales and revenues by customer class in the first nine months of 2008 compared to the same period of 2007 are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(1.2)	%
Commercial		(6.0)	%
Industrial		(6.7)	%
Decrease in Generation Sales		(3.4)	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	99
Commercial		42
Industrial		6
Increase in Generation Revenues	$	147

Wholesale generation revenues increased $97million in the first nine months of 2008 due to higher market prices, partially offset by a slight decrease in sales volumes as compared to the first nine months of 2007.

Distribution revenues decreased $3 million in the first nine months of 2008 as compared to the same period of 2007 due to lower KWH deliveries, reflecting the weather impacts described above, partially offset by a slight increase in composite unit prices.

Changes in distribution KWH deliveries and revenues by customer class in the first nine months of 2008 compared to the same period in 2007 are summarized in the following tables:

Distribution KWH Deliveries	Decrease
Residential		(1.2)	%
Commercial		(1.4)	%
Industrial		(1.5)	%
Decrease in Distribution Deliveries		(1.3)	%

78

Distribution Revenues	Increase (Decrease)
	(In millions)
Residential	$	1
Commercial		(4	)
Industrial		-
Net Decrease in Distribution Revenues	$	(3	)

Expenses

Total expenses increased by $236 million in the first nine months of 2008 as compared to the same period of 2007. The following table presents changes from the prior year period by expense category:

Expenses  - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	246
Other operating costs		(1	)
Provision for depreciation		6
Amortization of regulatory assets		(16	)
General taxes		1
Net increase in expenses	$	236

Purchased power costs increased in the first nine months of 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. Depreciation expense increased primarily due to an increase in depreciable property since the third quarter of 2007. Amortization of regulatory assets decreased in the first nine months of 2008 primarily due to the completion in December 2007 of certain regulatory asset amortizations associated with TMI-2 and lower transition cost amortization due to the lower KWH deliveries discussed above.

Other Expenses

Other expenses increased by $13 million in the first nine months of 2008 as compared to the same period in 2007 primarily due to interest expense associated with JCP&L’s $550 million issuance of senior notes in May 2007 and reduced life insurance investment values.

Sale of Investment

On April 17, 2008, JCP&L closed on 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 the first nine months of 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.

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.

79

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Jersey Central Power & Light Company:

We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of September 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2008 and 2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2008

80

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months						Nine Months
	Ended September 30						Ended September 30
	2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales	$	1,087,245		$	1,018,049		$	2,691,782		$	2,457,146
Excise tax collections		15,358			15,168			39,792			39,849
Total revenues		1,102,603			1,033,217			2,731,574			2,496,995
EXPENSES:
Purchased power		720,996			654,418			1,751,854			1,505,420
Other operating costs		78,275			87,010			234,628			236,225
Provision for depreciation		23,205			22,032			70,030			63,867
Amortization of regulatory assets		102,954			107,837			280,980			296,955
General taxes		19,476			18,631			52,042			51,183
Total expenses		944,906			889,928			2,389,534			2,153,650
OPERATING INCOME		157,697			143,289			342,040			343,345
OTHER INCOME (EXPENSE):
Miscellaneous income (expense)		(565	)		2,967			459			9,266
Interest expense		(25,747	)		(24,666	)		(75,051	)		(71,576	)
Capitalized interest		257			483			963			1,559
Total other expense		(26,055	)		(21,216	)		(73,629	)		(60,751	)
INCOME BEFORE INCOME TAXES		131,642			122,073			268,411			282,594
INCOME TAXES		55,752			46,275			115,623			118,637
NET INCOME		75,890			75,798			152,788			163,957
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(3,449	)		(2,114	)		(10,347	)		(6,344	)
Unrealized gain on derivative hedges		69			69			207			235
Other comprehensive loss		(3,380	)		(2,045	)		(10,140	)		(6,109	)
Income tax benefit related to other comprehensive loss		(1,469	)		(994	)		(4,408	)		(2,973	)
Other comprehensive loss, net of tax		(1,911	)		(1,051	)		(5,732	)		(3,136	)
TOTAL COMPREHENSIVE INCOME	$	73,979		$	74,747		$	147,056		$	160,821
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an
integral part of these statements.

81

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	38		$	94
Receivables-
Customers (less accumulated provisions of $4,115,000 and $3,691,000,
respectively, for uncollectible accounts)		386,037			321,026
Associated companies		45			21,297
Other		51,020			59,244
Notes receivable - associated companies		17,874			18,428
Prepaid taxes		81,540			1,012
Other		2,059			17,603
		538,613			438,704
UTILITY PLANT:
In service		4,297,036			4,175,125
Less - Accumulated provision for depreciation		1,547,099			1,516,997
		2,749,937			2,658,128
Construction work in progress		65,095			90,508
		2,815,032			2,748,636
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		183,152			176,512
Nuclear plant decommissioning trusts		158,418			175,869
Other		2,176			2,083
		343,746			354,464
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		1,295,024			1,595,662
Goodwill		1,814,976			1,826,190
Pension Assets		122,332			100,615
Other		14,959			16,307
		3,247,291			3,538,774
	$	6,944,682		$	7,080,578
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	28,713		$	27,206
Short-term borrowings-
Associated companies		142,617			130,381
Accounts payable-
Associated companies		10,541			7,541
Other		226,947			193,848
Accrued interest		26,594			9,318
Cash collateral from suppliers		23,510			583
Other		123,273			105,827
		582,195			474,704
CAPITALIZATION:
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares-
14,421,637 shares outstanding		144,216			144,216
Other paid-in capital		2,648,732			2,655,941
Accumulated other comprehensive loss		(25,613	)		(19,881	)
Retained earnings		204,376			237,588
Total common stockholder's equity		2,971,711			3,017,864
Long-term debt and other long-term obligations		1,540,208			1,560,310
		4,511,919			4,578,174
NONCURRENT LIABILITIES:
Power purchase contract loss liability		602,626			749,671
Accumulated deferred income taxes		791,220			800,214
Nuclear fuel disposal costs		195,688			192,402
Asset retirement obligations		93,798			89,669
Other		167,236			195,744
		1,850,568			2,027,700
COMMITMENTS AND CONTINGENCIES (Note 11)
	$	6,944,682		$	7,080,578
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these balance sheets.

82

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months
	Ended September 30
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	152,788		$	163,957
Adjustments to reconcile net income to net cash from operating activities -
Provision for depreciation		70,030			63,867
Amortization of regulatory assets		280,980			296,955
Deferred purchased power and other costs		(132,820	)		(157,201	)
Deferred income taxes and investment tax credits, net		1,051			(23,786	)
Accrued compensation and retirement benefits		(32,087	)		(17,543	)
Cash collateral received from (returned to) suppliers		23,138			(32,243	)
Pension trust contribution		-			(17,800	)
Decrease (increase) in operating assets-
Receivables		(43,742	)		(149,024	)
Materials and supplies		348			127
Prepaid taxes		(62,148	)		(28,337	)
Other current assets		(114	)		2,079
Increase (decrease) in operating liabilities-
Accounts payable		36,099			(6,598	)
Accrued taxes		2,082			29,318
Accrued interest		17,276			13,062
Tax collections payable		(12,493	)		(12,478	)
Other		24,705			2,534
Net cash provided from operating activities		325,093			126,889
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			549,999
Short-term borrowings, net		12,236			-
Redemptions and Repayments-
Long-term debt		(19,138	)		(324,256	)
Short-term borrowings, net		-			(31,145	)
Common Stock		-			(125,000	)
Dividend Payments-
Common stock		(186,000	)		(43,000	)
Net cash provided from (used for) financing activities		(192,902	)		26,598
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(136,265	)		(144,668	)
Proceeds from asset sales		20,000			-
Loan repayments from associated companies, net		553			1,722
Sales of investment securities held in trusts		186,564			169,649
Purchases of investment securities held in trusts		(199,699	)		(181,794	)
Other		(3,400	)		1,640
Net cash used for investing activities		(132,247	)		(153,451	)
Net increase (decrease) in cash and cash equivalents		(56	)		36
Cash and cash equivalents at beginning of period		94			41
Cash and cash equivalents at end of period	$	38		$	77
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.

83

METROPOLITAN EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

Results of Operations

Net income decreased to $64 million in the first nine months of 2008, compared to $76 million in the same period of 2007. The decrease was primarily due to higher purchased power and other operating costs, partially offset by higher revenues and deferrals of new regulatory assets.

Revenues

Revenues increased by $105 million, or 9.2%, in the first nine months of 2008 principally due to higher wholesale generation revenues. Wholesale revenues increased by $96million in the first nine months of 2008, compared to the same period of 2007, primarily reflecting higher spot market prices for PJM market participants. Increased distribution throughput revenues were partially offset by decreases in retail generation revenues and PJM transmission revenues.

In the first nine months of 2008, retail generation revenues decreased $1million primarily due to lower KWH sales to the residential and industrial customer classes, 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 the first nine months of 2008 compared to the same period of 2007 are summarized in the following tables:

	Increase
Retail Generation KWH Sales	(Decrease)
Residential		(0.8	)%
Commercial		1.8	%
Industrial		(3.4	)%
Net Decrease in Retail Generation Sales		(0.7	)%

	Increase
Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	(1	)
Commercial		4
Industrial		(4	)
Net Decrease in Retail Generation Revenues	$	(1	)

Revenues from distribution throughput increased $27 million in the first nine months of 2008, compared to the same period in 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), were partially offset by decreased distribution rates. Decreased KWH deliveries in the residential and industrial customer classes were partially offset by increased KWH deliveries to commercial customers.

Changes in distribution KWH deliveries and revenues in the first nine months of 2008 compared to the same period of 2007 are summarized in the following tables:

84

	Increase
Distribution KWH Deliveries	(Decrease)
Residential		(0.8	)%
Commercial		1.8	%
Industrial		(3.4	)%
Net Decrease in Distribution Deliveries		(0.7	)%

Distribution Revenues	Increase
	(In millions)
Residential	$	11
Commercial		11
Industrial		5
Increase in Distribution Revenues	$	27

PJM transmission revenues decreased by $18million in the first nine months of 2008 compared to the same period of 2007, primarily due to decreased PJM FTR revenue. Met-Ed defers the difference between transmission revenues and net transmission costs incurred in PJM, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses increased by $116 million in the first nine months of 2008 compared to the same period of 2007. The following table presents changes from the prior year by expense category:

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	96
Other operating costs		35
Provision for depreciation		2
Amortization of regulatory assets		(1	)
Deferral of new regulatory assets		(18	)
General taxes		2
Net Increase in expenses	$	116

Purchased power costs increased by $96 million in the first nine months of 2008 due to higher composite unit prices from non-affiliates in PJM. Other operating costs increased by $35 million in the first nine months of 2008 primarily due to higher transmission expenses.

The deferral of new regulatory assets increased in the first nine months of 2008 primarily due to increased transmission cost deferrals ($29 million) and universal service charge deferrals ($4 million), partially offset by the absence of the 2007 deferral of previously expensed decommissioning costs ($15 million) for the Saxton nuclear research facility (see Regulatory Matters).

Other Expense

Other expense increased $8 million in the first nine months of 2008 primarily due to a decrease in interest earned on stranded regulatory assets, reflecting lower regulatory asset balances, and reduced life insurance investment values, partially offset by lower interest expense.

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.

85

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Metropolitan Edison Company:

We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of September 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2008 and 2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2008

86

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months						Nine Months
	Ended September 30						Ended September 30
	2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales	$	434,742		$	391,083		$	1,188,171		$	1,087,460
Gross receipts tax collections		20,793			19,524			59,669			55,146
Total revenues		455,535			410,607			1,247,840			1,142,606
EXPENSES:
Purchased power		245,699			209,842			680,424			584,249
Other operating costs		126,659			106,104			350,704			315,227
Provision for depreciation		11,394			11,154			33,446			31,969
Amortization of regulatory assets		34,642			36,853			101,383			101,965
Deferral of new regulatory assets		(30,962	)		(19,151	)		(111,545	)		(93,772	)
General taxes		23,030			21,986			64,887			63,208
Total expenses		410,462			366,788			1,119,299			1,002,846
OPERATING INCOME		45,073			43,819			128,541			139,760
OTHER INCOME (EXPENSE):
Interest income		4,016			7,239			14,368			22,740
Miscellaneous income		88			1,366			568			3,973
Interest expense		(11,014	)		(13,291	)		(33,666	)		(38,471	)
Capitalized interest		93			292			73			940
Total other expense		(6,817	)		(4,394	)		(18,657	)		(10,818	)
INCOME BEFORE INCOME TAXES		38,256			39,425			109,884			128,942
INCOME TAXES		16,270			14,737			45,866			53,145
NET INCOME		21,986			24,688			64,018			75,797
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(2,233	)		(1,452	)		(6,699	)		(4,357	)
Unrealized gain on derivative hedges		84			83			252			251
Other comprehensive loss		(2,149	)		(1,369	)		(6,447	)		(4,106	)
Income tax benefit related to other comprehensive loss		(971	)		(693	)		(2,912	)		(2,078	)
Other comprehensive loss, net of tax		(1,178	)		(676	)		(3,535	)		(2,028	)
TOTAL COMPREHENSIVE INCOME	$	20,808		$	24,012		$	60,483		$	73,769
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these statements.

87

METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	129		$	135
Receivables-
Customers (less accumulated provisions of $3,905,000 and $4,327,000
respectively, for uncollectible accounts)		149,363			142,872
Associated companies		22,060			27,693
Other		21,130			18,909
Notes receivable from associated companies		11,412			12,574
Prepaid taxes		19,626			14,615
Other		481			1,348
		224,201			218,146
UTILITY PLANT:
In service		2,044,493			1,972,388
Less - Accumulated provision for depreciation		770,510			751,795
		1,273,983			1,220,593
Construction work in progress		32,801			30,594
		1,306,784			1,251,187
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		256,366			286,831
Other		982			1,360
		257,348			288,191
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		418,568			424,313
Regulatory assets		540,785			494,947
Pension assets		59,740			51,427
Other		30,714			36,411
		1,049,807			1,007,098
	$	2,838,140		$	2,764,622
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	28,500		$	-
Short-term borrowings-
Associated companies		65,286			185,327
Other		250,000			100,000
Accounts payable-
Associated companies		23,643			29,855
Other		63,656			66,694
Accrued taxes		2,483			16,020
Accrued interest		7,273			6,778
Other		30,858			27,393
		471,699			432,067
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,500 shares outstanding		1,198,206			1,203,186
Accumulated other comprehensive loss		(18,932	)		(15,397	)
Accumulated deficit		(75,139	)		(139,157	)
Total common stockholder's equity		1,104,135			1,048,632
Long-term debt and other long-term obligations		513,721			542,130
		1,617,856			1,590,762
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		455,898			438,890
Accumulated deferred investment tax credits		7,922			8,390
Nuclear fuel disposal costs		44,205			43,462
Asset retirement obligations		168,367			160,726
Retirement benefits		5,252			8,681
Other		66,941			81,644
		748,585			741,793
COMMITMENTS AND CONTINGENCIES (Note 11)
	$	2,838,140		$	2,764,622
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an
integral part of these balance sheets.

88

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months
	Ended September 30
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	64,018		$	75,797
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		33,446			31,969
Amortization of regulatory assets		101,383			101,965
Deferred costs recoverable as regulatory assets		(9,673	)		(53,276	)
Deferral of new regulatory assets		(111,545	)		(93,772	)
Deferred income taxes and investment tax credits, net		39,919			20,514
Accrued compensation and retirement benefits		(18,948	)		(14,404	)
Cash collateral		-			1,650
Pension trust contribution		-			(11,012	)
Decrease (increase) in operating assets-
Receivables		(19,751	)		(57,599	)
Prepayments and other current assets		(4,144	)		7,227
Increase (decrease) in operating liabilities-
Accounts payable		(9,250	)		(79,316	)
Accrued taxes		(13,285	)		3,024
Accrued interest		495			(153	)
Other		13,510			11,386
Net cash provided from (used for) operating activities		66,175			(56,000	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		28,500			-
Short-term borrowings, net		29,959			193,324
Redemptions and Repayments-
Long-term debt		(28,640	)		(50,000	)
Net cash provided from financing activities		29,819			143,324
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(87,536	)		(74,812	)
Sales of investment securities held in trusts		131,915			153,943
Purchases of investment securities held in trusts		(140,429	)		(162,573	)
Loans from (to) associated companies, net		1,163			(3,511	)
Other		(1,113	)		(375	)
Net cash used for investing activities		(96,000	)		(87,328	)
Net decrease in cash and cash equivalents		(6	)		(4	)
Cash and cash equivalents at beginning of period		135			130
Cash and cash equivalents at end of period	$	129		$	126
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an
integral part of these statements.

89

PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

Results of Operations

Net income decreased to $62 million in the first nine months of 2008, compared to $74 million in the same period of 2007. The decrease was primarily due to increased purchased power costs, net amortization of regulatory assets, interest expense and other operating costs, partially offset by higher revenues.

Revenues

Revenues increased by $96 million, or 9.2%, in the first nine months of 2008 primarily due to higher retail and wholesale generation revenues, distribution throughput revenues and PJM transmission revenues. Wholesale revenues increased $76 million in the first nine months of 2008, compared to the same period of 2007, primarily reflecting higher spot market prices for PJM market participants.

In the first nine months of 2008, retail generation revenues increased $3 million primarily due to higher composite unit prices in all customer classes and higher KWH sales to commercial customers, partially offset by a slight decrease in KWH sales to industrial customers.

Changes in retail generation sales and revenues in the first nine months of 2008 compared to the same period of 2007 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)
Residential		-
Commercial		0.7	%
Industrial		(0.3	) %
Net Increase in Retail Generation Sales		0.2	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	1
Commercial		2
Industrial		-
Increase in Retail Generation Revenues	$	3

Revenues from distribution throughput increased $7 million in the first nine months of 2008 compared to the same period of 2007. Higher usage in the commercial and industrial 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), was partially offset by a decrease in distribution rates.

Changes in distribution KWH deliveries and revenues in the first nine months of 2008 compared to the same period of 2007 are summarized in the following tables:

Distribution KWH Deliveries	Increase
Residential		-
Commercial		0.7	%
Industrial		1.7	%
Increase in Distribution Deliveries		0.8	%

90

Distribution Revenues	Increase (Decrease)
	(In millions)
Residential	$	6
Commercial		2
Industrial		(1	)
Net Increase in Distribution Revenues	$	7

PJM transmission revenues increased by $12 million in the first nine months of 2008 compared to the same period of 2007, primarily due to higher PJM FTR revenue. Penelec defers the difference between transmission revenues and net transmission costs incurred in PJM, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses increased by $105 million in the first nine months of 2008 as compared with the same period of 2007. The following table presents changes from the prior year by expense category:

Expenses - Changes	Increase
	(In millions)
Purchased power costs	$	69
Other operating costs		6
Provision for depreciation		4
Amortization of regulatory assets, net		23
General taxes		3
Increase in expenses	$	105

Purchased power costs increased by $69 million, or 11.7%, in the first nine months of 2008 compared to the same period of 2007, due primarily to higher composite unit prices from non-affiliates in the PJM market. Other operating costs increased by $6 million in the first nine months of 2008, principally due to higher transmission expenses and higher expenses related to Penelec’s customer assistance programs. Depreciation expense increased primarily due to an increase in depreciable property since the third quarter of 2007.

Amortization of regulatory assets (net of deferrals) increased in the first nine months of 2008 primarily due to the absence of the 2007 deferral of previously expensed decommissioning costs ($12 million) for the Saxton nuclear research facility (see Regulatory Matters) and decreased transmission cost deferrals ($16 million), partially offset by an increase in universal service charge deferrals ($5 million).

In the first nine months of 2008, general taxes increased from the same period of 2007, due to higher gross receipts taxes ($4 million), partially offset by lower capital stock taxes ($1 million).

Other Expense

In the first nine months of 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.

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.

91

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Pennsylvania Electric Company:

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of September 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2008 and 2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2008

92

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
		Three Months						Nine Months
		Ended September 30						Ended September 30
		2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales		$	372,576		$	336,798		$	1,083,986		$	991,769
Gross receipts tax collections			17,200			16,637			52,704			48,989
Total revenues			389,776			353,435			1,136,690			1,040,758
EXPENSES:
Purchased power			230,656			203,247			657,681			588,583
Other operating costs			54,727			51,571			175,904			169,299
Provision for depreciation			14,097			12,566			40,531			36,678
Amortization of regulatory assets, net			23,415			20,861			55,346			32,648
General taxes			20,285			19,433			60,485			57,634
Total expenses			343,180			307,678			989,947			884,842
OPERATING INCOME			46,596			45,757			146,743			155,916
OTHER INCOME (EXPENSE):
Miscellaneous income (expense)			(93	)		1,483			774			5,035
Interest expense			(14,934	)		(14,017	)		(45,157	)		(38,426	)
Capitalized interest			57			194			(679	)		737
Total other expense			(14,970	)		(12,340	)		(45,062	)		(32,654	)
INCOME BEFORE INCOME TAXES			31,626			33,417			101,681			123,262
INCOME TAXES			9,058			10,387			39,324			49,025
NET INCOME			22,568			23,030			62,357			74,237
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits			(3,474	)		(2,825	)		(10,421	)		(8,475	)
Unrealized gain on derivative hedges			16			16			48			49
Change in unrealized gain on available-for-sale securities			2			10			(8	)		(6	)
Other comprehensive loss			(3,456	)		(2,799	)		(10,381	)		(8,432	)
Income tax benefit related to other comprehensive loss			(1,510	)		(1,294	)		(4,536	)		(3,894	)
Other comprehensive loss, net of tax			(1,946	)		(1,505	)		(5,845	)		(4,538	)
TOTAL COMPREHENSIVE INCOME		$	20,622		$	21,525		$	56,512		$	69,699
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral
part of these statements.

93

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	36		$	46
Receivables-
Customers (less accumulated provisions of $3,240,000 and $3,905,000
respectively, for uncollectible accounts)		130,427			137,455
Associated companies		57,715			22,014
Other		20,367			19,529
Notes receivable from associated companies		15,406			16,313
Prepaid taxes		31,313			1,796
Other		494			1,281
		255,758			198,434
UTILITY PLANT:
In service		2,290,777			2,219,002
Less - Accumulated provision for depreciation		858,150			838,621
		1,432,627			1,380,381
Construction work in progress		29,503			24,251
		1,462,130			1,404,632
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		128,594			137,859
Non-utility generation trusts		115,938			112,670
Other		299			531
		244,831			251,060
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		771,085			777,904
Pension assets		75,992			66,111
Other		29,610			33,893
		876,687			877,908
	$	2,839,406		$	2,732,034
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	145,000		$	-
Short-term borrowings-
Associated companies		30,483			214,893
Other		250,000			-
Accounts payable-
Associated companies		83,058			83,359
Other		47,796			51,777
Accrued taxes		3,923			15,111
Accrued interest		14,034			13,167
Other		30,297			25,311
		604,591			403,618
CAPITALIZATION:
Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
4,427,577 shares outstanding		88,552			88,552
Other paid-in capital		914,863			920,616
Accumulated other comprehensive income (loss)		(899	)		4,946
Retained earnings		50,300			57,943
Total common stockholder's equity		1,052,816			1,072,057
Long-term debt and other long-term obligations		632,910			777,243
		1,685,726			1,849,300
NONCURRENT LIABILITIES:
Regulatory liabilities		104,927			73,559
Asset retirement obligations		85,748			81,849
Accumulated deferred income taxes		253,798			210,776
Retirement benefits		40,864			41,298
Other		63,752			71,634
		549,089			479,116
COMMITMENTS AND CONTINGENCIES (Note 11)
	$	2,839,406		$	2,732,034
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are
an integral part of these statements.

94

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months
	Ended September 30
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	62,357		$	74,237
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		40,531			36,678
Amortization of regulatory assets, net		55,346			32,648
Deferred costs recoverable as regulatory assets		(20,304	)		(54,228	)
Deferred income taxes and investment tax credits, net		68,377			8,065
Accrued compensation and retirement benefits		(21,190	)		(16,032	)
Cash collateral		-			50
Pension trust contribution		-			(13,436	)
Decrease (increase) in operating assets-
Receivables		(42,971	)		13,809
Prepayments and other current assets		(28,730	)		(4,757	)
Increase (decrease) in operating liabilities-
Accounts payable		(3,437	)		14,299
Accrued taxes		(11,521	)		(4,930	)
Accrued interest		867			6,608
Other		14,663			9,197
Net cash provided from operating activities		113,988			102,208
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		45,000			297,149
Short-term borrowings, net		65,590			53,082
Redemptions and Repayments-
Long-term debt		(45,332	)		-
Common stock		-			(200,000	)
Dividend Payments-
Common stock		(70,000	)		(125,000	)
Net cash provided from (used for) financing activities		(4,742	)		25,231
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(94,810	)		(70,076	)
Loan repayments from associated companies, net		907			2,378
Sales of investment securities held in trust		84,499			94,292
Purchases of investment securities held in trust		(96,950	)		(150,711	)
Other		(2,902	)		(3,328	)
Net cash used for investing activities		(109,256	)		(127,445	)
Net decrease in cash and cash equivalents		(10	)		(6	)
Cash and cash equivalents at beginning of period		46			44
Cash and cash equivalents at end of period	$	36		$	38
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are
an integral part of these statements.

95

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 (i) FES’ and the Utilities’ respective Consolidated Financial Statements and Management’s Narrative Analysis of Results of Operations; (ii) the Combined Notes to Consolidated Financial Statements as they relate to FES and the Utilities; and (iii) FES’ and the Utilities’ respective 2007 Annual Reports on Form 10-K.

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 certain 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 and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return as of September 30, 2008 were $64 million for JCP&L and $64 million for Met-Ed. Regulatory assets not earning a current return are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed. The following table discloses regulatory assets by company:

	September 30,		December 31,		Increase
Regulatory Assets*	2008		2007		(Decrease)
	(In millions)
OE	$	621	$	737	$	(116	)
CEI		796		871		(75	)
TE		145		204		(59	)
JCP&L		1,295		1,596		(301	)
Met-Ed		541		495		46
ATSI		35		42		(7	)
Total	$	3,433	$	3,945	$	(512	)

* Penelec had net regulatory liabilities of approximately $105 million and $74 million as of September 30, 2008 and December 31, 2007, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

96

Ohio (Applicable to OE, CEI and TE)

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 to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 million (OE - $92 million, CEI - $69 million and TE - $28 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 (OE - $114 million, CEI - $79 million and TE - $33 million) of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the deferred fuel costs is addressed in the Ohio Companies’ comprehensive ESP filing, as described below. If the recovery of the deferred fuel costs is not resolved in the ESP, or in the event the MRO is implemented, recovery of the deferred fuel costs will be resolved in the proceeding that was instituted with the PUCO on February 8, 2008, as referenced above.

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 (OE - $156 million, CEI - $108 million and TE - $68 million). On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of 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 (OE - $57 million to $66 million, CEI - $54 million to $61 million and TE - $50 million to $53 million), with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. 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. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $58 million (OE - $38 million, CEI - $13 million and TE - $7 million) of interest costs deferred through September 30, 2008. The Ohio Companies’ electric distribution rate request is addressed in their comprehensive ESP filing, as described below.

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. A utility also may file an MRO in which it would have to prove the following objective market criteria:

·   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;

·   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

·   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 outlines a CBP that would be implemented if the ESP is not approved by the PUCO. Under SB221, a PUCO ruling on the ESP filing is required within 150 days and an MRO decision is required within 90 days. The ESP proposes to phase in new generation rates for customers beginning in 2009 for up to a three-year period and would resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. Major provisions of the ESP include:

·   a phase-in of new generation rates for up to a three-year period, whereby customers would receive a 10% phase-in credit; related costs (expected to approximate $429 million (OE - $198 million, CEI - $150 million and TE - $81 million) in 2009, $488 million (OE - $226 million, CEI - $170 million and TE - $92 million) in 2010 and $553 million (OE - $257 million, CEI - $193 million and TE - $103 million) in 2011) would be deferred for future collection over a period not to exceed 10 years;

·   a reconcilable rider to recover fuel transportation cost surcharges in excess of $30 million in 2009, $20 million in 2010 and $10 million in 2011;

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·   generation rate adjustments to recover any increase in fuel costs in 2011 over fuel costs incurred in 2010 for FES’ generation assets used to support the ESP;

·   generation rate adjustments to recover the costs of complying with new requirements for certain renewable energy resources, new taxes and new environmental laws or new interpretations of existing laws that take effect after January 1, 2008 and exceed $50 million during the plan period;

·   an RCP fuel rider to recover the 2006 and 2007 deferred fuel costs and carrying charges (described above) over a period not to exceed 25 years;

·   the resolution of outstanding issues pending in the Ohio Companies’ distribution rate case (described above), including annual electric distribution rate increases of $75 million for OE, $34.5 million for CEI and $40.5 million for TE. The new distribution rates would be effective January 1, 2009, for OE and TE and May 1, 2009 for CEI, with a commitment to maintain distribution rates through 2013. CEI also would be authorized to defer $25 million in distribution-related costs incurred from January 1, 2009, through April 30, 2009;

·   an adjustable delivery service improvement rider, effective January 1, 2009, through December 31, 2013, to ensure the Ohio Companies maintain and improve customer standards for service and reliability;

·   the waiver of RTC charges for CEI’s customers as of January 1, 2009, which would result in CEI’s write-off of approximately $485 million of estimated unrecoverable transition costs;

·   the continued recovery of transmission costs, including MISO, ancillary services and congestion charges, through an annually adjusted transmission rider; a separate rider will be established to recover costs incurred annually between May 1st and September 30th for capacity purchases required to meet FERC, NERC, MISO and other applicable standards for planning reserve margin requirements in excess of amounts provided by FES as described in the ESP (the separate application for the recovery of these costs was filed on October 17, 2008);

·   a deferred transmission cost recovery rider effective January 1, 2009, through December 31, 2010 to recover transmission costs deferred by the Ohio Companies in 2005 and accumulated carrying charges through December 31, 2008; a deferred distribution cost recovery rider effective January 1, 2011, to recover distribution costs deferred under the RCP, CEI’s additional $25 million of cost deferrals in 2009, line extension deferrals and transition tax deferrals;

·   the deferral of annual storm damage expenses in excess of $13.9 million, certain line extension costs, as well as depreciation, property tax obligations and post in-service carrying charges on energy delivery capital investments for reliability and system efficiency placed in service after December 31, 2008. Effective January 1, 2014, a rider will be established to collect the deferred balance and associated carrying charges over a 10-year period; and

·   a commitment by the Ohio Companies to invest in aggregate at least $1 billion in capital improvements in their energy delivery systems through 2013 and fund $25 million for energy efficiency programs and $25 million for economic development and job retention programs through 2013.

Evidentiary hearings in the ESP case concluded on October 31, 2008 and no further hearings are scheduled. The parties are required to submit initial briefs by November 21, 2008, with all reply briefs due by December 12, 2008.

The Ohio Companies’ MRO filing outlines a CBP for providing retail generation supply if the ESP is not approved by the PUCO or is changed and not accepted by the Ohio Companies. 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. On September 16, 2008, the PUCO staff filed testimony and evidentiary hearings were held. The PUCO failed to act on October 29, 2008 as required under the statute.  The Ohio Companies are unable to predict the outcome of this proceeding.

The Ohio Companies included an interim pricing proposal as part of their ESP filing, if additional time is necessary for final PUCO approval of either the ESP or MRO. FES will be required to obtain FERC authorization to sell electric capacity or energy to the Ohio Companies under the ESP or MRO, unless a waiver is obtained (see FERC Matters).

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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. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC. 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.

Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the Court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. The Commonwealth Court issued its decision on November 7, 2008, which affirmed the PPUC's January 11, 2007 order in all respects, including the deferral and recovery of transmission and congestion related costs.

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 Met-Ed’s and Penelec’s TSC filings.  In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing the company 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 with hearings for both companies scheduled to begin in January 2009. The TSCs include a component for 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 approval from the PPUC of 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. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. As part of the 2008 state budget negotiations, the Alternative Energy Investment Act was enacted 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 8, 2008, House Bill 2200 as amended, was voted out of the full Senate and adopted by the House. On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which becomes 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.

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, request for proposals, 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.

The current legislative session ends on November 30, 2008, and any pending legislation addressing rate mitigation and the expiration of rate caps not enacted by that time must be re-introduced in order to be considered in the next legislative session which begins 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 next year.

On September 25, 2008, Met-Ed and Penelec filed for Commission approval of a Voluntary Prepayment Plan that would provide an opportunity for residential and small commercial customers to pre-pay an amount, which would earn interest at 7.5%, on their monthly electric bills in 2009 and 2010, to be used to reduce electric rates in 2011 and 2012. Met-Ed and Penelec also intend to file a generation procurement plan for 2011 and beyond with the PPUC later this year or early next year. Met-Ed and Penelec requested that the PPUC approve the Plan by mid-December 2008 and are currently awaiting a decision.

New Jersey (Applicable to JCP&L)

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2008, the accumulated deferred cost balance totaled approximately $210 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. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the first half of 2008.

On April 17, 2008, a draft EMP was released for public comment. The final EMP was issued on October 22, 2008 and establishes 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 final EMP will be followed by appropriate legislation and regulation as necessary. At this time, JCP&L cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations.

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 could be issued by the FERC by year-end 2008.  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.

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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. 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 are due on November 10, 2008. 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.

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 is pending before the FERC.

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MISO Ancillary Services Market and Balancing Area Consolidation

MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. These markets would permit generators to sell, and load-serving entities to purchase, their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. Numerous parties filed requests for rehearing on March 26, 2008. On June 23, 2008, the FERC issued an order granting in part and denying in part rehearing.

On February 29, 2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor ASM and Consolidated Balancing Authority Initiative Verification plan and status and Real-Time Operations ASM Reversion plan. FERC action on this compliance filing remains pending. On March 26, 2008, MISO submitted a tariff filing in compliance with the FERC’s 30-day directives in the February 25 order. Numerous parties submitted comments and protests on April 16, 2008. The FERC issued an order accepting the revisions pending further compliance on June 23, 2008. On April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s 60-day directives in the February 25 order. FERC action on this compliance filing remains pending. On May 23, 2008, MISO submitted its amended Balancing Authority Agreement. On July 21, 2008, the FERC issued an order conditionally accepting the amended Balancing Authority Agreement and requiring a further compliance filing.  On August 19, 2008, MISO submitted its compliance filing to the FERC.  On July 25, 2008, MISO submitted another Readiness Certification.  The FERC has not yet acted on this submission.  MISO announced on August 26, 2008 that the startup of its market is postponed indefinitely.  MISO commits to make a filing giving at least sixty days notice of the new effective date. The latest announced effective date for market startup is January 6, 2009.

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.  Upon acceptance by the FERC, this filing will terminate the litigation and the Interconnection Agreement, among other effects.

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. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne zone load-serving entities to pay their PJM capacity obligations through May 31, 2011.

FirstEnergy desires to continue to use its Duquesne zone generation resources to serve load in PJM. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification on whether Duquesne-zone generators could participate in PJM’s May 2008 auction for the 2011-2012 planning year. In the order, the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators could contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with the FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction.

The FERC also directed MISO and PJM to resolve the substantive and procedural issues associated with Duquesne’s transition into MISO. As directed, PJM filed thirteen load-serving entity Capacity Payment Agreements and a Capacity Portability Agreement with the FERC. The Capacity Payment Agreements addressed Duquesne Zone load-serving entity obligations through May 31, 2011 with regards to RPM Capacity while the Capacity Portability Agreement addressed operational issues associated with the portability of such capacity. On September 30, 2008, the FERC approved both agreements, subject to conditions, taking notice of many operational and procedural issues brought forth by FirstEnergy and other market participants.

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Several issues surrounding Duquesne’s transition into MISO continue to be contested at the FERC. Specifically, Duquesne’s obligation to pay for transmission expansion costs allocated to the Duquesne zone when they were a member of PJM, and other issues in which market participants wish to be held harmless by Duquesne’s transition. FirstEnergy filed for rehearing on these issues on October 3, 2008. Duquesne’s transition into MISO is also contingent upon the start of MISO’s ancillary services market and consolidation of its balancing authorities, currently scheduled for January 6, 2009.

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. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by the FERC that established the RPM. In the complaint, the RPM Buyers request that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On July 11, 2008, PJM filed its answer to the complaint, in which it denied the allegation that the rates are unjust and unreasonable. Also on that date, FirstEnergy filed a motion to intervene. 

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 its progress on contemplating adjustments to the RPM as suggested by the Brattle Group in its report reviewing the RPM. The technical conference will take place in February, 2009. On October 20, 2008, the RPM Buyers filed a request for rehearing of the FERC’s September 19, 2008 order.

MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load-serving entities such as the Ohio Companies, Penn 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 purchase 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. Issuance of these orders is not expected to delay the June 1, 2009 start date for MISO Resource Adequacy.

Organized Wholesale Power Markets

The FERC issued a final rule on October 17, 2008, amending its regulations to “improve the operation of organized wholesale electric markets in the areas of: (1) demand response and market pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market-monitoring policies; and (4) the responsiveness of RTOs and ISOs to their customers and other stakeholders.”  The RTOs and ISOs were directed to submit amendments to their respective tariffs to address these market operation improvements.  The final rule directs RTOs to adopt market rules permitting prices to increase during periods of supply shortages and to permit enhanced participation by demand response resources.  It also codifies and defines for the first time the roles and duties of independent market monitors within RTOs.  Finally, it adopts requirements for enhanced access by stakeholders to RTO boards of directors.  RTOs are directed to make compliance filings six months from the effective date of the final rule.  The final rule is not expected to have any material effect on FirstEnergy's operations within MISO and PJM.

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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.  A ruling by the FERC is expected the week of December 15, 2008.

On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and The Waverly Power and Light Company (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 Companies with regard to air and water quality and other environmental matters. The effects of compliance on FES and the Companies 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 estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.

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

Clean Air Act Compliance (Applicable to FES)

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

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

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In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, is 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 $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above. 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. Under the Sammis NSR Litigation consent decree, an election to repower by December 31, 2012, install flue gas desulfurization (FGD) by December 31, 2010, or permanently shut down those units by December 31, 2010, is due no later than December 31, 2008. Although FirstEnergy will meet the December 31, 2008 deadline for making an election, one potential compliance option, should FGD be elected, would be to idle Burger Units 4 and 5 on December 31, 2010 pending completion of the FGD installation. Thus, OE is seeking a determination by the Court whether this approach is indeed in compliance with the terms of the Sammis NSR Litigation consent decree. The Court has scheduled a hearing on OE’s dispute resolution petition for November 17, 2008. The outcome of this dispute resolution process could have an impact on the option FirstEnergy ultimately elects with respect to Burger Units 4 and 5.

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. The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.

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.  By letter dated October 1, 2008, New Jersey informed the Court of its intent to file an amended complaint. Met-Ed is unable to predict the outcome of this matter.

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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. FGCO complied with the modified schedule and otherwise intends to fully comply with the ACO, 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 (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 would have required 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.” The Court ruling also vacated the CAIR regional cap and trade requirements for SO2 and NOX, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. 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 October 21, 2008, the Court ordered the parties who appealed CAIR to file responses to the rehearing petitions by November 5, 2008 and directed them to address (1) whether any party is seeking vacatur of CAIR and (2) whether the Court should stay its vacatur of CAIR until EPA promulgates a revised rule. The future cost of compliance with these regulations may be substantial and will depend on the Court’s ruling on rehearing, as well as the action taken by the EPA or Congress 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. The Supreme Court could grant the EPA’s petition and alter some or all of the lower Court’s decision, or 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. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FES’ only Pennsylvania coal-fired power plant, until 2015, if at all.

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Climate Change (Applicable to FES)

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, 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.

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 (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 is scheduled for December 2, 2008. 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.

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.

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Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.  As of September 30, 2008, FirstEnergy had approximately $1.9 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 September 30, 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 $94 million (JCP&L - $68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $24 million) have been accrued through September 30, 2008. Included in the total for JCP&L are accrued liabilities of approximately $57 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 September 30, 2008.

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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 OE, JCP&L and FES)

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

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint, which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint and oral argument was held on November 5, 2008.

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 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 FirstEnergy 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 FirstEnergy’s application of this Standard in periods after implementation will be dependent upon 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 FES’ or the Utilities’ financial statements.

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.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and its subsidiaries FGCO and NGC, and FESC.

FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2007 for FirstEnergy, FES and the Utilities. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utilities reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 9) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.

The consolidated financial statements as of September 30, 2008 and for the three-month and nine-month periods ended September 30, 2008 and 2007, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated November 6, 2008) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.

2.  EARNINGS PER SHARE

Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an accelerated share repurchase program at an initial price of approximately $900 million. A final purchase price adjustment of $51 million was settled in cash on December 13, 2007. The following table reconciles basic and diluted earnings per share of common stock:

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	Three Months				Nine Months
	Ended September 30				Ended September 30
Reconciliation of Basic and Diluted Earnings per Share	2008		2007		2008		2007
	(In millions, except per share amounts)
Net income	$	471	$	413	$	1,010	$	1,041
Average shares of common stock outstanding – Basic		304		304		304		307
Assumed exercise of dilutive stock options and awards		3		3		3		4
Average shares of common stock outstanding – Dilutive		307		307		307		311
Basic earnings per share	$	1.55	$	1.36	$	3.32	$	3.39
Diluted earnings per share	$	1.54	$	1.34	$	3.29	$	3.35

3. GOODWILL

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and more frequently as indicators of impairment arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment is indicated, FirstEnergy recognizes a loss – calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill.

FirstEnergy's 2008 annual review was completed in the third quarter of 2008 with no impairment indicated. As discussed in Note 12(B), the Ohio Companies filed a comprehensive ESP and MRO with the PUCO on July 31, 2008. The annual goodwill impairment analysis assumed management's best estimate of the outcome of those filings. There was no impairment indicated for FirstEnergy and the Ohio Companies based on a probability-weighted outcome of the ESP and MRO proceedings. If the PUCO’s final decision authorizes less revenue recovery than the amounts assumed, an additional impairment analysis would be performed at that time that could result in future goodwill impairment.

FirstEnergy's goodwill primarily relates to its energy delivery services segment. In the first and third quarters of 2008, FirstEnergy adjusted goodwill by $1 million and $23 million, respectively, of the former GPU companies due to the realization of tax benefits that had been reserved under purchase accounting. The following tables reconcile changes to goodwill for the three months and nine months ended September 30, 2008.

Three Months Ended	FirstEnergy			FES		CEI		TE		JCP&L			Met-Ed			Penelec
	(In millions)
Balance as of July 1, 2008	$	5,606		$	24	$	1,689	$	501	$	1,826		$	424		$	778
Adjustments related to GPU acquisition		(23	)		-		-		-		(11	)		(5	)		(7	)
Balance as of September 30, 2008	$	5,583		$	24	$	1,689	$	501	$	1,815		$	419		$	771

Nine Months Ended	FirstEnergy			FES		CEI		TE		JCP&L			Met-Ed			Penelec
	(In millions)
Balance as of January 1, 2008	$	5,607		$	24	$	1,689	$	501	$	1,826		$	425		$	778
Adjustments related to GPU acquisition		(24	)		-		-		-		(11	)		(6	)		(7	)
Balance as of September 30, 2008	$	5,583		$	24	$	1,689	$	501	$	1,815		$	419		$	771

4.  DIVESTITURES AND DISCONTINUED OPERATIONS

On March 7, 2008, FirstEnergy sold certain telecommunication assets, resulting in a net after-tax gain of $19.3 million. The sale of assets did not meet the criteria for classification as discontinued operations as of September 30, 2008.

5.  FAIR VALUE MEASURES

Effective January 1, 2008, FirstEnergy 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. FirstEnergy also adopted SFAS 159 on January 1, 2008, which provides the option to measure certain financial assets and financial liabilities at fair value. FirstEnergy has analyzed its financial assets and financial liabilities within the scope of SFAS 159 and, as of September 30, 2008, has elected not to record eligible assets and liabilities at fair value.

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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. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that are held in various trusts.

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. FirstEnergy’s 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. FirstEnergy develops its 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 FirstEnergy management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. FirstEnergy’s Level 3 instruments consist of NUG contracts.

FirstEnergy utilizes 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. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs.

The following table sets forth FirstEnergy’s financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of September 30, 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. FirstEnergy’s 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.

	September 30, 2008
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
	(In millions)
Assets:
Derivatives	$	-	$	45	$	-	$	45
Nuclear decommissioning trusts		761		1,112		-		1,873
Other investments		19		312		-		331
Total	$	780	$	1,469	$	-	$	2,249
Liabilities:
Derivatives	$	8	$	19	$	-	$	27
NUG contracts(1)		-		-		603		603
Total	$	8	$	19	$	603	$	630

(1)   NUG contracts are completely offset by regulatory assets.

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

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 for the three and nine months ended September 30, 2008:

	Three Months			Nine Months
	(In millions)
Balance at beginning of period	$	644		$	750
Realized and unrealized gains (losses)(1)		(32	)		(120	)
Purchases, sales, issuances and settlements, net(1)		(9	)		(27	)
Net transfers to (from) Level 3		-			-
Balance as of September 30, 2008	$	603		$	603
Change in unrealized gains (losses) relating to
instruments held as of September 30, 2008	$	(32	)	$	(120	)

(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”, FirstEnergy 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 is currently evaluating the impact of SFAS 157 on those financial assets and financial liabilities.

6. DERIVATIVE INSTRUMENTS

FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight for risk management activities throughout FirstEnergy. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.

FirstEnergy accounts for derivative instruments in its Consolidated Balance Sheet at their fair value unless they meet the criteria for the normal purchases and normal sales exception. Derivatives that meet those criteria are accounted for at cost. FirstEnergy regularly assesses derivatives based on the normal purchases and normal sales criteria and expects no changes in eligibility for the normal purchases and normal sales exception. The changes in the fair value of derivative instruments that do not meet the normal purchases and normal sales exception are recorded as other expense, as AOCL, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness. FirstEnergy does not offset fair value for the right to reclaim collateral or the obligation to return collateral.

FirstEnergy hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity, natural gas and other commodity purchases and anticipated interest payments associated with future debt issues. The effective portion of such hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are recognized directly in net income.

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The net deferred losses of $64 million included in AOCL as of September 30, 2008, for derivative hedging activity, as compared to $75 million as of December 31, 2007, resulted from a net $3 million increase related to current hedging activity and a $14 million decrease due to net hedge losses reclassified to earnings during the nine months ended September 30, 2008. Based on current estimates, approximately $16 million (after tax) of the net deferred losses on derivative instruments in AOCL as of September 30, 2008 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors, including commodity prices, counterparty credit and interest rates.

FirstEnergy has entered into swaps that have been designated as fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. In order to reduce counterparty exposure and lessen variable debt exposure under current market conditions, FirstEnergy unwound its remaining interest rate swaps. During the first nine months of 2008, FirstEnergy received $3 million to terminate interest rate swaps with an aggregate notional value of $250 million. As of September 30, 2008, FirstEnergy has no outstanding interest rate swaps hedging fixed-rate long term debt.

During 2007 and the first nine months of 2008, FirstEnergy entered into several forward-starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated issuance of variable-rate short-term debt and fixed-rate long-term debt securities, by one or more of its subsidiaries, as outstanding debt matures during 2008 and 2009. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury and LIBOR rates between the date of hedge inception and the date of the debt issuance. FirstEnergy considers counterparty credit and nonperformance risk in its hedge assessments and continues to expect the forward-starting swaps to be effective in protecting against the risk of changes in future interest payments. During the first nine months of 2008, FirstEnergy terminated swaps with a notional value of $750 million and entered into swaps with a notional value of $950 million. FirstEnergy paid $16 million related to the terminations, $5 million of which was deemed ineffective and recognized in current period earnings. FirstEnergy will recognize the remaining loss over the life of the associated future debt. As of September 30, 2008, FirstEnergy had forward swaps with an aggregate notional amount of $600 million and a fair value of $(0.2) million.

7. ASSET RETIREMENT OBLIGATIONS

FirstEnergy has recognized applicable legal obligations under SFAS 143 for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, FirstEnergy has recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47.

The ARO of $1.3 billion as of September 30, 2008 is primarily related to the future nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of September 30, 2008, the fair value of the decommissioning trust assets was approximately $1.9 billion.

The following tables analyze changes to the ARO balance during the three months and nine months ended September 30, 2008 and 2007, respectively.

ARO Reconciliation	FirstEnergy			FES			OE			CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Balance, July 1, 2008	$	1,307		$	836		$	96		$	2	$	29	$	92	$	166	$	84
Liabilities incurred		5			-			-			-		-		-		-		-
Liabilities settled		(1	)		(1	)		-			-		-		-		-		-
Accretion		21			14			1			-		1		2		2		2
Revisions in estimated cash flows		(18	)		-			(18	)		-		-		-		-		-
Balance, September 30, 2008	$	1,314		$	849		$	79		$	2	$	30	$	94	$	168	$	86
Balance, July 1, 2007	$	1,228		$	784		$	91		$	2	$	27	$	87	$	156	$	79
Liabilities incurred		-			-			-			-		-		-		-		-
Liabilities settled		-			-			-			-		-		-		-		-
Accretion		19			13			1			-		1		1		2		2
Revisions in estimated cash flows		-			-			-			-		-		-		-		-
Balance, September 30, 2007	$	1,247		$	797		$	92		$	2	$	28	$	88	$	158	$	81

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ARO Reconciliation	FirstEnergy			FES			OE			CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Balance, January 1, 2008	$	1,267		$	810		$	94		$	2	$	28	$	90	$	161	$	82
Liabilities incurred		5			-			-			-		-		-		-		-
Liabilities settled		(2	)		(1	)		(1	)		-		-		-		-		-
Accretion		62			40			4			-		2		4		7		4
Revisions in estimated cash flows		(18	)		-			(18	)		-		-		-		-		-
Balance, September 30, 2008	$	1,314		$	849		$	79		$	2	$	30	$	94	$	168	$	86
Balance, January 1, 2007	$	1,190		$	760		$	88		$	2	$	27	$	84	$	151	$	77
Liabilities incurred		-			-			-			-		-		-		-		-
Liabilities settled		(2	)		(1	)		-			-		-		-		-		-
Accretion		59			38			4			-		1		4		7		4
Revisions in estimated cash flows		-			-			-			-		-		-		-		-
Balance, September 30, 2007	$	1,247		$	797		$	92		$	2	$	28	$	88	$	158	$	81

8. PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its subsidiaries’ employees. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December 31, 2007. FirstEnergy also provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

The components of FirstEnergy's net periodic pension cost and other postretirement benefit cost (including amounts capitalized) for the three months and nine months ended September 30, 2008 and 2007, consisted of the following:

	Three Months						Nine Months
	Ended September 30						Ended September 30
Pension Benefits	2008			2007			2008			2007
	(In millions)
Service cost	$	21		$	21		$	62		$	63
Interest cost		72			71			217			213
Expected return on plan assets		(116	)		(112	)		(347	)		(337	)
Amortization of prior service cost		3			2			7			7
Recognized net actuarial loss		1			10			4			31
Net periodic cost (credit)	$	(19	)	$	(8	)	$	(57	)	$	(23	)

	Three Months						Nine Months
	Ended September 30						Ended September 30
Other Postretirement Benefits	2008			2007			2008			2007
	(In millions)
Service cost	$	5		$	5		$	14		$	16
Interest cost		18			17			55			52
Expected return on plan assets		(13	)		(12	)		(38	)		(38	)
Amortization of prior service cost		(37	)		(37	)		(111	)		(112	)
Recognized net actuarial loss		12			11			35			34
Net periodic cost (credit)	$	(15	)	$	(16	)	$	(45	)	$	(48	)

Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. FES and the Utilities capitalize employee benefits related to construction projects. The net periodic pension costs and net periodic postretirement benefit costs (including amounts capitalized) recognized by FES and each of the Utilities for the three months and nine months ended September 30, 2008 and 2007 were as follows:

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	Three Months						Nine Months
	Ended September 30						Ended September 30
Pension Benefit Cost (Credit)	2008			2007			2008			2007
	(In millions)
FES	$	4		$	5		$	11		$	16
OE		(6	)		(4	)		(20	)		(12	)
CEI		(1	)		-			(3	)		1
TE		(1	)		-			(2	)		-
JCP&L		(4	)		(2	)		(11	)		(7	)
Met-Ed		(3	)		(2	)		(8	)		(5	)
Penelec		(3	)		(2	)		(10	)		(8	)
Other FirstEnergy subsidiaries		(5	)		(3	)		(14	)		(8	)
	$	(19	)	$	(8	)	$	(57	)	$	(23	)

	Three Months						Nine Months
	Ended September 30						Ended September 30
Other Postretirement Benefit Cost (Credit)	2008			2007			2008			2007
	(In millions)
FES	$	(2	)	$	(2	)	$	(5	)	$	(7	)
OE		(2	)		(3	)		(5	)		(8	)
CEI		1			1			2			3
TE		1			1			3			4
JCP&L		(4	)		(4	)		(12	)		(12	)
Met-Ed		(3	)		(3	)		(8	)		(8	)
Penelec		(3	)		(3	)		(10	)		(10	)
Other FirstEnergy subsidiaries		(3	)		(3	)		(10	)		(10	)
	$	(15	)	$	(16	)	$	(45	)	$	(48	)

Under the Pension Protection Act of 2006, companies are generally required make a scheduled series of contributions to fund 100% of outstanding qualified pension benefit obligations over a seven year period. As of December 31, 2007, FirstEnergy’s pension plan was overfunded, and, therefore, FirstEnergy will not be required to make any contributions in 2009 for the 2008 plan year. However, the overall actual asset return as of December 31, 2008 may reduce the value of the pension plan’s assets to the level where contributions would be required in 2010 for the 2009 plan year.

9. VARIABLE INTEREST ENTITIES

FIN 46R addresses the consolidation of VIEs, including special-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the entity's residual economic risks and rewards. FirstEnergy and its subsidiaries consolidate a VIE when they are determined to be the VIE's primary beneficiary as defined by FIN 46R.

Mining Operations

On July 16, 2008, FirstEnergy Ventures Corp., a subsidiary of FirstEnergy, entered into a joint venture with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake in the Signal Peak mining and coal transportation operations near Roundup, Montana. FirstEnergy made a $125 million equity investment in the joint venture, which acquired 80% of the mining operations (Signal Peak Energy, LLC) and 100% of the transportation operations, with FirstEnergy Ventures Corp. owning a 45% economic interest and an affiliate of the Boich Companies owning a 55% economic interest in the joint venture. Both parties have a 50% voting interest in the joint venture. After January 2010, the joint venture will have 18 months to exercise an option to acquire the remaining 20% stake in the mining operations. In accordance with FIN 46R, FirstEnergy is including the limited liability companies created for the mining and transportation operations of this joint venture in its consolidated financial statements.

Trusts

FirstEnergy’s consolidated financial statements include PNBV and Shippingport, VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.

PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.

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Loss Contingencies

FES and the Ohio Companies are exposed to losses under their applicable sale and 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 as of September 30, 2008:

	Maximum Exposure		Discounted Lease Payments, net		Net Exposure
	(in millions)
FES	$	1,363	$	1,209	$	154
OE	788		597		191
CEI	718		79		639
TE	718		421		297

In October 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO, which 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 2007 Bruce Mansfield Unit 1 sale and leaseback transaction to a newly formed wholly-owned subsidiary in December 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE will remain primarily liable on the 1987 leases and related agreements as to the lessors and other parties to the 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. Also in the second quarter of 2008, NGC purchased 158.5 MW of lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2, which purchases were undertaken in connection with the previously disclosed exercise of the periodic purchase option provided in the TE and CEI sale and leaseback arrangements. The Ohio Companies continue to lease these MW under the respective sale and leaseback arrangements and the related lease debt remains outstanding.

Power Purchase Agreements

In accordance with FIN 46R, FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately 30 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. As required by FIN 46R, FirstEnergy periodically requests from these eight entities the information necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R.

Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it may incur for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs from these entities during the three months and nine months ended September 30, 2008 and 2007 are shown in the following table:

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	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(In millions)
JCP&L	$	26	$	30	$	67	$	71
Met-Ed		12		13		44		40
Penelec		8		7		25		22
Total	$	46	$	50	$	136	$	133

Transition Bonds

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

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of September 30, 2008, $377 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 - principally bondable transition property.

Bondable transition property under New Jersey law represents the irrevocable right of a utility company to charge, collect and receive from its customers, through a non-bypassable transition bond charge (TBC), the principal amount and interest on transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate quarterly servicing fees of $157,000 payable from TBC collections.

10. INCOME TAXES

FirstEnergy accounts for uncertainty in income taxes recognized in a company’s financial statements in accordance with FIN 48. This interpretation prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. FIN 48 also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation is a two-step process. The first step is to determine if it is more likely than not that a tax position will be sustained upon examination, based on the merits of the position, and should therefore be recognized. The second step is to measure a tax position that meets the more likely than not recognition threshold to determine the amount of income tax benefit to recognize in the financial statements.

Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate, if recognized in 2008. The majority of items that would not affect the 2008 effective tax rate would be purchase accounting adjustments to goodwill, if recognized in 2008. Upon completion of the federal tax examinations for tax years 2004 to 2006 in the third quarter of 2008, FirstEnergy recognized approximately $45 million in tax benefits, including $5 million that favorably affected FirstEnergy’s effective tax rate. A majority of the tax benefits recognized in the third quarter of 2008 adjusted goodwill as a purchase accounting adjustment ($20 million) and accumulated deferred income taxes for temporary tax items ($15 million). During the first nine months of 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of September 30, 2008, FirstEnergy expects that it is reasonably possible that approximately $151 million of the unrecognized benefits may be resolved within the next twelve months, of which $54 million to $147 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs capital gains and losses recognized on the disposition of assets and various other tax items.

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FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. The reversal of accrued interest associated with the $45 million in recognized tax benefits favorably affected FirstEnergy’s effective tax rate by $12 million in the third quarter and first nine months of 2008 and an interest receivable of $4 million was removed from the accrued interest for FIN 48 items. The net amount of interest accrued as of September 30, 2008 was $56 million, as compared to $53 million as of December 31, 2007.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2007. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audits for the years 2004-2006 were completed in the third quarter of 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 and the year 2008 in February 2008 under its Compliance Assurance Process program. Neither audit is expected to close before December 2008. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

11.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A)    GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of September 30, 2008, outstanding guarantees and other assurances aggregated approximately $4.2 billion, consisting of parental guarantees - $0.9 billion, subsidiaries’ guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $0.5 billion.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4 billion (included in the $0.9 billion discussed above) as of September 30, 2008 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of September 30, 2008, FirstEnergy's maximum exposure under these collateral provisions was $573 million, consisting of $64 million due to “material adverse event” contractual clauses and $509 million due to a below investment grade credit rating. Additionally, stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase this amount to $648 million, consisting of $58 million due to “material adverse event” contractual clauses and $590 million due to a below investment grade credit rating.

FES, through potential participation in utility sponsored competitive power procurement processes (including those of affiliates) or through forward hedging transactions and as a consequence of future power price movements, could be required to post significantly higher collateral to support its power transactions.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $94 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

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 Note 15). 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.

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On October 8, 2008, to enhance their liquidity position in the face of the turbulent credit and bond markets, FirstEnergy and its subsidiaries, 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. Once repaid, borrowings may not be re-borrowed.

In early October 2008, FirstEnergy took steps to further enhance its liquidity position by negotiating 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 - $156 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. As a result of these negotiations, a total of approximately $902 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.

(B)    ENVIRONMENTAL MATTERS

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

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

Clean Air Act Compliance

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

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

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

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In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, is 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 $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above. 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. Under the Sammis NSR Litigation consent decree, an election to repower by December 31, 2012, install flue gas desulfurization (FGD) by December 31, 2010, or permanently shut down those units by December 31, 2010, is due no later than December 31, 2008. Although FirstEnergy will meet the December 31, 2008 deadline for making an election, one potential compliance option, should FGD be elected, would be to idle Burger Units 4 and 5 on December 31, 2010 pending completion of the FGD installation. Thus, OE is seeking a determination by the Court whether this approach is indeed in compliance with the terms of the Sammis NSR Litigation consent decree. The Court has scheduled a hearing on OE’s dispute resolution petition for November 17, 2008. The outcome of this dispute resolution process could have an impact on the option FirstEnergy ultimately elects with respect to Burger Units 4 and 5.

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.   The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.

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.  By letter dated October 1, 2008, New Jersey informed the Court of its intent to file an amended complaint. Met-Ed is unable to predict the outcome of this matter.

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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. FGCO complied with the modified schedule and otherwise intends to fully comply with the ACO, 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 would have required 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.” The Court ruling also vacated the CAIR regional cap and trade requirements for SO2 and NOX, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. 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 October 21, 2008, the Court ordered the parties who appealed CAIR to file responses to the rehearing petitions by November 5, 2008 and directed them to address (1) whether any party is seeking vacatur of CAIR and (2) whether the Court should stay its vacatur of CAIR until EPA promulgates a revised rule. The future cost of compliance with these regulations may be substantial and will depend on the Court’s ruling on rehearing, as well as the action taken by the EPA or Congress in response to the Court’s ruling.

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. The Supreme Court could grant the EPA’s petition and alter some or all of the lower Court’s decision, or 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. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.

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Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, 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.

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.

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

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the 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 is scheduled for December 2, 2008. FirstEnergy 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.

Regulation of Hazardous Waste

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

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Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.  As of September 30, 2008, FirstEnergy had approximately $1.9 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 September 30, 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 $94 million (JCP&L - $68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $24 million) have been accrued through September 30, 2008. Included in the total for JCP&L are accrued liabilities of approximately $57 million for environmental remediation of former manufactured gas plants in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

(C)    OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

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

In August 2002, the trial Court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial Court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007.  Proceedings are continuing in the Superior Court 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 September 30, 2008.

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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.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint, which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint and oral argument was held on November 5, 2008.

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. FirstEnergy has a strike mitigation plan ready in the event of a strike.

FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

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12.  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.

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

In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the 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, ReliabilityFirst scheduled a compliance audit of FirstEnergy’s bulk-power system within the PJM region in October 2008. FirstEnergy currently does 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 to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 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 is addressed in the Ohio Companies’ comprehensive ESP filing, as described below. If the recovery of the deferred fuel costs is not resolved in the ESP, or in the event the MRO is implemented, recovery of the deferred fuel costs will be resolved in the proceeding that was instituted with the PUCO on February 8, 2008, as referenced above.

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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. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. 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. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $58 million of interest costs deferred through September 30, 2008 ($0.12 per share of common stock). The Ohio Companies’ electric distribution rate request is addressed in their comprehensive ESP filing, as described below.

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. A utility also may file an MRO in which it would have to prove the following objective market criteria:

·   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;

·   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

·   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 outlines a CBP that would be implemented if the ESP is not approved by the PUCO. Under SB221, a PUCO ruling on the ESP filing is required within 150 days and an MRO decision is required within 90 days. The ESP proposes to phase in new generation rates for customers beginning in 2009 for up to a three-year period and would resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. Major provisions of the ESP include:

·   a phase-in of new generation rates for up to a three-year period, whereby customers would receive a 10% phase-in credit; related costs (expected to approximate $429 million in 2009, $488 million in 2010 and $553 million in 2011) would be deferred for future collection over a period not to exceed 10 years;

·   a reconcilable rider to recover fuel transportation cost surcharges in excess of $30 million in 2009, $20 million in 2010 and $10 million in 2011;

·   generation rate adjustments to recover any increase in fuel costs in 2011 over fuel costs incurred in 2010 for FES’ generation assets used to support the ESP;

·   generation rate adjustments to recover the costs of complying with new requirements for certain renewable energy resources, new taxes and new environmental laws or new interpretations of existing laws that take effect after January 1, 2008 and exceed $50 million during the plan period;

·   an RCP fuel rider to recover the 2006 and 2007 deferred fuel costs and carrying charges (described above) over a period not to exceed 25 years;

·   the resolution of outstanding issues pending in the Ohio Companies’ distribution rate case (described above), including annual electric distribution rate increases of $75 million for OE, $34.5 million for CEI and $40.5 million for TE. The new distribution rates would be effective January 1, 2009, for OE and TE and May 1, 2009 for CEI, with a commitment to maintain distribution rates through 2013. CEI also would be authorized to defer $25 million in distribution-related costs incurred from January 1, 2009, through April 30, 2009;

·   an adjustable delivery service improvement rider, effective January 1, 2009, through December 31, 2013, to ensure the Ohio Companies maintain and improve customer standards for service and reliability;

·   the waiver of RTC charges for CEI’s customers as of January 1, 2009, which would result in CEI’s write-off of approximately $485 million of estimated unrecoverable transition costs ($1.01 per share of common stock);

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·   the continued recovery of transmission costs, including MISO, ancillary services and congestion charges, through an annually adjusted transmission rider; a separate rider will be established to recover costs incurred annually between May 1st and September 30th for capacity purchases required to meet FERC, NERC, MISO and other applicable standards for planning reserve margin requirements in excess of amounts provided by FES as described in the ESP (the separate application for the recovery of these costs was filed on October 17, 2008);

·   a deferred transmission cost recovery rider effective January 1, 2009, through December 31, 2010 to recover transmission costs deferred by the Ohio Companies in 2005 and accumulated carrying charges through December 31, 2008; a deferred distribution cost recovery rider effective January 1, 2011, to recover distribution costs deferred under the RCP, CEI’s additional $25 million of cost deferrals in 2009, line extension deferrals and transition tax deferrals;

·   the deferral of annual storm damage expenses in excess of $13.9 million, certain line extension costs, as well as depreciation, property tax obligations and post in-service carrying charges on energy delivery capital investments for reliability and system efficiency placed in service after December 31, 2008. Effective January 1, 2014, a rider will be established to collect the deferred balance and associated carrying charges over a 10-year period; and

·   a commitment by the Ohio Companies to invest in aggregate at least $1 billion in capital improvements in their energy delivery systems through 2013 and fund $25 million for energy efficiency programs and $25 million for economic development and job retention programs through 2013.

Evidentiary hearings in the ESP case concluded on October 31, 2008 and no further hearings are scheduled. The parties are required to submit initial briefs by November 21, 2008, with all reply briefs due by December 12, 2008.

The Ohio Companies’ MRO filing outlines a CBP for providing retail generation supply if the ESP is not approved by the PUCO or is changed and not accepted by the Ohio Companies. 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. On September 16, 2008, the PUCO staff filed testimony and evidentiary hearings were held. The PUCO failed to act on October 29, 2008 as required under the statute.  The Ohio Companies are unable to predict the outcome of this proceeding.

The Ohio Companies included an interim pricing proposal as part of their ESP filing, if additional time is necessary for final PUCO approval of either the ESP or MRO. FES will be required to obtain FERC authorization to sell electric capacity or energy to the Ohio Companies under the ESP or MRO, unless a waiver is obtained (see FERC Matters).

(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. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC. 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.

Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

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The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the Court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. The Commonwealth Court issued its decision on November 7, 2008, which affirmed the PPUC's January 11, 2007 order in all respects, including the deferral and recovery of transmission and congestion related costs.

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 Met-Ed’s and Penelec’s TSC filings.  In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing the company 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 with hearings for both companies scheduled to begin in January 2009. The TSCs include a component for 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 approval from the PPUC of 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. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. As part of the 2008 state budget negotiations, the Alternative Energy Investment Act was enacted 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 8, 2008, House Bill 2200 as amended, was voted out of the full Senate and adopted by the House. On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which becomes 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.

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, request for proposals, 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;

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·   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.

The current legislative session ends on November 30, 2008, and any pending legislation addressing rate mitigation and the expiration of rate caps not enacted by that time must be re-introduced in order to be considered in the next legislative session which begins 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 next year.

On September 25, 2008, Met-Ed and Penelec filed for Commission approval of a Voluntary Prepayment Plan that would provide an opportunity for residential and small commercial customers to pre-pay an amount, which would earn interest at 7.5%, on their monthly electric bills in 2009 and 2010, to be used to reduce electric rates in 2011 and 2012. Met-Ed and Penelec also intend to file a generation procurement plan for 2011 and beyond with the PPUC later this year or early next year. Met-Ed and Penelec requested that the PPUC approve the Plan by mid-December 2008 and are currently awaiting a decision.

(D)    NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2008, the accumulated deferred cost balance totaled approximately $210 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.

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. 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. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the first half of 2008.

On April 17, 2008, a draft EMP was released for public comment. The final EMP was issued on October 22, 2008 and establishes 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;

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·   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 final EMP will be followed by appropriate legislation and regulation as necessary. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations or those of JCP&L.

(E)    FERC MATTERS

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. 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 could be issued by the FERC by year-end 2008.  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.

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. 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 are due on November 10, 2008. 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.

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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 is pending before the FERC.

MISO Ancillary Services Market and Balancing Area Consolidation

MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. These markets would permit generators to sell, and load-serving entities to purchase, their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. Numerous parties filed requests for rehearing on March 26, 2008. On June 23, 2008, the FERC issued an order granting in part and denying in part rehearing.

On February 29, 2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor ASM and Consolidated Balancing Authority Initiative Verification plan and status and Real-Time Operations ASM Reversion plan. FERC action on this compliance filing remains pending. On March 26, 2008, MISO submitted a tariff filing in compliance with the FERC’s 30-day directives in the February 25 order. Numerous parties submitted comments and protests on April 16, 2008. The FERC issued an order accepting the revisions pending further compliance on June 23, 2008. On April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s 60-day directives in the February 25 order. FERC action on this compliance filing remains pending. On May 23, 2008, MISO submitted its amended Balancing Authority Agreement. On July 21, 2008, the FERC issued an order conditionally accepting the amended Balancing Authority Agreement and requiring a further compliance filing. On August 19, 2008, MISO submitted its compliance filing to the FERC. On July 25, 2008, MISO submitted another Readiness Certification.  The FERC has not yet acted on this submission.  MISO announced on August 26, 2008 that the startup of its market is postponed indefinitely.  MISO commits to make a filing giving at least sixty days notice of the new effective date. The latest announced effective date for market startup is January 6, 2009.

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.  Upon acceptance by the FERC, this filing will terminate the litigation and the Interconnection Agreement, among other effects.

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. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne zone load-serving entities to pay their PJM capacity obligations through May 31, 2011.

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FirstEnergy desires to continue to use its Duquesne zone generation resources to serve load in PJM. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification on whether Duquesne-zone generators could participate in PJM’s May 2008 auction for the 2011-2012 planning year. In the order, the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators could contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with the FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction.

The FERC also directed MISO and PJM to resolve the substantive and procedural issues associated with Duquesne’s transition into MISO. As directed, PJM filed thirteen load-serving entity Capacity Payment Agreements and a Capacity Portability Agreement with the FERC. The Capacity Payment Agreements addressed Duquesne Zone load-serving entity obligations through May 31, 2011 with regards to RPM Capacity while the Capacity Portability Agreement addressed operational issues associated with the portability of such capacity. On September 30, 2008, the FERC approved both agreements, subject to conditions, taking notice of many operational and procedural issues brought forth by FirstEnergy and other market participants.

Several issues surrounding Duquesne’s transition into MISO continue to be contested at the FERC. Specifically, Duquesne’s obligation to pay for transmission expansion costs allocated to the Duquesne zone when they were a member of PJM, and other issues in which market participants wish to be held harmless by Duquesne’s transition. FirstEnergy filed for rehearing on these issues on October 3, 2008. Duquesne’s transition into MISO is also contingent upon the start of MISO’s ancillary services market and consolidation of its balancing authorities, currently scheduled for January 6, 2009.

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. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by the FERC that established the RPM. In the complaint, the RPM Buyers request that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On July 11, 2008, PJM filed its answer to the complaint, in which it denied the allegation that the rates are unjust and unreasonable. Also on that date, FirstEnergy filed a motion to intervene. 

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 its progress on contemplating adjustments to the RPM as suggested by the Brattle Group in its report reviewing the RPM. The technical conference will take place in February, 2009. On October 20, 2008, the RPM Buyers filed a request for rehearing of the FERC’s September 19, 2008 order.

MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load-serving entities such as the Ohio Companies, Penn 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 purchase 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. Issuance of these orders is not expected to delay the June 1, 2009 start date for MISO Resource Adequacy.

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Organized Wholesale Power Markets

The FERC issued a final rule on October 17, 2008, amending its regulations to “improve the operation of organized wholesale electric markets in the areas of: (1) demand response and market pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market-monitoring policies; and (4) the responsiveness of RTOs and ISOs to their customers and other stakeholders.” The RTOs and ISOs were directed to submit amendments to their respective tariffs to address these market operation improvements.  The final rule directs RTOs to adopt market rules permitting prices to increase during periods of supply shortages and to permit enhanced participation by demand response resources.  It also codifies and defines for the first time the roles and duties of independent market monitors within RTOs.  Finally, it adopts requirements for enhanced access by stakeholders to RTO boards of directors.  RTOs are directed to make compliance filings six months from the effective date of the final rule.  The final rule is not expected to have any material effect on FirstEnergy's operations within MISO and PJM.

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.  A ruling by the FERC is expected the week of December 15, 2008.

On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and The Waverly Power and Light Company (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.

13.  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 FirstEnergy 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 FirstEnergy’s application of this Standard in periods after implementation will be dependent upon 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 FirstEnergy’s financial statements.

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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. FirstEnergy expects this Standard to increase its disclosure requirements for derivative instruments and hedging activities.

14.  SEGMENT INFORMATION

FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The assets and revenues for all other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”

The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. Its revenues are primarily derived from the delivery of electricity, cost recovery of regulatory assets, and default service electric generation sales to non-shopping customers in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under partial requirements purchased power agreements and from non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.

The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive electricity sales primarily in Ohio, Pennsylvania, Maryland and Michigan, owns or leases and operates FirstEnergy’s generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from the affiliated company PSA sales and the non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment’s customers. The segment’s internal revenues represent the affiliated company PSA sales.

The Ohio transitional generation services segment represents the regulated generation commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect the purchase of electricity from the competitive energy services segment through full-requirements PSA arrangements, the deferral and amortization of certain fuel costs authorized for recovery by the energy delivery services segment and the net MISO transmission revenues and expenses related to the delivery of generation load. This segment’s total assets consist of accounts receivable for generation revenues from retail customers.

137

Segment Financial Information
						Ohio
	Energy		Competitive			Transitional
	Delivery		Energy			Generation						Reconciling
Three Months Ended	Services		Services			Services			Other			Adjustments			Consolidated
	(In millions)
September 30, 2008
External revenues	$	2,657	$	460		$	813		$	5		$	(31	)	$	3,904
Internal revenues		-		786			-			-			(786	)		-
Total revenues		2,657		1,246			813			5			(817	)		3,904
Depreciation and amortization		286		67			46			1			1			401
Investment income		48		13			1			-			(22	)		40
Net interest charges		101		31			1			-			44			177
Income taxes		188		109			14			(46	)		(27	)		238
Net income		283		164			19			48			(43	)		471
Total assets		23,088		9,360			270			457			387			33,562
Total goodwill		5,559		24			-			-			-			5,583
Property additions		170		285			-			85			20			560
September 30, 2007
External revenues	$	2,520	$	370		$	723		$	9		$	19		$	3,641
Internal revenues		-		806			-			-			(806	)		-
Total revenues		2,520		1,176			723			9			(787	)		3,641
Depreciation and amortization		299		51			(16	)		1			8			343
Investment income		58		5			-			1			(34	)		30
Net interest charges		117		39			-			1			37			194
Income taxes		175		99			11			(2	)		(10	)		273
Net income		269		148			16			6			(26	)		413
Total assets		23,308		7,182			268			232			663			31,653
Total goodwill		5,585		24			-			-			-			5,609
Property additions		209		199			-			3			19			430
Nine Months Ended
September 30, 2008
External revenues	$	7,051	$	1,164		$	2,203		$	65		$	(57	)	$	10,426
Internal revenues		-		2,266			-			-			(2,266	)		-
Total revenues		7,051		3,430			2,203			65			(2,323	)		10,426
Depreciation and amortization		782		179			61			2			10			1,034
Investment income		133		(1	)		1			6			(66	)		73
Net interest charges		303		86			1			-			133			523
Income taxes		436		212			42			(33	)		(72	)		585
Net income		655		317			62			96			(120	)		1,010
Total assets		23,088		9,360			270			457			387			33,562
Total goodwill		5,559		24			-			-			-			5,583
Property additions		621		1,430			-			106			20			2,177
September 30, 2007
External revenues	$	6,655	$	1,089		$	1,968		$	29		$	(18	)	$	9,723
Internal revenues		-		2,210			-			-			(2,210	)		-
Total revenues		6,655		3,299			1,968			29			(2,228	)		9,723
Depreciation and amortization		767		153			(80	)		3			20			863
Investment income		190		13			1			1			(112	)		93
Net interest charges		340		131			1			3			97			572
Income taxes		464		259			46			-			(74	)		695
Net income		695		388			69			13			(124	)		1,041
Total assets		23,308		7,182			268			232			663			31,653
Total goodwill		5,585		24			-			-			-			5,609
Property additions		609		462			-			6			50			1,127

Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses and elimination of intersegment transactions.

138

15.  SUPPLEMENTAL GUARANTOR INFORMATION

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

The consolidating statements of income for the three-month and nine-month periods ended September 30, 2008 and 2007, consolidating balance sheets as of September 30, 2008 and December 31, 2007 and condensed consolidating statements of cash flows for the nine months ended September 30, 2008 and 2007 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. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

139

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
For the Three Months Ended September 30, 2008	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	1,222,783		$	574,394		$	267,017		$	(822,590	)	$	1,241,604
EXPENSES:
Fuel		8,177			307,646			34,123			-			349,946
Purchased power from non-affiliates		221,493			-			-			-			221,493
Purchased power from affiliates		815,243			7,347			15,821			(822,590	)		15,821
Other operating expenses		35,596			110,701			120,697			12,190			279,184
Provision for depreciation		1,978			33,432			30,559			(1,336	)		64,633
General taxes		4,829			10,768			6,139			-			21,736
Total expenses		1,087,316			469,894			207,339			(811,736	)		952,813
		-			-			-			-
OPERATING INCOME		135,467			104,500			59,678			(10,854	)		288,791
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		102,777			(515	)		13,287			(97,122	)		18,427
Interest expense - affiliates		(120	)		(4,963	)		(2,932	)		-			(8,015	)
Interest expense - other		(8,464	)		(23,447	)		(17,183	)		16,325			(32,769	)
Capitalized interest		41			11,376			978			-			12,395
Total other income (expense)		94,234			(17,549	)		(5,850	)		(80,797	)		(9,962	)
INCOME BEFORE INCOME TAXES		229,701			86,951			53,828			(91,651	)		278,829
INCOME TAXES		44,046			31,863			14,995			2,270			93,174
NET INCOME	$	185,655		$	55,088		$	38,833		$	(93,921	)	$	185,655

140

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

141

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
For the Nine Months Ended September 30, 2008	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	3,387,258		$	1,707,320		$	879,729		$	(2,562,309	)	$	3,411,998
EXPENSES:
Fuel		13,920			876,077			92,188			-			982,185
Purchased power from non-affiliates		648,556			-			-			-			648,556
Purchased power from affiliates		2,549,892			12,417			75,834			(2,562,309	)		75,834
Other operating expenses		103,034			342,041			381,826			36,567			863,468
Provision for depreciation		3,885			90,058			80,646			(4,054	)		170,535
General taxes		14,971			33,842			15,915			-			64,728
Total expenses		3,334,258			1,354,435			646,409			(2,529,796	)		2,805,306
OPERATING INCOME		53,000			352,885			233,320			(32,513	)		606,692
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		323,092			(1,234	)		(2,699	)		(305,710	)		13,449
Interest expense - affiliates		(252	)		(18,172	)		(7,529	)		-			(25,953	)
Interest expense - other		(19,105	)		(73,112	)		(38,833	)		49,241			(81,809	)
Capitalized interest		90			27,460			2,049			-			29,599
Total other income (expense)		303,825			(65,058	)		(47,012	)		(256,469	)		(64,714	)
INCOME BEFORE INCOME TAXES		356,825			287,827			186,308			(288,982	)		541,978
INCOME TAXES		13,092			109,615			68,597			6,941			198,245
NET INCOME	$	343,733		$	178,212		$	117,711		$	(295,923	)	$	343,733

142

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

143

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of September 30, 2008	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	-	$	-	$	-		$	2
Receivables-
Customers		137,126		-		-		-			137,126
Associated companies		267,777		195,005		100,481		(299,484	)		263,779
Other		910		1,595		20,419		-			22,924
Notes receivable from associated companies		118,526		38,400		-		-			156,926
Materials and supplies, at average cost		3,519		288,623		205,134		-			497,276
Prepayments and other		64,585		84,138		30,807		-			179,530
		592,445		607,761		356,841		(299,484	)		1,257,563
PROPERTY, PLANT AND EQUIPMENT:
In service		108,733		5,413,310		4,704,478		(391,859	)		9,834,662
Less - Accumulated provision for depreciation		10,990		2,712,638		1,658,863		(170,774	)		4,211,717
		97,743		2,700,672		3,045,615		(221,085	)		5,622,945
Construction work in progress		2,827		1,225,381		157,444		-			1,385,652
		100,570		3,926,053		3,203,059		(221,085	)		7,008,597
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,145,384		-			1,145,384
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		3,581,979		-		-		(3,581,979	)		-
Other		2,124		38,247		202		-			40,573
		3,584,103		38,247		1,208,486		(3,581,979	)		1,248,857
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		9,655		471,718		-		(251,032	)		230,341
Lease assignment receivable from associated companies		-		71,356		-		-			71,356
Goodwill		24,248		-		-		-			24,248
Property taxes		-		25,007		22,767		-			47,774
Pension assets		3,208		11,556		-		-			14,764
Unamortized sale and leaseback costs		-		8,445		-		48,920			57,365
Other		18,343		59,511		18,717		(46,869	)		49,702
		55,454		647,593		41,484		(248,981	)		495,550
	$	4,332,572	$	5,219,654	$	4,809,870	$	(4,351,529	)	$	10,010,567
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	4,679	$	873,562	$	1,077,289	$	(17,315	)	$	1,938,215
Short-term borrowings-
Associated companies		-		147,108		164,642		-			311,750
Other		1,000,000		-		-		-			1,000,000
Accounts payable-
Associated companies		276,155		202,678		158,215		(275,601	)		361,447
Other		36,724		126,449		-		-			163,173
Accrued taxes		4,109		88,826		17,661		(29,877	)		80,719
Other		36,491		116,637		26,777		38,009			217,914
		1,358,158		1,555,260		1,444,584		(284,784	)		4,073,218
CAPITALIZATION:
Common stockholder's equity		2,916,934		1,813,911		1,755,054		(3,568,965	)		2,916,934
Long-term debt and other long-term obligations		40,333		1,364,207		451,365		(1,296,982	)		558,923
		2,957,267		3,178,118		2,206,419		(4,865,947	)		3,475,857
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,035,013			1,035,013
Accumulated deferred income taxes		-		-		235,811		(235,811	)		-
Accumulated deferred investment tax credits		-		40,209		23,759		-			63,968
Asset retirement obligations		-		24,148		825,327		-			849,475
Retirement benefits		9,745		57,822		-		-			67,567
Property taxes		-		25,328		22,767		-			48,095
Lease market valuation liability		-		319,129		-		-			319,129
Other		7,402		19,640		51,203		-			78,245
		17,147		486,276		1,158,867		799,202			2,461,492
	$	4,332,572	$	5,219,654	$	4,809,870	$	(4,351,529	)	$	10,010,567

144

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING BALANCE SHEETS
(Unaudited)
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
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,332,913		-			1,332,913
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		2,516,838		-		-		(2,516,838	)		-
Other		2,732		37,071		201		-			40,004
		2,519,570		37,071		1,396,014		(2,516,838	)		1,435,817
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		16,978		522,216		-		(262,271	)		276,923
Lease assignment receivable from associated companies		-		215,258		-		-			215,258
Goodwill		24,248		-		-		-			24,248
Property taxes		-		25,007		22,767		-			47,774
Pension asset		3,217		13,506		-		-			16,723
Unamortized sale and leaseback costs		-		27,597		-		43,206			70,803
Other		22,956		52,971		6,159		(38,133	)		43,953
		67,399		856,555		28,926		(257,198	)		695,682
	$	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

145

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
For the Nine Months Ended September 30, 2008	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
NET CASH PROVIDED FROM OPERATING ACTIVITIES:	$	47,463		$	267,933		$	247,054		$	(8,317	)	$	554,133
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			328,325			209,050			-			537,375
Equity contribution from parent		280,000			675,000			175,000			(850,000	)		280,000
Short-term borrowings, net		700,000			-			139,363			(91,677	)		747,686
Redemptions and Repayments-
Long-term debt		(1,777	)		(286,776	)		(180,666	)		8,317			(460,902	)
Short-term borrowings, net		-			(91,677	)		-			91,677			-
Common stock dividend payment		(43,000	)		-			-			-			(43,000	)
Net cash provided from financing activities		935,223			624,872			342,747			(841,683	)		1,061,159
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(38,481	)		(778,329	)		(600,395	)		-			(1,417,205	)
Proceeds from asset sales		-			15,218			-			-			15,218
Sales of investment securities held in trusts		-			-			596,291			-			596,291
Purchases of investment securities held in trusts		-			-			(624,899	)		-			(624,899	)
Loan repayments from (loans to) associated companies, net		(94,755	)		(38,399	)		69,012			-			(64,142	)
Investment in subsidiary		(850,000	)		-			-			850,000			-
Restricted funds for debt redemption		-			(52,090	)		(29,550	)		-			(81,640	)
Other		550			(39,205	)		(260	)		-			(38,915	)
Net cash used for investing activities		(982,686	)		(892,805	)		(589,801	)		850,000			(1,615,292	)
Net change in cash and cash equivalents		-			-			-			-			-
Cash and cash equivalents at beginning of period		2			-			-			-			2
Cash and cash equivalents at end of period	$	2		$	-		$	-		$	-		$	2

146

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
For the Nine Months Ended September 30, 2007	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES	$	(7,937	)	$	350,927		$	179,037		$	-		$	522,027
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			1,328,919			-			(1,328,919	)		-
Equity contribution from parent		700,000			700,000			-			(700,000	)		700,000
Short-term borrowings, net		223,942			-			13,128			(237,070	)		-
Redemptions and Repayments-
Common stock		(600,000	)		-			-			-			(600,000	)
Long-term debt		-			(795,019	)		(315,155	)		-			(1,110,174	)
Short-term borrowings, net		-			(1,022,197	)		-			237,070			(785,127	)
Common stock dividend payment		(67,000	)		-			-			-			(67,000	)
Net cash provided from (used for) financing activities		256,942			211,703			(302,027	)		(2,028,919	)		(1,862,301	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(10,119	)		(332,499	)		(140,289	)		-			(482,907	)
Proceeds from asset sales		-			12,990			-			-			12,990
Proceeds from sale and leaseback transaction		-			-			-			1,328,919			1,328,919
Sales of investment securities held in trusts		-			-			521,535			-			521,535
Purchases of investment securities held in trusts		-			-			(552,779	)		-			(552,779	)
Loan repayments from (loans to) associated companies, net		460,023			(242,612	)		292,896			-			510,307
Investment in subsidiary		(700,000	)		-						700,000			-
Other		1,091			(509	)		1,627			-			2,209
Net cash provided from (used for) investing activities		(249,005	)		(562,630	)		122,990			2,028,919			1,340,274
Net change in cash and cash equivalents		-			-			-			-			-
Cash and cash equivalents at beginning of period		2			-			-			-			2
Cash and cash equivalents at end of period	$	2		$	-		$	-		$	-		$	2

147

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4.  CONTROLS AND PROCEDURES

(a)  EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY

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

(b)  CHANGES IN INTERNAL CONTROLS

During the quarter ended September 30, 2008, there were no changes in FirstEnergy’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’s internal control over financial reporting.

ITEM 4T. CONTROLS AND PROCEDURES – FES, OE, CEI, TE, JCP&L, MET-ED AND PENELEC

(a)  EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

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

(b)  CHANGES IN INTERNAL CONTROLS

During the quarter ended September 30, 2008, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.

148

PART II. OTHER INFORMATION

ITEM 1.     LEGAL PROCEEDINGS

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

ITEM 1A.  RISK FACTORS

FirstEnergy’s Annual Report on Form 10-K for the year ended December 31, 2007, and Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, include a detailed discussion of its risk factors. The information presented below updates certain of those risk factors and should be read in conjunction with the risk factors and information disclosed in FirstEnergy’s prior SEC filings.

FirstEnergy relies on access to the credit and capital markets to finance a portion of its working capital requirements and to support its liquidity needs. Access to these markets may be adversely affected by factors beyond FirstEnergy’s control, including turmoil in the financial services industry, volatility in securities trading markets and general economic downturns. In particular, recent disruptions in the variable-rate demand bond markets could require utilization of a significant portion of the sources of liquidity currently available to FirstEnergy and its subsidiaries.

FirstEnergy relies upon access to the credit and capital markets as a source of liquidity for the portion of its working capital requirements not provided by cash from operations and to comply with various regulatory requirements. Market disruptions such as those currently being experienced in the United States and abroad may increase FirstEnergy’s cost of borrowing or adversely affect its ability to access sources of liquidity upon which it relies to finance operations and satisfy obligations as they become due. These disruptions may include turmoil in the financial services industry, including substantial uncertainty surrounding particular lending institutions and counterparties with whom FirstEnergy does business, unprecedented volatility in the markets where FirstEnergy’s outstanding securities trade, and general economic downturns in the areas where FirstEnergy does business. If FirstEnergy is unable to access credit at competitive rates, or if its short-term or long-term borrowing costs dramatically increase, FirstEnergy’s ability to finance its operations, meet its short-term obligations and implement its operating strategy could be adversely affected.

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

(c)   FirstEnergy

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

	Period
	July 1-31,	August 1-31,	September 1-30,	Third
	2008	2008	2008	Quarter
Total Number of Shares Purchased (a)	52,166	32,187	208,772	293,125
Average Price Paid per Share	$81.63	$71.63	$72.09	$73.74
Total Number of Shares Purchased
As Part of Publicly Announced Plans
or Programs
Maximum Number (or Approximate Dollar	-	-	-	-
Value) of Shares that May Yet Be
Purchased Under the Plans or Programs	-	-	-	-

(a) Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan, and shares purchased as part of publicly announced plans.

149

ITEM 6.     EXHIBITS

Exhibit Number
FirstEnergy
	10.1	$U.S. 300,000,000 Credit Agreement, dated as of October 8, 2008, among FirstEnergy Generation Corp., as Borrower, FirstEnergy Corp. and FirstEnergy Solutions Corp., as Guarantors, Credit Suisse and the other Banks parties thereto from time to time, as Banks, and Credit Suisse, as Administrative Agent
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
FES
	4.1	Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, of FirstEnergy Generation Corp. to The Bank of New York Trust Company, N.A., as Trustee
	10.1	$U.S. 300,000,000 Credit Agreement, dated as of October 8, 2008, among FirstEnergy Generation Corp., as Borrower, FirstEnergy Corp. and FirstEnergy Solutions Corp., as Guarantors, Credit Suisse and the other Banks parties thereto from time to time, as Banks, and Credit Suisse, as Administrative Agent
	10.2	Third Restated Partial Requirements Agreement dated November 1, 2008
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
OE
	4.1	Fourteenth Supplemental Indenture, dated as of October 1, 2008, to Ohio Edison Company’s General Mortgage Indenture and Deed of Trust dated as of January 1, 1998  (incorporated by reference to October 22, 2008 Form 8-K, Exhibit 4.1)
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
CEI
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
TE
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
JCP&L
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
Met-Ed
	10.2	Third Restated Partial Requirements Agreement dated November 1, 2008
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
Penelec
	10.2	Third Restated Partial Requirements Agreement dated November 1, 2008
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

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

150

SIGNATURES

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

November 7, 2008

FIRSTENERGY CORP.

Registrant

FIRSTENERGY SOLUTIONS CORP.

Registrant

OHIO EDISON COMPANY

Registrant

THE CLEVELAND ELECTRIC

ILLUMINATING COMPANY

Registrant

THE TOLEDO EDISON COMPANY

Registrant

METROPOLITAN EDISON COMPANY

Registrant

PENNSYLVANIA ELECTRIC COMPANY

Registrant

/s/  Harvey L. Wagner

Harvey L. Wagner

Vice President, Controller

and Chief Accounting Officer

JERSEY CENTRAL POWER & LIGHT COMPANY

Registrant

/s/  Paulette R. Chatman

Paulette R. Chatman

Controller

(Principal Accounting Officer)

151