10-Q

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, 2007

OR

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

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

Indicate by check mark whether each of the registrants (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., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and Pennsylvania Electric Company
Yes (  )  No (X)	The Toledo Edison Company, Jersey Central Power & Light Company and Metropolitan Edison Company

Indicate by check mark whether any of the registrants is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer  (X)	FirstEnergy Corp.
Accelerated Filer  (  )	N/A
Non-accelerated Filer  (X)	FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company

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

Yes (  )  No (X)

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 OCTOBER 31, 2007
FirstEnergy Corp., $.10 par value	304,835,407
FirstEnergy Solutions Corp., no par value	7
Ohio Edison Company, no par value	60
The Cleveland Electric Illuminating Company, no par value	67,930,743
The Toledo Edison Company, $5 par value	29,402,054
Jersey Central Power & Light Company, $10 par value	14,421,637
Metropolitan Edison Company, no par value	859,500
Pennsylvania Electric Company, $20 par value	4,427,577

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

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.

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.

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 achievement expressed or implied by such forward-looking statements. Actual results may differ materially due to the speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Ohio and Pennsylvania, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, the continued ability of FirstEnergy’s regulated utilities to collect transition and other charges or to recover increased transmission costs, maintenance costs being higher than anticipated, other legislative and regulatory changes including revised environmental requirements, the uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated) or levels of emission reductions related to the Consent Decree resolving the New Source Review litigation or other potential regulatory initiatives, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits and oversight) by the NRC (including, but not limited to, the Demand for Information issued to FENOC on May 14, 2007) as disclosed in the registrants’ SEC filings, the timing and outcome of various proceedings before the PUCO (including, but not limited to, the distribution rate cases and the generation supply plan filing for the Ohio Companies and the successful resolution of the issues remanded to the PUCO by the Ohio Supreme Court regarding the RSP and RCP, including the deferral of fuel costs) and the PPUC (including the resolution of the Petitions for Review filed with the Commonwealth Court of Pennsylvania with respect to the transition rate plan for Met-Ed and Penelec), the continuing availability of generating units and their the ability to operate at, or near full capacity, the ability to comply with applicable state and federal reliability standards, the inability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives), the ability to improve electric commodity margins and to experience growth in the distribution business, the ability to access the public securities and other capital markets and the cost of such capital, the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the August 14, 2003 regional power outage,  the risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors. The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible to predict all such factors, nor assess the impact of any such factor on the registrants’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. Also, a security rating is not a recommendation to buy, sell or hold securities, and it may be subject to revision or withdrawal at any time and each such rating should be evaluated independently of any other rating. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

TABLE OF CONTENTS

		Pages
Glossary of Terms		iii-iv
Part I.     Financial Information
Items 1. and 2. - Financial Statements and Management’s Discussion and Analysis of Financial Condition and                 Results of Operations.
	Notes to Consolidated Financial Statements	1-34
FirstEnergy Corp.
	Consolidated Statements of Income	35
	Consolidated Statements of Comprehensive Income	36
	Consolidated Balance Sheets	37
	Consolidated Statements of Cash Flows	38
	Report of Independent Registered Public Accounting Firm	39
	Management's Discussion and Analysis of Financial Condition and	40-80
	Results of Operations
FirstEnergy Solutions Corp.
	Consolidated Statements of Income and Comprehensive Income	81
	Consolidated Balance Sheets	82
	Consolidated Statements of Cash Flows	83
	Report of Independent Registered Public Accounting Firm	84
	Management's Narrative Analysis of Results of Operations	85-87
Ohio Edison Company
	Consolidated Statements of Income and Comprehensive Income	88
	Consolidated Balance Sheets	89
	Consolidated Statements of Cash Flows	90
	Report of Independent Registered Public Accounting Firm	91
	Management's Narrative Analysis of Results of Operations	92-93
The Cleveland Electric Illuminating Company
	Consolidated Statements of Income and Comprehensive Income	94
	Consolidated Balance Sheets	95
	Consolidated Statements of Cash Flows	96
	Report of Independent Registered Public Accounting Firm	97
	Management's Narrative Analysis of Results of Operations	98-99
The Toledo Edison Company
	Consolidated Statements of Income and Comprehensive Income	100
	Consolidated Balance Sheets	101
	Consolidated Statements of Cash Flows	102
	Report of Independent Registered Public Accounting Firm	103
	Management's Narrative Analysis of Results of Operations	104-105

i

TABLE OF CONTENTS (Cont'd)

Jersey Central Power & Light Company		Pages
	Consolidated Statements of Income and Comprehensive Income	106
	Consolidated Balance Sheets	107
	Consolidated Statements of Cash Flows	108
	Report of Independent Registered Public Accounting Firm	109
	Management's Narrative Analysis of Results of Operations	110-111
Metropolitan Edison Company
	Consolidated Statements of Income and Comprehensive Income	112
	Consolidated Balance Sheets	113
	Consolidated Statements of Cash Flows	114
	Report of Independent Registered Public Accounting Firm	115
	Management's Narrative Analysis of Results of Operations	116-117
Pennsylvania Electric Company
	Consolidated Statements of Income and Comprehensive Income	118
	Consolidated Balance Sheets	119
	Consolidated Statements of Cash Flows	120
	Report of Independent Registered Public Accounting Firm	121
	Management's Narrative Analysis of Results of Operations	122-123
Combined Management’s Discussion and Analysis of Registrant Subsidiaries		124-137
Item 3.                      Quantitative and Qualitative Disclosures About Market Risk.		138
Item 4.                      Controls and Procedures.		138
Part II.    Other Information
Item 1.                      Legal Proceedings.		139
Item 1A.                   Risk Factors.		139
Item 2.                      Unregistered Sales of Equity Securities and Use of Proceeds.		139
Item 6.                      Exhibits.		140

ii

      

GLOSSARY OF TERMS      

           

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

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
Companies	OE, CEI, TE, JCP&L, Met-Ed and Penelec
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial, and other corporate support services
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., a public utility holding company
FSG	FirstEnergy Facilities Services Group, LLC, former parent company of several heating, ventilation, air conditioning and energy management companies
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition    Funding	JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition    bonds
JCP&L Transition    Funding II	JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition    bonds
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MYR	MYR Group, Inc., a utility infrastructure construction service company
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
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
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
TEBSA	Termobarranquilla S.A., Empresa de Servicios Publicos
The following abbreviations and acronyms are used to identify frequently used terms in this report:
ALJ	Administrative Law Judge
APIC	Additional Paid-In Capital
AOCL	Accumulated Other Comprehensive Loss
ARO	Asset Retirement Obligation
BGS	Basic Generation Service
CAIR	Clean Air Interstate Rule
CAL	Confirmatory Action Letter
CAMR	Clean Air Mercury Rule
CBP	Competitive Bid Process
CO2	Carbon Dioxide
DOJ	United States Department of Justice
DRA	Division of Ratepayer Advocate
ECAR	East Central Area Reliability Coordination Agreement
EIS	Energy Independence Strategy
EITF	Emerging Issues Task Force
EITF 06-11	EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends or Share-Based    Payment Awards”
EMP	Energy Master Plan
EPA	Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ERO	Electric Reliability Organization
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 39-1	FIN 39-1, “Amendment of FASB Interpretation No. 39”
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB    Statement No. 143"

iii

      

GLOSSARY OF TERMS, Cont’d.      

    

FIN 48	FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement    No. 109”
FMB	First Mortgage Bonds
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
IRS	Internal Revenue Service
kV	Kilovolt
KWH	Kilowatt-hours
LOC	Letter of Credit
MEIUG	Met-Ed Industrial Users Group
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
MOU	Memorandum of Understanding
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
NOPR	Notice of Proposed Rulemaking
NOV	Notice of Violation
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
OCA	Office of Consumer Advocate
OCC	Office of the Ohio Consumers’ Counsel
OVEC	Ohio Valley Electric Corporation
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
RFP	Request for Proposal
RSP	Rate Stabilization Plan
RTO	Regional Transmission Organization
RTOR	Regional Through and Out Rates
S&P	Standard & Poor’s Ratings Service
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
SFAS	Statement of Financial Accounting Standards
SFAS 107	SFAS No. 107, “Disclosure about Fair Value of Financial Instruments”
SFAS 109	SFAS No. 109, “Accounting for Income Taxes”
SFAS 123(R)	SFAS No. 123(R), "Share-Based Payment"
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
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
SRM	Special Reliability Master
TBC	Transition Bond Charge
TMI-2	Three Mile Island Unit 2
VIE	Variable Interest Entity

iv

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. AND SUBSIDIARIES

FIRSTENERGY SOLUTIONS CORP. AND SUBSIDIARIES

OHIO EDISON COMPANY AND SUBSIDIARIES

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES

THE TOLEDO EDISON COMPANY AND SUBSIDIARY

JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES

METROPOLITAN EDISON COMPANY AND SUBSIDIARIES

PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1.  ORGANIZATION AND BASIS OF PRESENTATION

FirstEnergy's principal business is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly owned subsidiary of OE. FirstEnergy’s consolidated financial statements also include its other subsidiaries: FENOC, FES and its subsidiaries FGCO and NGC, and FESC.

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

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, 2006 for FirstEnergy and the Companies. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain businesses divested in 2006 have been classified as discontinued operations on the Consolidated Statements of Income (see Note 4). As discussed in Note 14, interim period segment reporting in 2006 was reclassified to conform with the current year business segment organizations and operations. 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 8) 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, 2007 and for the three-month and nine-month periods ended September 30, 2007 and 2006 have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated October 31, 2007) is included on page 39. 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 the registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Exchange Act of 1934.

1

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. The pool of stock-based compensation tax benefits is calculated in accordance with SFAS 123(R). On August 10, 2006, FirstEnergy repurchased 10.6 million shares, approximately 3.2%, of its outstanding common stock through an accelerated share repurchase program. The initial purchase price was $600 million, or $56.44 per share. A final purchase price adjustment of $27 million was settled in cash on April 2, 2007. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an additional accelerated share repurchase program at an initial price of $62.63 per share, or a total initial purchase price of approximately $900 million. The final purchase price for this program will be adjusted to reflect the volume-weighted average price of FirstEnergy’s common stock during the period of time that the bank will acquire shares to cover its short position, which is expected to be by the end of 2007. The basic and diluted earnings per share calculations shown below reflect the impact associated with these accelerated share repurchase programs. FirstEnergy intends to settle, in cash or shares, any obligation on its part to pay the difference between the average of the daily volume-weighted average price of the shares as calculated under the March 2007 program and the initial price of the shares.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Reconciliation of Basic and Diluted Earnings per Share	2007		2006		2007		2006
	(In millions, except per share amounts)
Income from continuing operations	$	413	$	452	$	1,041	$	983
Discontinued operations		-		2		-		(4	)
Redemption premium on subsidiary preferred stock		-		-		-		(3	)
Net earnings available for common shareholders	$	413	$	454	$	1,041	$	976
Average shares of common stock outstanding – Basic		304		322		307		326
Assumed exercise of dilutive stock options and awards		3		3		4		3
Average shares of common stock outstanding – Dilutive		307		325		311		329
Earnings per share:
Basic earnings per share:
Earnings from continuing operations	$	1.36	$	1.40	$	3.39	$	3.00
Discontinued operations		-		0.01		-		(0.01	)
Net earnings per basic share	$	1.36	$	1.41	$	3.39	$	2.99
Diluted earnings per share:
Earnings from continuing operations	$	1.34	$	1.39	$	3.35	$	2.98
Discontinued operations		-		0.01		-		(0.01	)
Net earnings per diluted share	$	1.34	$	1.40	$	3.35	$	2.97

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 2007 annual review was completed in the third quarter of 2007 with no impairment indicated.

FirstEnergy's goodwill primarily relates to its energy delivery services segment. In the third quarter of 2007, FirstEnergy adjusted goodwill for the former GPU companies due to the realization of tax benefits that had been reserved in purchase accounting. See Note 12 for a discussion of the tax implications related to the Bruce Mansfield Unit 1 sale and leaseback transaction. The following tables reconcile changes to goodwill for the three months and nine months ended September 30, 2007.

2

Three Months Ended	FirstEnergy			FES		CEI		TE		JCP&L			Met-Ed			Penelec
	(In millions)
Balance as of July 1, 2007	$	5,898		$	24	$	1,689	$	501	$	1,962		$	496		$	861
Adjustments related to GPU acquisition		(289	)		-		-		-		(136	)		(70	)		(83	)
Balance as of September 30, 2007	$	5,609		$	24	$	1,689	$	501	$	1,826		$	426		$	778

Nine Months Ended	FirstEnergy			FES		CEI		TE		JCP&L			Met-Ed			Penelec
	(In millions)
Balance as of January 1, 2007	$	5,898		$	24	$	1,689	$	501	$	1,962		$	496		$	861
Adjustments related to GPU acquisition		(289	)		-		-		-		(136	)		(70	)		(83	)
Balance as of September 30, 2007	$	5,609		$	24	$	1,689	$	501	$	1,826		$	426		$	778

4.  DIVESTITURES AND DISCONTINUED OPERATIONS

In 2006, FirstEnergy sold its remaining FSG subsidiaries (Roth Bros., Hattenbach, Dunbar, Edwards and RPC) for an aggregate net after-tax gain of $2.2 million. Hattenbach, Dunbar, Edwards, and RPC are included in discontinued operations for the third quarter and nine months ended September 30, 2006; Roth Bros. did not meet the criteria for that classification.

In March 2006, FirstEnergy sold 60% of its interest in MYR for an after-tax gain of $0.2 million. In June 2006, as part of the March agreement, FirstEnergy sold an additional 1.67% interest. As a result of the March sale, FirstEnergy deconsolidated MYR in the first quarter of 2006 and accounted for its remaining 38.33% interest under the equity method.  In the fourth quarter of 2006, FirstEnergy sold its remaining MYR interest for an after-tax gain of $8.6 million.

The income for the period that MYR was accounted for as an equity method investment has not been included in discontinued operations; however, results prior to the initial sale in March 2006, including the gain on the sale, are reported as discontinued operations.

Revenues associated with discontinued operations were $36 million and $211 million in the third quarter and first nine months of 2006, respectively. The following table summarizes the net income (loss) included in "Discontinued Operations" on the Consolidated Statements of Income for the three months and nine months ended September 30, 2006:

	Three Months			Nine Months
	(In millions)
FSG subsidiaries	$	2	$	(6	)
MYR		-		2
Total	$	2	$	(4	)

5.  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 on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criterion. Derivatives that meet that criterion are accounted for using traditional accrual accounting. The changes in the fair value of derivative instruments that do not meet the normal purchase and normal sales criterion are recorded as other expense, as AOCL, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness.

FirstEnergy hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases 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 included directly in earnings.

3

The net deferred losses of $52 million included in AOCL as of September 30, 2007, for derivative hedging activity, as compared to $58 million as of December 31, 2006, resulted from a net $10 million increase related to current hedging activity and a $16 million decrease due to net hedge losses reclassified to earnings during the nine months ended September 30, 2007. Based on current estimates, approximately $14 million (after tax) of the net deferred losses on derivative instruments in AOCL as of September 30, 2007 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.

FirstEnergy has entered into swaps that have been designated as fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. During the first nine months of 2007, FirstEnergy unwound swaps with a total notional value of $150 million, for which it incurred $8 million in cash losses that will be recognized as interest expense over the remaining maturity of each hedged security. As of September 30, 2007, FirstEnergy had interest rate swaps with an aggregate notional value of $600 million and a fair value of $(14) million.

During 2006 and the first nine months of 2007, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated issuances of fixed-rate, long-term debt securities for one or more of its subsidiaries as outstanding debt matures during 2007 and 2008. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first nine months of 2007, FirstEnergy terminated swaps with a notional value of $1.6 billion for which it paid $20 million, all of which were deemed effective. FirstEnergy will recognize the $20 million loss over the life of the associated future debt. As of September 30, 2007, FirstEnergy had forward swaps with an aggregate notional amount of $400 million and a fair value of $5 million.

6.  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 liability of $1.2 billion as of September 30, 2007 is primarily related to the 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, 2007, the fair value of the decommissioning trust assets was approximately $2.1 billion.

The following tables analyze changes to the ARO balances during the three months and nine months ended September 30, 2007 and 2006, respectively.

Three Months Ended	FirstEnergy		FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
ARO Reconciliation
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
cashflows		-		-		-		-		-		-		-		-
Balance, September 30, 2007	$	1,247	$	797	$	92	$	2	$	28	$	88	$	158	$	81
Balance, July 1, 2006	$	1,160	$	743	$	85	$	2	$	26	$	82	$	146	$	74
Liabilities incurred		-		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-		-
Accretion		19		13		2		-		-		1		3		2
Revisions in estimated
cashflows		-		-		-		-		-		-		-		-
Balance, September 30, 2006	$	1,179	$	756	$	87	$	2	$	26	$	83	$	149	$	76

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Nine Months Ended	FirstEnergy			FES			OE		CEI			TE		JCP&L		Met-Ed		Penelec
	(In millions)
ARO Reconciliation
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
cashflows		-			-			-		-			-		-		-		-
Balance, September 30, 2007	$	1,247		$	797		$	92	$	2		$	28	$	88	$	158	$	81
Balance, January 1, 2006	$	1,126		$	716		$	83	$	8		$	25	$	80	$	142	$	72
Liabilities incurred		-			-			-		-			-		-		-		-
Liabilities settled		(6	)		-			-		(6	)		-		-		-		-
Accretion		55			36			4		-			1		3		7		4
Revisions in estimated
cashflows		4			4			-		-			-		-		-		-
Balance, September 30, 2006	$	1,179		$	756		$	87	$	2		$	26	$	83	$	149	$	76

7.  PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its and 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, 2006. On January 2, 2007, FirstEnergy made a $300 million voluntary cash contribution to its qualified pension plan. Projections indicate that additional cash contributions are not expected to be required before 2016. 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. During 2006, FirstEnergy amended the health care plan effective in 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized health care coverage. 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 and other postretirement benefit costs (including amounts capitalized) for the three months and nine months ended September 30, 2007 and 2006 consisted of the following:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Pension Benefits	2007			2006			2007			2006
	(In millions)
Service cost	$	21		$	21		$	63		$	63
Interest cost		71			66			213			199
Expected return on plan assets		(112	)		(99	)		(337	)		(297	)
Amortization of prior service cost		2			2			7			7
Recognized net actuarial loss		10			15			31			44
Net periodic cost (credit)	$	(8	)	$	5		$	(23	)	$	16

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Other Postretirement Benefits	2007			2006			2007			2006
	(In millions)
Service cost	$	5		$	9		$	16		$	26
Interest cost		17			26			52			79
Expected return on plan assets		(12	)		(12	)		(38	)		(35	)
Amortization of prior service cost		(37	)		(19	)		(112	)		(57	)
Recognized net actuarial loss		11			14			34			42
Net periodic cost (credit)	$	(16	)	$	18		$	(48	)	$	55

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Pension and other postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. FirstEnergy’s subsidiaries capitalize employee benefit costs related to construction projects. The net periodic pension and other postretirement benefit costs (including amounts capitalized) recognized by FES and each of the Companies for the three months and nine months ended September 30, 2007 and 2006 were as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Pension Benefit Cost (Credit)	2007			2006			2007			2006
	(In millions)
FES	$	5.2		$	9.9		$	15.7		$	29.9
OE		(4.0	)		(1.5	)		(11.9	)		(4.5	)
CEI		0.3			1.0			0.9			2.9
TE		-			0.2			(0.1	)		0.7
JCP&L		(2.1	)		(1.4	)		(6.4	)		(4.1	)
Met-Ed		(1.7	)		(1.7	)		(5.1	)		(5.2	)
Penelec		(2.6	)		(1.3	)		(7.7	)		(4.0	)
Other FirstEnergy subsidiaries		(2.7	)		-			(8.1	)		-
	$	(7.6	)	$	5.2		$	(22.7	)	$	15.7

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Other Postretirement Benefit Cost (Credit)	2007			2006		2007			2006
	(In millions)
FES	$	(2.4	)	$	3.4	$	(7.4	)	$	10.2
OE		(2.7	)		4.2		(8.0	)		12.6
CEI		1.0			2.8		2.9			8.3
TE		1.2			2.0		3.7			6.1
JCP&L		(4.0	)		0.6		(11.9	)		1.8
Met-Ed		(2.5	)		0.7		(7.7	)		2.2
Penelec		(3.2	)		1.8		(9.5	)		5.4
Other FirstEnergy subsidiaries		(3.3	)		2.7		(9.8	)		7.9
	$	(15.9	)	$	18.2	$	(47.7	)	$	54.5

8.  VARIABLE INTEREST ENTITIES

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

Trusts

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

PNBV was established to purchase a portion of the lease obligation bonds issued in connection with 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.

OE, CEI and TE are exposed to losses under the applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $827 million, $758 million and $758 million, respectively, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the applicable sale and leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $606 million, $73 million and $429 million, respectively, that would not be payable if the casualty value payments are made.

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Effective October 16, 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. FGCO assumed all of CEI’s and TE’s obligations arising under those leases. However, CEI and TE will remain primarily liable on the leases and related agreements as to the lessors and other parties to the agreements. The assignment terminates automatically upon the termination of the underlying leases.

Power Purchase Agreements

In accordance with FIN 46R, FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Companies and the contract price for power is correlated with the 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 incurs for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. As of September 30, 2007, the net above-market loss liability projected for these eight NUG agreements was $158 million. Purchased power costs from these entities during the three months and nine months ended September 30, 2007 and 2006 are shown in the following table:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
	(In millions)
JCP&L	$	30	$	29	$	71	$	63
Met-Ed		13		12		40		45
Penelec		7		8		22		22
Total	$	50	$	49	$	133	$	130

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, 2007, $404 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.

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

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9.  INCOME TAXES

On January 1, 2007, FirstEnergy adopted FIN 48, which provides guidance for accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. 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.

As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits was $268 million. FirstEnergy recorded a $2.7 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate upon recognition. The majority of items that would not have affected the effective tax rate would be purchase accounting adjustments to goodwill upon recognition. During the first nine months of 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of September 30, 2007, the entire liability for uncertain tax positions is included in other non-current liabilities and changes to FirstEnergy’s tax contingencies that are reasonably possible in the next twelve months are not material.

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. As of January 1, 2007, the net amount of interest accrued was $34 million. During the first nine months of 2007, there were no material changes to the amount of interest accrued.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2006. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audit for years 2004 and 2005 began in June 2006 and is not expected to close before December 2007. The IRS began auditing the year 2006 in April 2006 under its Compliance Assurance Process experimental program, which is not expected to close before December 2007. 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.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity (see Note 12). This transaction generated tax capital gains of approximately $752 million, all of which were offset by existing tax capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowances in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 3).

10.  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, 2007, outstanding guarantees and other assurances aggregated approximately $4.7 billion, consisting of parental guarantees - $1.2  billion, subsidiaries’ guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $0.7  billion.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for subsidiary financings or refinancings of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.6 billion (included in the $1.2 billion discussed above) as of September 30, 2007 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

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While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating-downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of September 30, 2007, FirstEnergy's maximum exposure under these collateral provisions was $442 million.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $75 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions.

The Companies, with the exception of TE and JCP&L, each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company.

			Borrowing
Subsidiary Company	Parent Company		Capacity
			(In millions)
OES Capital, Incorporated		OE	$	170
Centerior Funding Corp.		CEI		200
Penn Power Funding LLC		Penn		25
Met-Ed Funding LLC		Met-Ed		80
Penelec Funding LLC		Penelec		75
			$	550

FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($27 million as of September 30, 2007), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. The LOC was reduced to $19 million on October 15, 2007.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1 (see Note 12). 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.

(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 $1.8 billion for 2007 through 2011.

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

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The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006 alleging violations to various sections of the Clean Air Act. FirstEnergy has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.

FirstEnergy complies with SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO_X 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 NO_X reductions at FirstEnergy's facilities. The EPA's NO_X Transport Rule imposes uniform reductions of NO_X emissions (an approximate 85% reduction in utility plant NO_X 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 NO_X emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NO_X budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act, alleging violations of air pollution laws at the Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 16, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. FirstEnergy is currently studying PennFuture’s complaint.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. 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 allowed each affected state until 2006 to develop implementing regulations to achieve additional reductions of NO_X and SO₂ emissions in two phases (Phase I in 2009 for NO_X, 2010 for SO₂ and Phase II in 2015 for both NO_X and SO₂). FirstEnergy's Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO₂ and NO_X emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on NO_X emissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_X emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_X cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

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, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO₂ and NO_X emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

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The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FirstEnergy would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FirstEnergy will be disadvantaged if these model rules were implemented as proposed because FirstEnergy’s substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

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. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. 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 Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn, and is now owned by FGCO. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as the New Source Review, or NSR, cases.

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NO_X and SO₂ emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreement are currently estimated to be $1.7 billion for 2007 through 2011 ($400 million of which is expected to be spent during 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009).

The Sammis NSR Litigation consent decree also requires FirstEnergy to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.

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 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. At the international level, efforts have begun to develop climate change agreements for post-2012 GHG reductions. 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.

At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States.  State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

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On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO₂ emissions from automobiles as “air pollutants” under the Clean Air Act. Although this decision did not address CO₂ emissions from electric generating plants, the EPA has similar authority under the Clean Air Act to regulate “air pollutants” from those and other facilities. Also 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, the EPA proposed to change the NSR regulations, on May 8, 2007, to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.

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 federal Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to EPA for further rulemaking and eliminated the restoration option from 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 (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. FirstEnergy is evaluating various control options and their costs and effectiveness. Depending on the outcome of such studies, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future cost of compliance with these standards may require material capital expenditures.

Regulation of Hazardous Waste

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

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.  As of September 30, 2007, FirstEnergy had approximately $1.5 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry.  As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans to seek for these facilities.

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are 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, 2007, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $89 million (JCP&L - $60 million, TE - $3 million, CEI - $1 million, and FirstEnergy Corp. - $25 million) have been accrued through September 30, 2007.

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(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.  FirstEnergy is defending this class action but is unable to predict the outcome of this matter.  No liability has been accrued as of September 30, 2007.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. – Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

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FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Two other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc. (AEP), as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. The four cases remaining were consolidated for hearing by the PUCO in an order dated March 7, 2006.  In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on January 8, 2008.

FirstEnergy is defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although FirstEnergy is unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Nuclear Plant Matters

On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information 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 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 Demand for Information reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. The NRC held a public meeting on June 27, 2007 with FENOC to discuss FENOC’s response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC’s compliance with these commitments is subject to future NRC review.

Other Legal Matters

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

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

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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. The arbitration panel provided additional rulings regarding damages during a September 2007 hearing and it is anticipated that he will issue a final order in late 2007. JCP&L intends to re-file an appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

11.  REGULATORY MATTERS

(A) RELIABILITY INITIATIVES

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. – Canada Power System Outage Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training and emergency response preparedness recommended for completion in 2004. On July 14, 2004, NERC independently verified that FirstEnergy had implemented the various initiatives to be completed by June 30 or summer 2004, with minor exceptions noted by FirstEnergy, which exceptions are now essentially complete. FirstEnergy is 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 equipment or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability entities may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future, which could require additional, material expenditures.

As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L’s ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a stipulation that incorporates the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L’s Planning and Operations and Maintenance programs and practices. On February 11, 2005, JCP&L met with the DRA to discuss reliability improvements. The SRM completed his work and issued his final report to the NJBPU on June 1, 2006. JCP&L filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L continues to file compliance reports reflecting activities associated with the MOU and stipulation.

The EPACT served, among other things, partly to amend the Federal Power Act by adding a new Section 215, which requires that a new ERO establish and enforce reliability standards for the bulk-power system, subject to review by the FERC. Subsequently, the FERC certified NERC as the ERO, approved NERC's Compliance Monitoring and Enforcement Program and approved a set of reliability standards, which became mandatory and enforceable on June 18, 2007 with penalties and sanctions for noncompliance. The FERC also approved a delegation agreement between NERC and ReliabilityFirst Corporation, one of eight Regional Entities that carry out enforcement for NERC.  All of FirstEnergy’s facilities are located within the ReliabilityFirst region.

To date, FERC has approved 83 of the 107 reliability standards proposed by NERC. Nevertheless, the FERC has directed NERC to submit improvements to 56 of the 83 approved standards and has endorsed NERC's process for developing reliability standards and its associated work plan. On May 4, 2007, NERC submitted 24 proposed Violation Risk Factors that would operate as a system of weighting the risk to the power grid associated with a particular reliability standard violation. The FERC issued an order approving 22 of those factors on June 26, 2007. Further, NERC adopted eight cyber security standards and filed them with the FERC for approval. On December 11, 2006, the FERC Staff provided its preliminary assessment of the cyber security standards and cited various deficiencies in the proposed standards. Numerous parties, including FirstEnergy, provided comments on the preliminary assessment. The standards remain pending before the FERC. Separately, on July 20, 2007, the FERC issued a NOPR proposing to adopt eight related Critical Infrastructure Protection Reliability Standards. On October 5, 2007, numerous parties, including FirstEnergy, provided comments on the proposed Critical Infrastructure Protection standards. These standards, and FirstEnergy’s comments thereon, are pending before FERC.

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FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the FERC's guidance to NERC in its March 16, 2007 Final Rule on Mandatory Reliability Standards, it appears that the FERC may eventually adopt stricter standards than those just approved. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates. If FirstEnergy is unable to meet the reliability standards for its bulk power system in the future, it could have a material adverse effect on FirstEnergy’s and its subsidiaries’ financial condition, results of operations and cash flows.

On April 18-20, 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy's bulk-power system within the Midwest ISO region and found FirstEnergy to be in full compliance with all audited reliability standards.  Similarly, ReliabilityFirst has scheduled a compliance audit of FirstEnergy's bulk-power system within the PJM region in 2008. FirstEnergy does not expect any material adverse impact to its financial condition as a result of these audits.

(B) OHIO

On September 9, 2005, the Ohio Companies filed their RCP with the PUCO. The filing included a stipulation and supplemental stipulation with several parties agreeing to the provisions set forth in the plan. On January 4, 2006, the PUCO issued an order which approved the stipulation on the RCP after clarifying certain provisions. Several parties subsequently filed appeals to the Supreme Court of Ohio in connection with certain portions of the RCP approved by the PUCO. In its order, the PUCO authorized the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs, all such costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a 25-year period through distribution rates, which was expected to begin on January 1, 2009 for OE and TE, and approximately May 2009 for CEI.  Through September 30, 2007, the deferred fuel costs, including interest, were $89 million, $61 million and $26 million for OE, CEI and TE, respectively.

On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated certain provisions of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” because fuel costs are a component of generation service, not distribution service, and because the Court concluded the PUCO did not address whether the deferral of fuel costs was anticompetitive.  The Court remanded the matter to the PUCO for further consideration consistent with the Court’s Opinion on this issue and affirmed the PUCO’s Order in all other respects. On September 7, 2007, the Ohio Companies filed a Motion for Reconsideration with the Court. On September 10, 2007 the Ohio Companies filed an Application with the PUCO that requests the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. The Ohio Companies requested the riders become effective in October 2007 and end in December 2008, subject to reconciliation which is expected to continue through the first quarter of 2009. This matter is currently pending before the PUCO. Although unable to predict the ultimate outcome of this matter, the Ohio Companies intend to continue deferring the fuel costs pursuant to the RCP, pending the Court’s disposition of the Motion for Reconsideration and the PUCO’s action with respect to the Ohio Companies’ Application.

On August 31, 2005, the PUCO approved a rider recovery mechanism through which the Ohio Companies may recover all MISO transmission and ancillary service related costs incurred during each year ending June 30. Pursuant to the PUCO’s order, the Ohio Companies, on May 1, 2007, filed revised riders, which became effective on July 1, 2007.  The revised riders represent an increase over the amounts collected through the 2006 riders of approximately $64 million annually.  If it is subsequently determined by the PUCO that adjustments to the rider as filed are necessary, such adjustments, with carrying costs, will be incorporated into the 2008 transmission rider filing.

On May 8, 2007, the Ohio Companies filed with the PUCO a notice of intent to file for an increase in electric distribution rates. The Ohio Companies filed the application and rate request with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the bill for most Ohio customers.  The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operating and maintenance expenses and recovery of regulatory assets created by deferrals that were approved in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million to the PUCO to establish the test period data that will be used as the basis for setting rates in that proceeding. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in early 2008. The PUCO order is expected to be issued in the second quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

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On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Comments by intervenors in the case were filed on September 5, 2007.  The PUCO Staff filed comments on September 21, 2007.  Parties filed reply comments on October 12, 2007. The Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process.

On September 25, 2007, the Ohio Governor’s proposed energy plan was officially introduced into the Ohio Senate. The bill proposes to revise state energy policy to address electric generation pricing after 2008, establish advanced energy portfolio standards and energy efficiency standards, and create GHG emissions reporting and carbon control planning requirements. The bill also proposes to move to a “hybrid” system for determining rates for PLR service in which electric utilities would provide regulated generation service unless they satisfy a statutory burden to demonstrate the existence of a competitive market for retail electricity. The Senate Energy & Public Utilities Committee has been conducting hearings on the bill and receiving testimony from interested parties, including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer groups, utility executives and others. Several proposed amendments to the bill have been submitted, including those from Ohio’s investor-owned electric utilities. A substitute version of the bill, which incorporated certain of the proposed amendments, was introduced into the Senate Energy & Public Utilities Committee on October 25, 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of the Ohio Companies.

(C) PENNSYLVANIA

Met-Ed and Penelec have been purchasing a portion of their PLR requirements from FES through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy requirements during the term of these agreements with FES.

On September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that were substantially higher than the fixed price in the partial requirements agreements.

Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.

If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its 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.

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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 also 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, when new transmission rates were effective, 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 in 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 expenses and the transmission deferral. 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). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part the MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the 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. On June 19, 2007, initial briefs were filed and responsive briefs were filed through September 21, 2007.  Reply briefs were filed on October 5, 2007. Oral arguments are expected to take place in late 2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the financial condition and results of operations of Met-Ed, Penelec and FirstEnergy.

As of September 30, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $496 million and $58 million, respectively. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in February 2007 and briefing was completed on March 28, 2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.

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On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service will be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. On September 28, 2007, Penn filed a Joint Petition for Settlement resolving all but one issue in the case.  Briefs were also filed on September 28, 2007 on the unresolved issue of incremental uncollectible accounts expense.  The settlement is either supported, or not opposed, by all parties. The PPUC is expected to act on the settlement and the unresolved issue in late November or early December 2007 for the initial RFP to take place in January 2008.

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation programs to meet demand 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 an optional 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 final form of any legislation arising from the special legislative session is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

(D) NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2007, the accumulated deferred cost balance totaled approximately $330 million.

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

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that would 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. Comments on the alternative proposal were submitted on June 15, 2006. On November 3, 2006, the Staff circulated a revised draft proposal to interested stakeholders. Another revised draft was circulated by the NJBPU Staff on February 8, 2007.

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated with the issuance of a proposed set of objectives which, as to electricity, included the following:

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

·   Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date;

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·   Reduce air pollution related to energy use;

·   Encourage and maintain economic growth and development;

·   Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020;

·   Maintain unit prices for electricity to no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia); and

·   Eliminate transmission congestion by 2020.

Comments on the objectives and participation in the development of the EMP have been solicited and a number of working groups have been formed to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing (1) energy efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing issues have completed their assigned tasks of data gathering and analysis and have provided reports to the EMP Committee. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected later in 2007. A final draft of the EMP is expected to be presented to the Governor in late 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of JCP&L.

On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards.  Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff.  On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments which were due on September 26, 2007.  At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such regulations may have on its operations or those of JCP&L.

(E) FERC MATTERS

On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the fourth quarter of 2007.

On January 31, 2005, certain PJM transmission owners made three 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. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas & Electric Company (BG&E) and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. Hearings were held and numerous parties appeared and litigated various issues; including AEP, which filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. At the conclusion of the hearings, the ALJ issued an initial decision adopting the FERC Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate. The ALJ recommended an April 1, 2006 effective date for this change in rate design. Numerous parties, including FirstEnergy, submitted briefs opposing the ALJ’s decision and recommendations.  On April 19, 2007, the FERC issued an order rejecting the ALJ’s findings and recommendations in nearly every respect. The FERC found that the PJM transmission owners’ existing “license plate” 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 socialized 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.  Nevertheless, 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.

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On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 Order.  Subsequently, FirstEnergy and other parties filed pleadings opposing the requests for rehearing. The FERC’s Orders on PJM rate design, if sustained on rehearing and appeal, will prevent the allocation of the cost 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 future transmission costs shifting to the JCP&L, Met-Ed and Penelec zones.

    New FERC Transmission Rate Design Filings

On August 1, 2007, a number of filings were made with the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.

FirstEnergy joined in a filing made by the MISO transmission owners that would maintain the existing “license plate” rates for transmission service within MISO provided over existing transmission facilities.  FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to continue the elimination of transmission rates associated with service over existing transmission facilities between MISO and PJM.  If adopted by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities.  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 be maintained (known as the RECB Process). Each of these filings was supported by the majority of transmission owners in either MISO or PJM, as applicable.

The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV and higher transmission facilities be spread throughout the entire MISO footprint.  Further, Indianapolis Power and Light Company separately moved the FERC to reopen the record to address the cost allocation for the RECB Process.  If either proposal is adopted by the FERC, it could shift a greater portion of the cost of new 345 kV and higher transmission facilities to the FirstEnergy footprint in MISO, and increase the transmission rates paid by load-serving FirstEnergy affiliates in MISO.

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “SuperRegion” that regionalizes the cost of new and existing transmission facilities operated at voltages of 345 kV and above.  Lower voltage facilities would continue to be recovered in the host utility transmission rate zone through a license plate rate.  AEP requests a refund effective October 1, 2007, or alternatively, February 1, 2008.  The effect of this proposal, if adopted by FERC, would be to shift significant costs to the FirstEnergy zones in MISO and PJM.  FirstEnergy believes that most of these costs would ultimately be recoverable in retail rates. On October 12, 2007, BG&E filed a motion to dismiss AEP’s complaint. On October 16, 2007, the Organization of MISO States filed comments urging the FERC to dismiss AEP’s complaint. Interventions and protests to AEP’s complaint and answers to BG&E’s motion to dismiss were due October 29, 2007. FirstEnergy and other transmission owners filed protests to AEP’s complaint and support for BG&E’s motion to dismiss. AEP has asked for consolidation of its complaint with the cases above, and FirstEnergy expects it to be resolved on the same timeline as those cases.

Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC.  All or some of these proceedings may be consolidated by the FERC and set for hearing.  The outcome of these cases cannot be predicted.  Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates.  FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates.  Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.

    MISO Ancillary Services Market and Balancing Area Consolidation Filing

MISO made a filing on September 14, 2007 to establish Ancillary Services markets for regulation, spinning and supplemental reserves to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region.  An effective date of June 1, 2008 was requested in the filing.

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MISO’s previous filing to establish an Ancillary Services market was rejected without prejudice by FERC on June 22, 2007, subject to MISO making certain modifications in its filing. FirstEnergy believes that MISO’s September 14 filing generally addresses the FERC’s directives.  FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas, but filed objections on specific aspects of the MISO proposal.  Interventions and protests to MISO’s filing were made with FERC on October 15, 2007.

    Order No. 890 on Open Access Transmission Tariffs

On February 16, 2007, the FERC issued a final rule (Order No. 890) that revises its decade-old open access transmission regulations and policies.  The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process.  The final rule became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffs to comply with the FERC’s order. MISO, PJM and ATSI submitted tariff filings to the FERC on October 11, 2007. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.

12.  LEASES

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion (net after-tax proceeds of approximately $1.2 billion) for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034.  A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates.  The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. FES’ registration obligations under the registration rights agreement applicable to the $1.135 billion principal amount of pass through certificates issued in connection with the transaction were satisfied in September 2007, at which time the transaction was classified as an operating lease under GAAP for FES and FirstEnergy. This transaction generated tax capital gains of approximately $752 million, all of which were offset by existing tax capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowances in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 3).

The future minimum lease payments associated with the recently completed Bruce Mansfield Unit 1 sale and leaseback transaction as of September 30, 2007 are as follows (in millions):

2007	$	44
2008		89
2009		89
2010		89
2011		89
Years thereafter		2,286
Total minimum lease payments	$	2,686

13.  NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 157 – “Fair Value Measurements”

In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

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SFAS 159 – “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of

FASB Statement No. 115”

In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value. This Statement requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings.  The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet.  This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157 and SFAS 107. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

EITF 06-11 – “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”

In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R).  The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to APIC. This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement.  The consensus is effective for income tax benefits of dividends declared during fiscal years beginning after December 15, 2007.  EITF 06-11 is not expected to have a material effect on FirstEnergy’s financial statements.

FSP FIN 39-1 – “Amendment of FASB Interpretation No. 39”

In April 2007, the FASB issued Staff Position (FSP) FIN 39-1, which permits an entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement as the derivative instruments.  This FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. The effects of applying the guidance in this FSP should be recognized as a retrospective change in accounting principle for all financial statements presented. FirstEnergy is currently evaluating the impact of this FSP on its financial statements but it is not expected to have a material impact.

14.  SEGMENT INFORMATION

Effective January 1, 2007, FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. None of the aggregate “Other” segments individually meet the criteria to be considered a reportable segment. The energy delivery services segment consists of regulated transmission and distribution operations, including transition cost recovery, and PLR generation service for FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. The competitive energy services segment primarily consists of unregulated generation and commodity operations, including competitive electric sales, and generation sales to affiliated electric utilities. The Ohio transitional generation services segment represents PLR generation service by FirstEnergy’s Ohio electric utility subsidiaries. “Other” primarily consists of telecommunications services and other non-core assets. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”

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

The competitive energy services segment supplies electric power to its electric utility affiliates and competitive electric sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. The segment 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 power 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 power sales.

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The Ohio transitional generation services segment represents the regulated generation 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 electric generation 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 its generation load. This segment’s total assets consist of accounts receivable for generation revenues from retail customers.

Segment reporting in 2006 has been revised to conform to the current year business segment organization and operations. Changes in the current year operations reporting and revised 2006 segment reporting primarily reflect the transfer from FES to the regulated utilities of the responsibility for obtaining PLR generation for the utilities’ non-shopping customers. This reflects FirstEnergy’s alignment of its business units to accommodate its retail strategy and participation in competitive electricity marketplaces in Ohio, Pennsylvania and New Jersey. The differentiation of the regulated generation commodity operations between the two regulated business segments recognizes that generation sourcing for the Ohio Companies is currently in a transitional state through 2008 as compared to the segregated commodity sourcing of their Pennsylvania and New Jersey utility affiliates. The results of the energy delivery services and the Ohio transitional generation services segments now include their electric generation revenues and the corresponding generation commodity costs under affiliated and non-affiliated purchased power arrangements and related net retail PJM/MISO transmission expenses associated with serving electricity load in their respective franchise areas.

FSG completed the sale of its five remaining subsidiaries in 2006. Its assets and results for 2006 are combined in the “Other” segments in this report, as the remaining business does not meet the criteria of a reportable segment. Interest expense on holding company debt and corporate support services revenues and expenses are included in "Reconciling Adjustments."

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Segment Financial Information
					Ohio
	Energy		Competitive		Transitional
	Delivery		Energy		Generation						Reconciling
Three Months Ended	Services		Services		Services			Other			Adjustments			Consolidated
	(In millions)
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		-			1			21			430
September 30, 2006
External revenues	$	2,306	$	353	$	690		$	24		$	(9	)	$	3,364
Internal revenues		-		762		-			-			(762	)		-
Total revenues		2,306		1,115		690			24			(771	)		3,364
Depreciation and amortization		227		49		(40	)		1			6			243
Investment income		80		18		-			-			(52	)		46
Net interest charges		107		49		-			2			22			180
Income taxes		187		112		18			(14	)		(30	)		273
Income from
continuing operations		280		169		27			25			(49	)		452
Discontinued operations		-		-		-			2			-			2
Net income		280		169		27			27			(49	)		454
Total assets		23,940		6,822		240			321			839			32,162
Total goodwill		5,911		24		-			-			-			5,935
Property additions		119		126		-			-			6			251
Nine Months Ended
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		-			4			52			1,127
September 30, 2006
External revenues	$	5,876	$	1,077	$	1,808		$	92		$	(32	)	$	8,821
Internal revenues		14		1,997		-			-			(2,011	)		-
Total revenues		5,890		3,074		1,808			92			(2,043	)		8,821
Depreciation and amortization		657		143		(89	)		3			17			731
Investment income		244		35		-			1			(160	)		120
Net interest charges		308		139		1			5			60			513
Income taxes		468		201		58			(17	)		(85	)		625
Income from
continuing operations		702		302		88			30			(139	)		983
Discontinued operations		-		-		-			(4	)		-			(4	)
Net income		702		302		88			26			(139	)		979
Total assets		23,940		6,822		240			321			839			32,162
Total goodwill		5,911		24		-			-			-			5,935
Property additions		489		473		-			-			28			990

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.

25

15.  SUPPLEMENTAL GUARANTOR INFORMATION

As discussed in Note 12, 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.

The consolidating statements of income for the three months and nine months ended September 30, 2007 and 2006, consolidating balance sheets as of September 30, 2007 and December 31, 2006 and condensed consolidating statements of cash flows for the nine months ended September 30, 2007 and 2006 for FES (parent), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and reflect the consolidating entries associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

26

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 (expense), including
net income from equity investees		82,870			2,375			3,935			(76,525	)		12,655
Interest expense to 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

27

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
For the Three Months Ended September 30, 2006	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	1,120,844		$	466,628		$	246,039		$	(723,931	)	$	1,109,580
EXPENSES:
Fuel		12,632			273,398			29,491			-			315,521
Purchased power from non-affiliates		173,620			-			-			-			173,620
Purchased power from affiliates		711,298			52,062			16,218			(723,931	)		55,647
Other operating expenses		42,115			48,728			107,873			-			198,716
Provision for depreciation		456			24,656			21,782			-			46,894
General taxes		3,223			8,931			5,455			-			17,609
Total expenses		943,344			407,775			180,819			(723,931	)		808,007
OPERATING INCOME		177,500			58,853			65,220			-			301,573
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		69,102			1,694			18,089			(61,223	)		27,662
Interest expense to affiliates		-			(29,988	)		(11,428	)		-			(41,416	)
Interest expense - other		(207	)		(2,749	)		(4,958	)		-			(7,914	)
Capitalized interest		5			1,217			1,167			-			2,389
Total other income (expense)		68,900			(29,826	)		2,870			(61,223	)		(19,279	)
INCOME BEFORE INCOME TAXES		246,400			29,027			68,090			(61,223	)		282,294
INCOME TAXES		70,281			10,134			25,760			-			106,175
NET INCOME	$	176,119		$	18,893		$	42,330		$	(61,223	)	$	176,119

28

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 (expense), including
net income from equity investees		271,599			2,669			13,350			(239,862	)		47,756
Interest expense to 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

29

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
For the Nine Months Ended September 30, 2006	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	3,071,970		$	1,336,076		$	797,967		$	(2,145,891	)	$	3,060,122
EXPENSES:
Fuel		16,650			752,229			76,034			-			844,913
Purchased power from non-affiliates		477,249			-			-			-			477,249
Purchased power from affiliates		2,143,509			141,974			49,106			(2,145,891	)		188,698
Other operating expenses		149,042			204,282			421,443			-			774,767
Provision for depreciation		1,314			72,778			61,322			-			135,414
General taxes		9,268			29,536			16,746			-			55,550
Total expenses		2,797,032			1,200,799			624,651			(2,145,891	)		2,476,591
OPERATING INCOME		274,938			135,277			173,316			-			583,531
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		146,375			(3,052	)		35,518			(133,998	)		44,843
Interest expense to affiliates		(241	)		(87,318	)		(35,105	)		-			(122,664	)
Interest expense - other		(564	)		(5,650	)		(11,666	)		-			(17,880	)
Capitalized interest		(3	)		3,290			5,411			-			8,698
Total other income (expense)		145,567			(92,730	)		(5,842	)		(133,998	)		(87,003	)
INCOME BEFORE INCOME TAXES		420,505			42,547			167,474			(133,998	)		496,528
INCOME TAXES		108,549			13,296			62,727			-			184,572
NET INCOME	$	311,956		$	29,251		$	104,747		$	(133,998	)	$	311,956

30

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of September 30, 2007	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	-	$	-	$	-		$	2
Receivables-
Customers		144,443		-		-		-			144,443
Associated companies		282,118		169,108		113,936		(279,700	)		285,462
Other		4,862		554		-		-			5,416
Notes receivable from associated companies		-		242,612		-		-			242,612
Materials and supplies, at average cost		195		224,149		216,722		-			441,066
Prepayments and other		67,892		13,693		2,240		-			83,825
		499,512		650,116		332,898		(279,700	)		1,202,826
PROPERTY, PLANT AND EQUIPMENT:
In service		25,171		5,023,255		3,530,969		(395,817	)		8,183,578
Less - Accumulated provision for depreciation		6,807		2,539,192		1,476,051		(169,154	)		3,852,896
		18,364		2,484,063		2,054,918		(226,663	)		4,330,682
Construction work in progress		1,034		414,243		181,602		-			596,879
		19,398		2,898,306		2,236,520		(226,663	)		4,927,561
INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,342,083		-			1,342,083
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		2,462,960		-		-		(2,462,960	)		-
Other		5,315		34,447		202		-			39,964
		2,468,275		34,447		1,405,185		(2,462,960	)		1,444,947
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		28,756		403,890		-		(192,464	)		240,182
Goodwill		24,248		-		-		-			24,248
Property taxes		-		20,946		23,165		-			44,111
Pension assets		1,154		8,295		-		-			9,449
Other		33,049		32,477		5,112		-			70,638
		87,207		465,608		28,277		(192,464	)		388,628
	$	3,074,392	$	4,048,477	$	4,002,880	$	(3,161,787	)	$	7,963,962
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	-	$	624,517	$	861,265	$	(16,061	)	$	1,469,721
Notes payable-
Associated companies		223,942		-		13,128		-			237,070
Other		-		-		-		-			-
Accounts payable-
Associated companies		279,976		158,500		273,919		(279,700	)		432,695
Other		65,782		112,038		-		-			177,820
Accrued taxes		44,995		461,635		30,430		-			537,060
Other		60,252		59,770		9,731		33,486			163,239
		674,947		1,416,460		1,188,473		(262,275	)		3,017,605
CAPITALIZATION:
Common stockholder's equity		2,369,019		905,100		1,557,860		(2,462,960	)		2,369,019
Long-term debt		-		1,575,653		242,400		(1,312,857	)		505,196
		2,369,019		2,480,753		1,800,260		(3,775,817	)		2,874,215
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,068,769			1,068,769
Accumulated deferred income taxes		-		-		192,464		(192,464	)		-
Accumulated deferred investment tax credits		-		36,764		25,511		-			62,275
Asset retirement obligations		-		24,350		773,007		-			797,357
Retirement benefits		7,843		45,662		-		-			53,505
Property taxes		-		21,268		23,165		-			44,433
Other		22,583		23,220		-		-			45,803
		30,426		151,264		1,014,147		876,305			2,072,142
	$	3,074,392	$	4,048,477	$	4,002,880	$	(3,161,787	)	$	7,963,962

31

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of December 31, 2006	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	-	$	-	$	-		$	2
Receivables-
Customers		129,843		-		-		-			129,843
Associated companies		201,281		160,965		69,751		(196,465	)		235,532
Other		2,383		1,702		-		-			4,085
Notes receivable from associated companies		460,023		-		292,896		-			752,919
Materials and supplies, at average cost		195		238,936		221,108		-			460,239
Prepayments and other		45,314		10,389		1,843		-			57,546
		839,041		411,992		585,598		(196,465	)		1,640,166
PROPERTY, PLANT AND EQUIPMENT:
In service		16,261		4,960,453		3,378,630		-			8,355,344
Less - Accumulated provision for depreciation		5,738		2,477,004		1,335,526		-			3,818,268
		10,523		2,483,449		2,043,104		-			4,537,076
Construction work in progress		345		170,063		169,478		-			339,886
		10,868		2,653,512		2,212,582		-			4,876,962
INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,238,272		-			1,238,272
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		1,471,184		-		-		(1,471,184	)		-
Other		6,474		65,833		202		-			72,509
		1,477,658		65,833		1,301,374		(1,471,184	)		1,373,681
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		24,248		-		-		-			24,248
Property taxes		-		20,946		23,165		-			44,111
Accumulated deferred income taxes		32,939		-		-		(32,939	)		-
Other		23,544		11,542		4,753		-			39,839
		80,731		32,488		27,918		(32,939	)		108,198
	$	2,408,298	$	3,163,825	$	4,127,472	$	(1,700,588	)	$	7,999,007
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	-	$	608,395	$	861,265	$	-		$	1,469,660
Notes payable to associated companies		-		1,022,197		-		-			1,022,197
Accounts payable-
Associated companies		375,328		11,964		365,222		(196,465	)		556,049
Other		32,864		103,767		-		-			136,631
Accrued taxes		54,537		32,028		26,666		-			113,231
Other		49,906		41,401		9,634		-			100,941
		512,635		1,819,752		1,262,787		(196,465	)		3,398,709
CAPITALIZATION:
Common stockholder's equity		1,859,363		78,542		1,392,642		(1,471,184	)		1,859,363
Long-term debt		-		1,057,252		556,970		-			1,614,222
		1,859,363		1,135,794		1,949,612		(1,471,184	)		3,473,585
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		-		25,293		129,095		(32,939	)		121,449
Accumulated deferred investment tax credits		-		38,894		26,857		-			65,751
Asset retirement obligations		-		24,272		735,956		-			760,228
Retirement benefits		10,255		92,772		-		-			103,027
Property taxes		-		21,268		23,165		-			44,433
Other		26,045		5,780		-		-			31,825
		36,300		208,279		915,073		(32,939	)		1,126,713
	$	2,408,298	$	3,163,825	$	4,127,472	$	(1,700,588	)	$	7,999,007

32

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	$	(17,080	)	$	350,927		$	146,468		$	-		$	480,315
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			1,328,919			-			(1,328,919	)		-
Equity contribution from parent		710,468			700,000			1,325			(701,325	)		710,468
Short-term borrowings, net		223,942			-			13,128			(237,070	)		-
Redemptions and Repayments-
Long-term debt		-			(795,019	)		(315,155	)		-			(1,110,174	)
Short-term borrowings, net		-			(1,022,197	)		-			237,070			(785,127	)
Common stock		(600,000	)		-			-			-			(600,000	)
Common stock dividend payments		(67,000	)		-			-			-			(67,000	)
Net cash provided from (used for) financing activities		267,410			211,703			(300,702	)		(2,030,244	)		(1,851,833	)
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		-			-			(521,535	)		-			(521,535	)
Loan repayments from (loans to) associated companies, net		460,023			(242,612	)		292,896			-			510,307
Investment in subsidiary		(701,325	)		-			-			701,325			-
Other		1,091			(509	)		1,627			-			2,209
Net cash provided from (used for) investing activities		(250,330	)		(562,630	)		154,234			2,030,244			1,371,518
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

33

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
For the Nine Months Ended September 30, 2006	FES			FGCO			NGC			Eliminations		Consolidated
	(In thousands)
NET CASH PROVIDED FROM
OPERATING ACTIVITIES	$	145,390		$	72,860		$	239,855		$	-	$	458,105
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			146,704			105,241			-		251,945
Short-term borrowings, net		-			66,817			-			-		66,817
Redemptions and Reyapments-
Long-term debt		-			(146,740	)		(106,500	)		-		(253,240	)
Net cash provided from financing activities		-			66,781			(1,259	)		-		65,522
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(699	)		(131,853	)		(294,746	)		-		(427,298	)
Proceeds from asset sales		-			20,437			-			-		20,437
Sales of investment securities held in trusts		-			-			886,863			-		886,863
Purchases of investment securities held in trusts		-			-			(886,863	)		-		(886,863	)
Loans to associated companies		(145,734	)		-			57,442			-		(88,292	)
Other		1,043			(28,225	)		(1,292	)		-		(28,474	)
Net cash used for investing activities		(145,390	)		(139,641	)		(238,596	)		-		(523,627	)
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

34

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(In millions, except per share amounts)
REVENUES:
Electric utilities	$	3,260		$	2,996		$	8,685		$	7,677
Unregulated businesses		381			368			1,038			1,144
Total revenues *		3,641			3,364			9,723			8,821
EXPENSES:
Fuel and purchased power		1,495			1,317			3,801			3,306
Other operating expenses		756			758			2,255			2,230
Provision for depreciation		162			153			477			445
Amortization of regulatory assets		288			243			785			665
Deferral of new regulatory assets		(107	)		(153	)		(399	)		(379	)
General taxes		197			187			589			553
Total expenses		2,791			2,505			7,508			6,820
OPERATING INCOME		850			859			2,215			2,001
OTHER INCOME (EXPENSE):
Investment income		30			46			93			120
Interest expense		(203	)		(185	)		(593	)		(528	)
Capitalized interest		9			7			21			21
Subsidiaries’ preferred stock dividends		-			(2	)		-			(6	)
Total other expense		(164	)		(134	)		(479	)		(393	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		686			725			1,736			1,608
INCOME TAXES		273			273			695			625
INCOME FROM CONTINUING OPERATIONS		413			452			1,041			983
Discontinued operations (net of income tax benefits of
$1 million and $2 million in the three months and
nine months ended September 30, 2006, respectively) (Note 4)		-			2			-			(4	)
NET INCOME	$	413		$	454		$	1,041		$	979
BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income from continuing operations	$	1.36		$	1.40		$	3.39		$	3.00
Discontinued operations		-			0.01			-			(0.01	)
Net earnings per basic share	$	1.36		$	1.41		$	3.39		$	2.99
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		304			322			307			326
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income from continuing operations	$	1.34		$	1.39		$	3.35		$	2.98
Discontinued operations		-			0.01			-			(0.01	)
Net earnings per diluted share	$	1.34		$	1.40		$	3.35		$	2.97
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		307			325			311			329
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	1.00		$	0.45		$	1.50		$	1.35
* Includes excise tax collections of $108 million in the third quarter of both 2007 and 2006, and $308 million and $297 million in the nine
months ended September 2007 and 2006, respectively.
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

35

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(In millions)
NET INCOME	$	413		$	454		$	1,041		$	979
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(12	)		-			(34	)		-
Unrealized gain (loss) on derivative hedges		(10	)		(28	)		10			45
Change in unrealized gain on available for sale securities		26			26			89			39
Other comprehensive income (loss)		4			(2	)		65			84
Income tax expense (benefit) related to other
comprehensive income		-			(1	)		19			30
Other comprehensive income (loss), net of tax		4			(1	)		46			54
COMPREHENSIVE INCOME	$	417		$	453		$	1,087		$	1,033
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

36

FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2007			2006
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	30		$	90
Receivables-
Customers (less accumulated provisions of $38 million and
$43 million, respectively, for uncollectible accounts)		1,432			1,135
Other (less accumulated provisions of $22 million and
$24 million, respectively, for uncollectible accounts)		194			132
Materials and supplies, at average cost		543			577
Prepayments and other		207			149
		2,406			2,083
PROPERTY, PLANT AND EQUIPMENT:
In service		24,353			24,105
Less - Accumulated provision for depreciation		10,248			10,055
		14,105			14,050
Construction work in progress		933			617
		15,038			14,667
INVESTMENTS:
Nuclear plant decommissioning trusts		2,140			1,977
Investments in lease obligation bonds		738			811
Other		787			746
		3,665			3,534
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,609			5,898
Regulatory assets		4,047			4,441
Pension assets		318			-
Other		570			573
		10,544			10,912
	$	31,653		$	31,196
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	2,265		$	1,867
Short-term borrowings		573			1,108
Accounts payable		760			726
Accrued taxes		671			598
Accrued interest		215			111
Other		894			845
		5,378			5,255
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $.10 par value, authorized 375,000,000 shares-
304,835,407 and 319,205,517 shares outstanding, respectively		30			32
Other paid-in capital		5,564			6,466
Accumulated other comprehensive loss		(213	)		(259	)
Retained earnings		3,387			2,806
Unallocated employee stock ownership plan common stock-
521,818 shares		-			(10	)
Total common stockholders' equity		8,768			9,035
Long-term debt and other long-term obligations		8,617			8,535
		17,385			17,570
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,317			2,740
Asset retirement obligations		1,247			1,190
Deferred gain on sale and leaseback transaction		1,069			-
Power purchase contract loss liability		872			1,182
Retirement benefits		918			944
Lease market valuation liability		684			767
Other		1,783			1,548
		8,890			8,371
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
	$	31,653		$	31,196
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
balance sheets.

37

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	September 30,
	2007			2006
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,041		$	979
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		477			445
Amortization of regulatory assets		785			665
Deferral of new regulatory assets		(399	)		(379	)
Nuclear fuel and lease amortization		75			67
Deferred purchased power and other costs		(265	)		(323	)
Deferred income taxes and investment tax credits, net		(158	)		36
Investment impairment		16			13
Deferred rents and lease market valuation liability		(41	)		(54	)
Accrued compensation and retirement benefits		(50	)		78
Commodity derivative transactions, net		5			28
Gain on asset sales		(35	)		(38	)
Income from discontinued operations		-			4
Cash collateral		(50	)		(98	)
Pension trust contribution		(300	)		-
Decrease (increase) in operating assets-
Receivables		(329	)		(7	)
Materials and supplies		62			(30	)
Prepayments and other current assets		(39	)		(49	)
Increase (decrease) in operating liabilities-
Accounts payable		(15	)		(93	)
Accrued taxes		355			(32	)
Accrued interest		104			104
Electric service prepayment programs		(52	)		(45	)
Other		(36	)		(28	)
Net cash provided from operating activities		1,151			1,243
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		1,100			1,235
Short-term borrowings, net		-			482
Redemptions and Repayments-
Common stock		(918	)		(600	)
Preferred stock		-			(107	)
Long-term debt		(647	)		(993	)
Short-term borrowings, net		(535	)		-
Net controlled disbursement activity		6			(22	)
Stock-based compensation tax benefit		16			-
Common stock dividend payments		(464	)		(439	)
Net cash used for financing activities		(1,442	)		(444	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(1,127	)		(990	)
Proceeds from asset sales		37			83
Proceeds from sale and leaseback transaction		1,329			-
Sales of investment securities held in trusts		1,010			1,370
Purchases of investment securities held in trusts		(1,067	)		(1,381	)
Cash investments		48			109
Other		1			(13	)
Net cash provided from (used for) investing activities		231			(822	)
Net decrease in cash and cash equivalents		(60	)		(23	)
Cash and cash equivalents at beginning of period		90			64
Cash and cash equivalents at end of period	$	30		$	41
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

38

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, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  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, 2006, and the related consolidated statements of income, capitalization, common stockholders’ equity, preferred stock, and of cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(K) and Note 12 to the consolidated financial statements) dated February 27, 2007, except as to Note 2(H) and Note 16, which are as of September 14, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

October 31, 2007

39

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

Net income in the third quarter of 2007 was $413 million, or basic earnings of $1.36 per share of common stock ($1.34 diluted), compared with net income of $454 million, or basic earnings of $1.41 per share of common stock ($1.40 diluted) in the third quarter of 2006. Net income in the first nine months of 2007 was $1.04 billion, or basic earnings of $3.39 per share of common stock ($3.35 diluted), compared with net income of $979 million, or basic earnings of $2.99 per share of common stock ($2.97 diluted) in the first nine months of 2006. The decrease in FirstEnergy’s third quarter earnings was driven primarily by higher fuel and purchased power costs and increased depreciation and amortization, partially offset by higher electric sales revenues.

Change in Basic Earnings Per Share From Prior Year Periods	Three Months Ended September 30,			Nine Months Ended September 30,
Basic Earnings Per Share – 2006	$	1.41		$	2.99
Revenues		0.55			1.76
Fuel and purchased power		(0.37	)		(0.99	)
Depreciation and amortization		(0.11	)		(0.29	)
Deferral of new regulatory assets		(0.09	)		(0.01	)
Other expenses		(0.16	)		(0.36	)
Reduced common shares outstanding		0.08			0.18
Non-core asset sales/impairments – 2006		(0.01	)		0.03
PPUC NUG Accounting Adjustment – 2006		0.02			0.02
Non-core asset sales -- 2007		0.04			0.04
Saxton decommissioning regulatory asset – 2007		-			0.05
Trust securities impairment – 2007		-			(0.03	)
Basic Earnings Per Share – 2007	$	1.36		$	3.39

Regulatory Matters

Ohio

On August 15, 2007, the PUCO approved a stipulation that creates a green pricing option for customers of the Ohio Companies. The stipulation was filed on May 29, 2007 by the Ohio Companies, the PUCO Staff, and the OCC. The Green Resource Program will enable customers to support the development of alternative energy resources through their voluntary participation in this alternative to the Ohio Companies’ standard service offer for generation supply. The Green Resource Program will be established through the Ohio Companies’ purchase of Renewable Energy Certificates (RECs) at prices determined through a competitive bidding process monitored by the PUCO.

On August 16, 2007, the PUCO held a technical conference for interested parties to gain a better understanding of the Ohio Companies’ competitive generation supply plan proposal filed with the PUCO on July 10, 2007. The proposal seeks approval to conduct a competitive bidding process to provide generation service, beginning January 1, 2009, to customers who choose not to purchase electricity from an alternative supplier. The proposal is currently pending before the PUCO.

On August 29, 2007, the Supreme Court of Ohio upheld findings by the PUCO approving several provisions of the Ohio Companies’ RCP. The Court, however, remanded the portion of the order that authorized the Ohio Companies to collect deferred fuel costs through future distribution rates back to the PUCO for further consideration. The Court found recovery of competitive generation service costs through noncompetitive distribution rates unlawful. The PUCO’s order had authorized the Ohio Companies to defer increased fuel costs incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances, and to recover these deferred costs over a 25-year period beginning in 2009. On September 7, 2007, the Ohio Companies filed a Motion for Reconsideration with the Court on the issue of the deferred fuel costs. On September 10, 2007, the Ohio Companies filed an Application on remand with the PUCO proposing that the increased fuel costs be recovered through two generation-related fuel cost recovery riders during the period of October 2007 through December 2008, subject to reconciliation which is expected to continue through the first quarter of 2009. This matter is currently pending before the PUCO. Although unable to predict the ultimate outcome of this matter, the Ohio Companies intend to continue deferring the fuel costs pursuant to the RCP, pending the Court’s disposition of the Motion for Reconsideration and the PUCO’s action with respect Ohio Companies’ Application.

40

On September 25, 2007, the Ohio Governor’s proposed energy plan was officially introduced into the Ohio Senate. The bill proposes to revise state energy policy to address electric generation pricing after 2008, establish advanced energy portfolio standards and energy efficiency standards, and create GHG emission reporting and carbon control planning requirements. The bill also proposes to move to a “hybrid” system for determining rates for PLR service in which electric utilities would provide regulated generation service unless they satisfy a statutory burden to demonstrate the existence of a competitive market for retail electricity. The Senate Energy & Public Utilities Committee which has been conducting hearings on the bill and receiving testimony from interested parties, including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer groups, utility executives and others. On October 4, 2007, FirstEnergy’s Chief Executive Officer provided testimony to the Committee citing several concerns with the current version of the bill, including its lack of context in which to establish prices. He recommended that the PUCO be provided the clear statutory authority to negotiate rate plans, and in the event that negotiations do not result in rate plan agreements, a competitive bidding process be utilized to establish generation prices for customers that do not choose alternative suppliers. He also proposed that the PUCO’s statutory authority be expanded to promote societal programs such as energy efficiency, demand response, renewable power, and infrastructure improvements. Several proposed amendments to the bill have been submitted, including those from Ohio’s investor-owned electric utilities. A substitute version of the bill, which incorporated certain of the proposed amendments, was introduced into the Senate Energy & Public Utilities Committee on October 25, 2007.

Pennsylvania

On September 21 and October 5, 2007, responsive and reply briefs, respectively, were filed by the parties in the appeal of the PPUC’s January 2007 transition rate plan order to the Pennsylvania Commonwealth Court. Met-Ed and Penelec have appealed the PPUC’s decision on the denial of generation rate relief and on a consolidated income tax adjustment related to the cost of capital, while other parties appealed the PPUC’s decision on transmission rate relief. Oral arguments are expected to take place in late 2007 or early 2008.

On September 28, 2007, a Joint Petition for Settlement was filed with the PPUC for approval of Penn’s Interim Default Service Supply Plan for the three-year period covering June 1, 2008, through May 31, 2011.  For customers who choose not to shop, the plan provides for Penn to obtain market-based generation supply through an RFP by rate class for residential and commercial customers, with industrial customers being supplied through short-term markets. The settlement agreement resolves all issues in the proceeding, except those regarding incremental uncollectible accounts expense, and is either supported, or not opposed, by all parties. A PPUC hearing was held on September 11, 2007 on the uncollectible expense issue. An ALJ recommended decision is expected shortly with a PPUC Order expected in late November or early December.

Generation

Perry

On August 21, 2007, FENOC announced plans to expand used nuclear fuel storage capacity at the Perry Nuclear Power Plant. The plan calls for installing above-ground, airtight steel and concrete cylindrical canisters, cooled by natural air circulation, to store used fuel assemblies.  Initially, six canisters will be installed, with the capability to add up to 74 additional canisters as needed. Construction of the new fuel storage system, which is expected to cost approximately $30 million, is scheduled to begin in the spring of 2008, with completion planned for 2010.

Beaver Valley

On October 24, 2007, Beaver Valley Unit 1 returned to service following completion of its scheduled refueling outage that began on September 24, 2007. During the outage several improvement projects were completed, including reinforcing welds on the pressurizer, spray lines and safety relief valves, increasing the size of the containment sump strainer, and replacing a reactor coolant pump motor. The ten-year in-service inspection of the reactor vessel was also completed with no significant issues identified. Beaver Valley Unit 1 operated for 378 consecutive days when it was taken off line for the outage. In late August 2007, FENOC filed applications with the NRC seeking renewal of the operating licenses for Beaver Valley Units 1 and 2 for an additional 20 years, which would extend the operating licenses to January 29, 2036 for Unit 1 and May 27, 2047 for Unit 2.

41

Financial Matters

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

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

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

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 requirements in Pennsylvania and New Jersey. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to non-shopping retail customers under the PLR obligations in its Pennsylvania and New Jersey franchise areas.  Its net income reflects the commodity costs of securing electricity from the competitive energy services segment under partial requirements purchased power agreements with FES and non-affiliated power suppliers, including 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 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 FirstEnergy's generating facilities 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 PLR requirements of FirstEnergy's 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.

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:

42

		Three Months Ended September 30,									Nine Months Ended September 30,
								Increase									Increase
		2007			2006			(Decrease)			2007			2006			(Decrease)
		(In millions, except per share amounts)
Net Income (Loss)
By Business Segment:
Energy delivery services	$	269		$	280		$	(11	)	$	695		$	702		$	(7	)
Competitive energy services		148			169			(21	)		388			302			86
Ohio transitional generation services		16			27			(11	)		69			88			(19	)
Other and reconciling adjustments*		(20	)		(22	)		2			(111	)		(113	)		2
Total	$	413		$	454		$	(41	)	$	1,041		$	979		$	62
Basic Earnings Per Share:
Income from continuing operations	$	1.36		$	1.40		$	(0.04	)	$	3.39		$	3.00		$	0.39
Discontinued operations		-			0.01			(0.01	)		-			(0.01	)		0.01
Net earnings per basic share	$	1.36		$	1.41		$	(0.05	)	$	3.39		$	2.99		$	0.40
Diluted Earnings Per Share:
Income from continuing operations	$	1.34		$	1.39		$	(0.05	)	$	3.35		$	2.98		$	0.37
Discontinued operations		-			0.01			(0.01	)		-			(0.01	)		0.01
Net earnings per diluted share	$	1.34		$	1.40		$	(0.06	)	$	3.35		$	2.97		$	0.38

* Represents other operating segments and reconciling adjustments including interest expense on holding company debt and corporate support services revenues and expenses.

Summary of Results of Operations – Third Quarter of 2007 Compared with the Third Quarter of 2006

Financial results for FirstEnergy's major business segments in the third quarter of 2007 and 2006 were as follows:

							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 and purchased power		1,116			554			631			(806	)		1,495
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 From Continuing Operations
Before Income Taxes		444			247			27			(32	)		686
Income taxes		175			99			11			(12	)		273
Net Income	$	269		$	148		$	16		$	(20	)	$	413

43

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
Third Quarter 2006 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	2,120		$	313		$	682		$	-		$	3,115
Other		186			40			8			15			249
Internal		-			762			-			(762	)		-
Total Revenues		2,306			1,115			690			(747	)		3,364
Expenses:
Fuel and purchased power		960			515			604			(762	)		1,317
Other operating expenses		468			218			76			(4	)		758
Provision for depreciation		97			49			-			7			153
Amortization of regulatory assets		237			-			6			-			243
Deferral of new regulatory assets		(107	)		-			(46	)		-			(153	)
General taxes		157			21			5			4			187
Total Expenses		1,812			803			645			(755	)		2,505
Operating Income		494			312			45			8			859
Other Income (Expense):
Investment income		80			18			-			(52	)		46
Interest expense		(109	)		(52	)		-			(24	)		(185	)
Capitalized interest		4			3			-			-			7
Subsidiaries' preferred stock dividends		(2	)		-			-			-			(2	)
Total Other Expense		(27	)		(31	)		-			(76	)		(134	)
Income From Continuing Operations
Before Income Taxes		467			281			45			(68	)		725
Income taxes		187			112			18			(44	)		273
Income from continuing operations		280			169			27			(24	)		452
Discontinued operations		-			-			-			2			2
Net Income	$	280		$	169		$	27		$	(22	)	$	454
Changes Between Third Quarter 2007 and
Third Quarter 2006 Financial Results
Increase (Decrease)
Revenues:
External
Electric	$	220		$	25		$	34		$	-		$	279
Other		(6	)		(8	)		(1	)		13			(2	)
Internal		-			44			-			(44	)		-
Total Revenues		214			61			33			(31	)		277
Expenses:
Fuel and purchased power		156			39			27			(44	)		178
Other operating expenses		(32	)		46			4			(20	)		(2	)
Provision for depreciation		5			2			-			2			9
Amortization of regulatory assets		42			-			3			-			45
Deferral of new regulatory assets		25			-			21			-			46
General taxes		9			5			(4	)		-			10
Total Expenses		205			92			51			(62	)		286
Operating Income		9			(31	)		(18	)		31			(9	)
Other Income (Expense):
Investment income		(22	)		(13	)		-			19			(16	)
Interest expense		(11	)		8			-			(15	)		(18	)
Capitalized interest		(1	)		2			-			1			2
Subsidiaries' preferred stock dividends		2			-			-			-			2
Total Other Expense		(32	)		(3	)		-			5			(30	)
Income From Continuing Operations
Before Income Taxes		(23	)		(34	)		(18	)		36			(39	)
Income taxes		(12	)		(13	)		(7	)		32			-
Income from continuing operations		(11	)		(21	)		(11	)		4			(39	)
Discontinued operations		-			-			-			(2	)		(2	)
Net Income	$	(11	)	$	(21	)	$	(11	)	$	2		$	(41	)

44

Energy Delivery Services – Third Quarter 2007 Compared to Third Quarter 2006

Net income decreased $11 million (or 4%) to $269 million in the third quarter of 2007 compared to $280 million in the third quarter of 2006, primarily due to increased purchased power costs and higher amortization of regulatory assets, partially offset by higher revenues and reduced other operating expenses.

Revenues –

The increase in total revenues resulted from the following sources:

	Three Months Ended
	September 30,
Revenues by Type of Service	2007		2006		Increase (Decrease)
	(In millions)
Distribution services	$	1,104	$	1,124	$	(20	)
Generation sales:
Retail		942		857		85
Wholesale		207		91		116
Total generation sales		1,149		948		201
Transmission		219		177		42
Other		48		57		(9	)
Total Revenues	$	2,520	$	2,306	$	214

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

Electric Distribution KWH Deliveries
Residential	(1.7)	%
Commercial	1.4	%
Industrial	1.0	%
Total Distribution KWH Deliveries	(0.5)	%

The reduction in distribution services revenues was primarily due to distribution rate decreases for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).

The following table summarizes the price and volume factors contributing to the $201 million increase in generation revenues in the third quarter of 2007 compared to 2006:

Sources of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 5.9% decrease in sales volumes	$	(50	)
Change in prices		135
		85
Wholesale:
Effect of 95% increase in sales volumes		86
Change in prices		30
		116
Net Increase in Generation Sales	$	201

The increase in retail generation prices during the third quarter of 2007 compared to 2006 was primarily due to increased generation rates for JCP&L resulting from the New Jersey BGS auction 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 beginning in January 2007.

Transmission revenues increased $42 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred, with no material effect to current period earnings (see Outlook – State Regulatory Matters – Pennsylvania).

45

Expenses –

The net increases in revenues discussed above were offset by a $205 million increase in expenses due to the following:

· Purchased power costs were $157million higher in the third quarter of 2007 due to higher unit costs, increased volumes purchased and a decrease in purchased power cost deferrals. The increased unit costs reflected the effect of higher JCP&L purchased power unit prices resulting from the BGS auction. The increased KWH purchases in 2007 primarily resulted from more sales to the PJM wholesale market by Met-Ed and Penelec.  Deferred purchased power costs were lower due to higher generation charges to JCP&L customers.  The following table summarizes the sources of changes in purchased power costs:

Sources of Change in Purchased Power	Increase
	(In millions)
Purchased Power:
Change due to increased unit costs	$	97
Change due to increased volume		42
Decrease in NUG costs deferred		18
Net Increase in Purchased Power Costs	$	157

· Amortization of regulatory assets increased $42million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC revenues for JCP&L as discussed above.

· The deferral of new regulatory assets during the third quarter of 2007 was $25 million lower than in 2006 due in part to $40 million in reduced deferrals of transmission related PJM costs. The reduced deferral in the third quarter of 2007 was attributable to greater recovery of PJM costs in the 2007 period under the transmission service charge rider (see Outlook – State Regulatory Matters - Pennsylvania). The reduction in deferred PJM costs was partially offset by higher distribution deferrals under the RCP.

·      Other operating expenses decreased $32million, partially offsetting the above increases, due to the net effects of:

-   A decrease of $21 million in transmission expenses caused by the expiration of transmission hedging instruments and reduced financial transmission rights revenue.

-  A decrease in operation and maintenance expenses of $19million primarily due to lower employee labor and benefit costs ($10 million) lower uncollectible

    expenses related to customer receivables ($4 million) and lower leased equipment costs ($3 million).

-   An increase in miscellaneous operating expenses ($9million) resulting from increased corporate support billings from FESC.

Other Expense –

Other expense increased $32 million in 2007 compared to the third quarter of 2006 primarily due to lower investment income of $22 million resulting from the repayment of notes receivable from affiliates since the third quarter of 2006, and increased interest expense of $11 million related in part to new debt issuances by CEI, JCP&L and Penelec.

Competitive Energy Services – Third Quarter 2007 Compared to Third Quarter 2006

Net income for this segment was $148million in the third quarter of 2007 compared to $169million in the same period last year. Increased fuel and purchased power costs and other operating expenses, partially offset by higher revenues, led to the $21 million decrease.

46

Revenues –

Total revenues increased $61 million in the third quarter of 2007 compared to the same period in 2006. This increase primarily resulted from increased affiliated sales to the Ohio Companies, Met-Ed and Penelec as well as higher unit prices from the Ohio Companies. These increases were partially offset by lower sales to Penn as a result of the implementation of its competitive solicitation process in 2007. Higher retail revenues resulted from increased KWH sales in the MISO market, partially offset by reduced volume in the PJM market.

Increased non-affiliated wholesale revenues primarily reflected capacity revenues earned in PJM’s new capacity market. The capacity market was initiated in June 2007 to encourage the development of capacity resources in PJM. Lower wholesale sales to non-affiliates partially offset these increases due to decreased generation available for the non-affiliated wholesale market.

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

	Three Months Ended
	September 30,				Increase
Revenues By Type of Service	2007		2006		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	189	$	178	$	11
Wholesale		149		134		15
Total Non-Affiliated Generation Sales		338		312		26
Affiliated Generation Sales		806		762		44
Transmission		26		32		(6	)
Other		6		9		(3	)
Total Revenues	$	1,176	$	1,115	$	61

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

	Increase
Source of Change in Non-Affiliated Generation Sales	(Decrease)
	(In millions)
Retail:
Effect of 0.2% increase in sales volumes	$	1
Change in prices		10
		11
Wholesale:
Effect of 11% decrease in sales volumes		(15	)
Change in prices		30
		15
Net Increase in Non-Affiliated Generation Sales	$	26
Source of Change in Affiliated Generation Sales	Increase
	(In millions)
Ohio Companies:
Effect of 2% increase in sales volumes	$	12
Change in prices		14
		26
Pennsylvania Companies:
Effect of 8% increase in sales volumes		13
Change in prices		5
		18
Net Increase in Affiliated Generation Sales	$	44

47

Expenses -

Total expenses were $92 million higher in the third quarter of 2007 due to the net effect of the following factors:

· Purchased power costs increased $55 million due primarily to higher volumes for replacement power related to a forced outage at Perry in the third quarter of 2007 and higher market prices. The sources of change in purchased power costs are summarized in the following table:

Source of Change in Purchased Power	Increase
	(In millions)
Change due to increased unit costs	$	14
Change due to 18% increase in volume		31
Change due to new PJM capacity market		10
Total Increase in Purchased Power Costs	$	55

· Fuel costs were $16 million lower primarily due to lower coal prices ($8 million), reduced emission allowance costs ($5 million) and a decrease in natural gas consumed resulting from reduced combustion turbine generation ($2 million).

· Fossil operating costs were $32 million higher in 2007 primarily due to the absence of gains on the sales of emissions allowances recognized in 2006.

· Miscellaneous operating expenses were $13 million higher primarily due to increased contractor expenses related to the Beaver Valley Unit 1 outage and corporate support billings from FESC.

· Higher general taxes of $5 million resulted from increased gross receipts taxes and property taxes.

Ohio Transitional Generation Services – Third Quarter 2007 Compared to Third Quarter 2006

Net income decreased $11 million to $16million in the third quarter of 2007 compared to $27million in the same period last year. Higher purchased power costs were partially offset by higher generation revenues.

Revenues –

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

	Three Months Ended
	September 30,
Revenues by Type of Service	2007		2006		Increase
	(In millions)
Generation sales:
Retail	$	622	$	605	$	17
Wholesale		3		3		-
Total generation sales		625		608		17
Transmission		98		82		16
Total Revenues	$	723	$	690	$	33

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

Source of Change in Generation Sales	Increase
	(In millions)
Effect of 2% increase in sales volumes	$	10
Change in prices		7
Total Increase in Retail Generation Sales	$	17

48

The increase in generation sales was primarily due to higher weather-related usage in the third quarter of 2007 resulting from slightly higher than normal cooling degree days during the period. Average prices increased slightly due to customer usage patterns and higher composite unit prices for returning customers.

Expenses -

Purchased power costs were $27 million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power	Increase
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	-
Change due to volume		1
		1
Purchases from FES:
Change due to increased unit costs		14
Change due to volume		12
		26
Total Increase in Purchased Power Costs	$	27

The increase in volumes purchased was due to the higher retail generation sales requirements.  The higher unit costs resulted from the provision of the full-requirements PSA with FES under which purchased power unit costs reflected the increases in the Ohio Companies’ retail generation sales unit prices.

The deferral of new regulatory assets decreased by $21 million in the third quarter of 2007 compared to 2006 due to reduced cost deferrals under the Ohio Companies’ RCP.

Other – Third Quarter 2007 Compared to Third Quarter 2006

FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $2million increase in FirstEnergy’s net income in the third quarter of 2007 compared to the same quarter of 2006. The increase was primarily due to the sale of First Communications ($13 million, net of taxes) offset by higher financing costs of $14 million.

49

Summary of Results of Operations – First Nine Months of 2007 Compared with the First Nine Months of 2006

Financial results for FirstEnergy's major business segments in the first nine months of 2007 and 2006 were as follows:

							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 and purchased power		2,838			1,461			1,712			(2,210	)		3,801
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 From Continuing Operations
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

50

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Nine Months 2006 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	5,434		$	955		$	1,790		$	-		$	8,179
Other		442			122			18			60			642
Internal		14			1,997			-			(2,011	)		-
Total Revenues		5,890			3,074			1,808			(1,951	)		8,821
Expenses:
Fuel and purchased power		2,343			1,416			1,558			(2,011	)		3,306
Other operating expenses		1,197			838			185			10			2,230
Provision for depreciation		282			143			-			20			445
Amortization of regulatory assets		650			-			15			-			665
Deferral of new regulatory assets		(275	)		-			(104	)		-			(379	)
General taxes		459			70			7			17			553
Total Expenses		4,656			2,467			1,661			(1,964	)		6,820
Operating Income		1,234			607			147			13			2,001
Other Income (Expense):
Investment income		244			35			-			(159	)		120
Interest expense		(310	)		(148	)		(1	)		(69	)		(528	)
Capitalized interest		11			9			-			1			21
Subsidiaries' preferred stock dividends		(9	)		-			-			3			(6	)
Total Other Expense		(64	)		(104	)		(1	)		(224	)		(393	)
Income From Continuing Operations
Before Income Taxes		1,170			503			146			(211	)		1,608
Income taxes		468			201			58			(102	)		625
Income from continuing operations		702			302			88			(109	)		983
Discontinued operations		-			-			-			(4	)		(4	)
Net Income	$	702		$	302		$	88		$	(113	)	$	979
Changes Between First Nine Months 2007
and First Nine Months 2006
Financial Results Increase (Decrease)
Revenues:
External
Electric	$	714		$	18		$	152		$	-		$	884
Other		65			(6	)		8			(49	)		18
Internal		(14	)		213			-			(199	)		-
Total Revenues		765			225			160			(248	)		902
Expenses:
Fuel and purchased power		495			45			154			(199	)		495
Other operating expenses		58			1			33			(67	)		25
Provision for depreciation		19			10			-			3			32
Amortization of regulatory assets		115			-			5			-			120
Deferral of new regulatory assets		(24	)		-			4			-			(20	)
General taxes		27			11			(4	)		2			36
Total Expenses		690			67			192			(261	)		688
Operating Income		75			158			(32	)		13			214
Other Income (Expense):
Investment income		(54	)		(22	)		1			48			(27	)
Interest expense		(37	)		4			-			(32	)		(65	)
Capitalized interest		(4	)		4			-			-			-
Subsidiaries' preferred stock dividends		9			-			-			(3	)		6
Total Other Expense		(86	)		(14	)		1			13			(86	)
Income From Continuing Operations
Before Income Taxes		(11	)		144			(31	)		26			128
Income taxes		(4	)		58			(12	)		28			70
Income from continuing operations		(7	)		86			(19	)		(2	)		58
Discontinued operations		-			-			-			4			4
Net Income	$	(7	)	$	86		$	(19	)	$	2		$	62

51

Energy Delivery Services – First Nine Months of 2007 Compared to First Nine Months of 2006

Net income decreased $7 million (or 1%) to $695 million in the first nine months of 2007 compared to $702 million in the first nine months of 2006, primarily due to increased revenues partially offset by higher operating expenses and other expenses.

Revenues –

The increase in total revenues resulted from the following sources:

	Nine Months Ended
	September 30,
Revenues by Type of Service	2007		2006		Increase
	(In millions)
Distribution services	$	2,996	$	2,972	$	24
Generation sales:
Retail		2,417		2,138		279
Wholesale		489		196		293
Total generation sales		2,906		2,334		572
Transmission		595		426		169
Other		158		158		-
Total Revenues	$	6,655	$	5,890	$	765

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

Electric Distribution KWH Deliveries
Residential	4.4	%
Commercial	3.4	%
Industrial	(0.4	)%
Total Distribution KWH Deliveries	2.5	%

The increase in electric distribution deliveries to customers was primarily due to higher weather-related usage during the first nine months of 2007 compared to the same period of 2006 (heating degree days increased by 13.7% and cooling degree days increased by 9.5%). The higher revenues from increased distribution deliveries were partially offset by distribution rate decreases for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).

The following table summarizes the price and volume factors contributing to the $572 million increase in non-affiliated generation sales revenues in 2007 compared to 2006:

Sources of Change in Generation Sales	Increase (Decrease)
	(In millions)
Retail:
Effect of 2% decrease in sales volumes	$	(38	)
Change in prices		317
		279
Wholesale:
Effect of 118% increase in sales volumes		232
Change in prices		61
		293
Net Increase in Generation Sales	$	572

The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in Penn’s service territory in the first nine months of 2007. The increase in retail generation prices during the first nine months of 2007 compared to 2006 was primarily due to increased generation rates for JCP&L resulting from the New Jersey BGS auction process and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market beginning in January 2007.

52

Transmission revenues increased $169 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of transmission cost recovery. 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 partially offset by a $690 million increase in expenses due to the following:

· Purchased power costs were $495million higher in the first nine months of 2007 due to higher unit costs and volumes purchased. The increased unit costs reflected the effect of higher JCP&L costs resulting from the BGS auction process. The increased purchases in 2007 were due primarily to higher sales to the wholesale market.  The following table summarizes the sources of changes in purchased power costs:

Sources of Change in Purchased Power	Increase
	(In millions)
Purchased Power:
Change due to increased unit costs	$	261
Change due to increased volume		174
Decrease in NUG costs deferred		60
Net Increase in Purchased Power Costs	$	495

· Other operating expenses increased $58million due to the net effects of:

-     An increase of $80million in MISO and PJM transmission expenses, resulting primarily from higher congestion costs.

-     A decrease in miscellaneous operating expenses of $10million primarily due to changes in the assessment of regulatory fees and employee benefits   from FESC.

-     A decrease in operation and maintenance expenses of $9million primarily due to increased labor activities devoted to construction projects in 2007.

· Amortization of regulatory assets increased $115million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC rates for JCP&L as discussed above.

· The deferral of new regulatory assets during the first nine months of 2007 was $24 million higher in 2007 primarily due to the deferral of previously expensed decommissioning costs of $27million related to the Saxton nuclear research facility (see Outlook – State Regulatory Matters - Pennsylvania), increased RCP distribution deferrals of $23 million, offset by a reduction in deferred PJM transmission costs of $30 million.

·   Depreciation expense increased $19 million and property taxes increased $27 million due primarily to property additions since the third quarter of 2006.

Other Expense –

Other expense increased $86million in 2007 compared to the first nine months of 2006 primarily due to lower investment income of $54million resulting from the repayment of notes receivable from affiliates since the third quarter of 2006 and increased interest expense of $37million related to new debt issuances by CEI, JCP&L and Penelec.

Competitive Energy Services – First Nine Months of 2007 Compared to First Nine Months of 2006

Net income for this segment was $388million in the first nine months of 2007 compared to $302million in the same period last year. This increase reflects an improvement in gross generation margin and lower nuclear production costs, which were partially offset by increased depreciation and general taxes and reduced investment income.

53

Revenues –

Total revenues increased $225million in the first nine months of 2007 compared to the same period in 2006. This increase primarily resulted from higher unit prices under affiliated generation sales to the Ohio Companies and increased retail sales, which were partially offset by lower non-affiliated wholesale sales.

The higher retail revenues resulted from increased sales in both the MISO and PJM markets. The increase in MISO retail sales primarily reflect FES’ increased sales to shopping customers in Penn’s service territory. Lower non-affiliated wholesale revenues reflected the effect of decreased generation available for the non-affiliated wholesale market due to increased affiliated company power sales under the Ohio Companies’ full-requirements PSA and the partial-requirements power sales agreement with Met-Ed and Penelec.

The increased affiliated company generation revenues were due to higher unit prices and increased sales volumes. The increase in PSA sales to the Ohio Companies was due to their higher retail generation sales requirements. The higher unit prices resulted from the provision of the full-requirements PSA under which PSA rates reflect the increases in the Ohio Companies’ retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn due to the implementation of its competitive solicitation process in 2007.

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

	Nine Months Ended
	September 30,				Increase
Revenues by Type of Service	2007		2006		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	547	$	445	$	102
Wholesale		425		509		(84	)
Total Non-Affiliated Generation Sales		972		954		18
Affiliated Generation Sales		2,210		1,997		213
Transmission		71		96		(25	)
Other		46		27		19
Total Revenues	$	3,299	$	3,074	$	225

Transmission revenues decreased $25 million due to reduced retail load in the MISO market, lower transmission rates and reduced financial transmission rights auction revenue.

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

	Increase
Source of Change in Non-Affiliated Generation Sales	(Decrease)
	(In millions)
Retail:
Effect of 12% increase in sales volumes	$	52
Change in prices		50
		102
Wholesale:
Effect of 26% decrease in sales volumes		(131	)
Change in prices		47
		(84	)
Net Increase in Non-Affiliated Generation Sales	$	18
Source of Change in Affiliated Generation Sales	Increase
	(In millions)
Ohio Companies:
Effect of 4% increase in sales volumes	$	56
Change in prices		89
		145
Pennsylvania Companies:
Effect of 12% increase in sales volumes		54
Change in prices		14
		68
Net Increase in Affiliated Generation Sales	$	213

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Expenses -

Total expenses increased $67 million in the first nine months of 2007 due to the following factors:

· Purchased power costs increased $86 million due principally to higher volumes for replacement power related to the forced outages at Bruce Mansfield and Perry.

· Higher fossil operating costs of $43 million due to the absence of gains from the sale of emissions allowances recognized in 2006 ($24 million) and increased scheduled maintenance outages ($13 million).

· Higher depreciation expenses of $10 million were due to property additions.

· Higher general taxes of $11 million resulted from increased gross receipts taxes and property taxes.

Partially offsetting the higher costs were:

· Fuel costs were $41 million lower primarily due to reduced coal costs and emission allowance costs offset by increases in nuclear fuel and natural gas costs. Coal costs were reduced due to a $14 million inventory adjustment and $23 million of reduced coal consumption reflecting lower generation. Reduced emission allowance costs ($18 million) were partially offset by increased natural gas costs ($4 million) due to increased consumption and nuclear fuel costs ($8 million) due to increased consumption and higher prices.

·        Nuclear operating costs were $54 million lower due to fewer outages in 2007 compared to 2006 and reduced employee benefit costs.

Other Expense –

Total other expense in the first nine months of 2007 was $14million higher than the 2006 period primarily due to decreased earnings on nuclear decommissioning trust investments (including a $16 million impairment in 2007).

Ohio Transitional Generation Services – First Nine Months of 2007 Compared to First Nine Months of 2006

Net income for this segment decreased to $69million in the first nine months of 2007 from $88 million in the same period last year. Higher operating expenses, primarily for purchased power, were partially offset by higher generation revenues.

Revenues –

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

	Nine Months Ended
	September 30,				Increase
Revenues by Type of Service	2007		2006		(Decrease)
	(In millions)
Generation sales:
Retail	$	1,712	$	1,581	$	131
Wholesale		7		12		(5	)
Total generation sales		1,719		1,593		126
Transmission		248		213		35
Other		1		2		(1	)
Total Revenues	$	1,968	$	1,808	$	160

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

Source of Change in Generation Sales	Increase
	(In millions)
Retail:
Effect of 4% increase in sales volumes	$	66
Change in prices		65
Total Increase in Retail Generation Sales	$	131

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The increase in generation sales was primarily due to higher weather-related usage in the first nine months of 2007 compared to the same period of 2006, as discussed above, and reduced customer shopping. Average prices increased primarily due to higher composite unit prices for returning customers. The percentage of generation services provided by alternative suppliers to total sales delivered by the Ohio Companies in their service areas decreased by 6.4percentage points from the same period last year.

Expenses -

Purchased power costs were $153million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power	Increase
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	6
Change due to volume purchased		2
		8
Purchases from FES:
Change due to increased unit costs		89
Change due to volume purchased		56
		145
Total Increase in Purchased Power Costs	$	153

The increase in purchases was due to the higher retail generation sales requirements.  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 $33 million primarily due to MISO transmission-related expenses. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.

Other – First Nine Months of 2007 Compared to First Nine Months of 2006

FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $2million increase in FirstEnergy’s net income in the first nine months of 2007. The increase was primarily due to the sale of First Communications ($13 million, net of taxes), the absence of subsidiaries’ preferred stock dividends in 2007 ($6 million) and the absence of a $4million loss included in 2006 results from discontinued operations (see Note 4).

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2007 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.

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. FirstEnergy and certain of its subsidiaries also have access to $2.75 billion of short-term financing under a revolving credit facility which expires in 2011.  Under the terms of the facility, FirstEnergy is permitted to have up to $1.5 billion in outstanding borrowings at any time, subject to the facility cap of $2.75 billion of aggregate outstanding borrowings by it and its subsidiaries that are also parties to such facility. In the first nine months of 2007, FirstEnergy received $1.8 billion of cash dividends and return of capital from its subsidiaries and paid $464 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.

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On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or approximately 4.5%, of its outstanding common stock at an initial price of approximately $900 million pursuant to an accelerated share repurchase program.  FirstEnergy acquired these shares under its previously announced authorization to repurchase up to 16 million shares of its common stock. The share repurchase was funded with short-term borrowings, which have since been repaid with the proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion (net after-tax proceeds of approximately $1.2 billion) for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034.  A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates.  The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases.  The notes and certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements. FES’ registration obligations under the registration rights agreement applicable to the $1.135 billion principal amount of pass through certificates issued in connection with the transaction were satisfied in September 2007, at which time the transaction was classified as an operating lease under GAAP for FES and FirstEnergy. This transaction generated tax capital gains of approximately $752 million. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowances in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 3).

As of September 30, 2007, FirstEnergy had $30 million of cash and cash equivalents compared with $90 million as of December 31, 2006. The major sources of changes in these balances are summarized below.

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 $1.2 billion in the first nine months of 2007 and 2006 summarized as follows:

	Nine Months Ended
	September 30,
Operating Cash Flows	2007			2006
	(In millions)
Net income	$	1,041		$	979
Non-cash charges		358			497
Pension trust contribution		(300	)		-
Working capital and other		52			(233	)
	$	1,151		$	1,243

Net cash provided from operating activities decreased by $92 million in the first nine months of 2007 compared to the first nine months of 2006 primarily due to a $300 million pension trust contribution in 2007 and a $139 million change in non-cash charges, partially offset by a $285 million change in working capital and other and a $62 million increase in net income (see Results of Operations above). The decrease in non-cash charges and increase from working capital primarily reflects changes to deferred income taxes and accrued taxes related to the Bruce Mansfield Unit 1 sale and leaseback transaction discussed above. Excluding the tax effects of the sale and leaseback transaction, the changes in working capital and other primarily resulted from a $322 million increase in receivables due to higher sales, partially offset by $92 million from reduced materials and supplies inventories due primarily to lower coal inventory levels and $78 million of decreased payments for accounts payable, reflecting a change in the timing of payments from the first nine months of 2006.

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Cash Flows From Financing Activities

In the first nine months of 2007, cash used for financing activities was $1.4 billion compared to $444 million in the first nine months of 2006. The increase was primarily due to more common shares repurchased in 2007 than in 2006 and the repayment of short-term borrowings in 2007. The following table summarizes security issuances and redemptions.

	Nine Months Ended
	September 30,
Securities Issued or Redeemed	2007			2006
	(In millions)
New issues
Pollution control notes	$	-		$	253
Secured notes		-			382
Unsecured notes		1,100			600
	$	1,100		$	1,235
Redemptions
First mortgage bonds	$	287		$	1
Pollution control notes		4			311
Senior secured notes		203			181
Unsecured notes		153			500
Common stock		918			600
Preferred stock		-			107
	$	1,565		$	1,700
Short-term borrowings, net	$	(535	)	$	482

FirstEnergy had approximately $573 million of short-term indebtedness as of September 30, 2007 compared to approximately $1.1 billion as of December 31, 2006. Available bank borrowing capability as of September 30, 2007 included the following:

Borrowing Capability (In millions)
Short-term credit facilities(1)	$	2,870
Accounts receivable financing facilities		550
Utilized		(570	)
LOCs		(337	)
Net available capability	$	2,513

   

⁽¹⁾ Includes the  $2.75 billion revolving credit facility described below, a $100 million revolving credit facility that expires in December 2009 and a $20 million uncommitted line of credit.

As of September 30, 2007, the Ohio Companies and Penn had the aggregate capability to issue approximately $3.1 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $543 million, $459 million and $112 million, respectively, as of September 30, 2007. JCP&L satisfied the provision of its senior note indenture for the release of all FMBs held as collateral for senior notes in May 2007, subsequently repaid its other remaining FMBs and, effective September 14, 2007, discharged and released its mortgage indenture.

The applicable earnings coverage tests in the respective charters of OE, TE, Penn and JCP&L are currently inoperative. In the event that any of them issues preferred stock in the future, the applicable earnings coverage test will govern the amount of preferred stock that may be issued. CEI, Met-Ed and Penelec do not have similar restrictions and could issue up to the number of preferred shares authorized under their respective charters.

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As of September 30, 2007, approximately $1.0 billion of capacity remained unused under an existing FirstEnergy shelf registration statement filed with the SEC in 2003 to support future securities issuances. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units. As of September 30, 2007, OE had approximately $400 million of capacity remaining unused under a shelf registration for unsecured debt securities filed with the SEC in 2006.

FirstEnergy and certain of its subsidiaries are parties to a $2.75 billion five-year revolving credit facility (included in the borrowing capability table above). FirstEnergy may request an increase in the total commitments available under this facility up to a maximum of $3.25 billion. Commitments under the facility are available until August 24, 2011, unless the lenders agree, at the request of the Borrowers, to two 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:

	Revolving			Regulatory and
	Credit Facility			Other Short-Term
Borrower	Sub-Limit			Debt Limitations(1)
	(In millions)
FirstEnergy	$	2,750		$	-	(2)
OE		500			500
Penn		50			41
CEI		250	(3)		500
TE		250	(3)		500
JCP&L		425			423
Met-Ed		250			250	(4)
Penelec		250			250	(4)
FES		250			-	(2)
ATSI		-	(5)		50

⁽¹⁾ As of September 30, 2007.

⁽²⁾ No regulatory approvals, statutory or charter limitations applicable.

⁽³⁾ Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s.

⁽⁴⁾ Excluding amounts which may be borrowed under the regulated money pool.

⁽⁵⁾ The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) such borrower has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed the obligations of such borrower under the facility.

The revolving credit facility, combined with an aggregate $550 million ($255 million unused as of September 30, 2007) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet working capital requirements and for other general corporate purposes 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, 2007, FirstEnergy and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy	57	%
OE	47	%
Penn	21	%
CEI	60	%
TE	55	%
JCP&L	31	%
Met-Ed	46	%
Penelec	50	%
FES	48	%

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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 2007 was 5.66% for the regulated companies’ money pool and 5.65% 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 Companies’ securities ratings as of October 18, 2007. The ratings outlook from Moody’s is stable for FES and positive for all other companies. The ratings outlook from S&P on all securities is negative.

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

On February 21, 2007, FirstEnergy made a $700 million equity investment in FES, all of which was subsequently contributed to FGCO and used to pay down generation asset transfer-related promissory notes owed to the Ohio Companies and Penn. OE used its $500 million of proceeds to repurchase shares of its common stock from FirstEnergy.

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

On May 21, 2007, JCP&L issued $550 million of senior unsecured debt securities, consisting of $250 million of 5.65% senior notes due 2017 and $300 million of 6.15% senior notes due 2037.  A portion of the proceeds of the offering were used to redeem outstanding FMB of JCP&L comprised of $125 million principal amount of 7.50% series and $150 million principal amount of 6.75% series.  On July 1, 2007, JCP&L also redeemed all $12.2 million outstanding principal amount of its remaining series of FMB. In addition, $125 million of proceeds were used to repurchase shares of its common stock from FirstEnergy.  The remaining proceeds were used for general corporate purposes.

As described above, on July 13, 2007, FGCO completed the sale and leaseback of a 93.825% undivided interest in Unit 1 of the Bruce Mansfield Generating Plant. Net after-tax proceeds of approximately $1.2 billion from the transaction were used to repay short-term borrowings from, and to invest in, the FirstEnergy non-utility money pool. The repayments and investment allowed FES to reduce its investment in that money pool in order to repay approximately $250 million of external bank borrowings and fund a $600 million equity repurchase from FirstEnergy. FirstEnergy used these funds to reduce its external short term borrowings as discussed above.

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

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

Cash Flows From Investing Activities

Net cash flows provided from investing activities resulted principally from the proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction, partially offset by property additions. Energy delivery services expenditures for property additions primarily include expenditures related to transmission and distribution facilities. Capital expenditures by the competitive energy services segment are principally generation-related. The following table summarizes investing activities for the nine months ended September 30, 2007 and 2006 by segment:

Summary of Cash Flows	Property
Provided from (Used for) Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Nine Months Ended September 30, 2007
Energy delivery services	$	(609	)	$	34		$	(2	)	$	(577	)
Competitive energy services		(462	)		1,345			(1	)		882
Other		(56	)		(5	)		2			(59	)
Inter-Segment reconciling items		-			(15	)		-			(15	)
Total	$	(1,127	)	$	1,359		$	(1	)	$	231
Nine Months Ended September 30, 2006
Energy delivery services	$	(489	)	$	196		$	(8	)	$	(301	)
Competitive energy services		(473	)		(7	)		(1	)		(481	)
Other		(28	)		31			20			23
Inter-Segment reconciling items		-			(63	)		-			(63	)
Total	$	(990	)	$	157		$	11		$	(822	)

In the first nine months of 2007, net cash provided from investing activities was $231 million compared to $822 million used for investing activities in the first nine months of 2006. The change was principally due to $1.3 billion in proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction described above.  Partially offsetting the cash proceeds from the sale and leaseback transaction was a $137 million increase in property additions and a $61 million decrease in cash provided from cash investments, primarily from the use of restricted cash investments to repay debt during 2006.

During the remaining three months of 2007, capital requirements for property additions and capital leases are expected to be approximately $460 million. FirstEnergy and the Companies have additional requirements of approximately $10 million for maturing long-term debt during the remainder of 2007. 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 2007-2011 is expected to be nearly $8.0 billion (excluding nuclear fuel), of which approximately $1.5 billion applies to 2007. Investments for additional nuclear fuel during the 2007-2011 period are estimated to be approximately $1.2 billion, of which about $95 million applies to 2007. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $810 million and $100 million, respectively, as the nuclear fuel is consumed.

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 FirstEnergy’s credit ratings.

As of September 30, 2007, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.7 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)	$	647
LOC (long-term debt) – interest coverage (2)		9
Other (3)		575
		1,231
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts		37
LOC (long-term debt) – interest coverage (2)		3
Other (4)		2,686
		2,726
Surety Bonds		75
LOC (long-term debt) – interest coverage (2)		5
LOC (non-debt) (5)(6)		690
Total Guarantees and Other Assurances	$	4,727

⁽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 pollution control revenue bonds with various maturities. The principal amount of floating-rate pollution control revenue bonds of $1.6 billion is reflected in long-term debt on FirstEnergy’s consolidated balance sheets.

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

⁽⁴⁾ Includes FES’ guarantee of FGCO’s obligations under the sale and leaseback of Bruce Mansfield Unit 1.

⁽⁵⁾ Includes $71 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility.

⁽⁶⁾ Includes approximately $194 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE.

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

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of September 30, 2007, FirstEnergy’s maximum exposure under these collateral provisions was $442 million.

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.

FirstEnergy has guaranteed the obligations of the operators of the TEBSA project up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($27 million as of September 30, 2007), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. The LOC was reduced to $19 million on October 15, 2007.

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As described above, on July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in the Bruce Mansfield Plant 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.

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 Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. As of September 30, 2007, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $2.0 billion.

FirstEnergy has equity ownership interests in certain businesses that are accounted for using the equity method. 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 change in the fair value of commodity derivative contracts related to energy production during the three months and nine months ended September 30, 2007 is summarized in the following table:

	Three Months Ended									Nine Months Ended
Increase (Decrease) in the Fair Value	September 30, 2007									September 30, 2007
of Commodity 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	$	(845	)	$	(12	)	$	(857	)	$	(1,140	)	$	(17	)	$	(1,157	)
Additions/change in value of existing contracts		(38	)		-			(38	)		69			(6	)		63
Settled contracts		47			5			52			235			16			251
Outstanding net liability at end of period (1)		(836	)		(7	)		(843	)		(836	)		(7	)		(843	)
Non-commodity Net Liabilities at End of Period:
Interest rate swaps (2)		-			(8	)		(8	)		-			(8	)		(8	)
Net Liabilities - Derivative Contracts at End of Period	$	(836	)	$	(15	)	$	(851	)	$	(836	)	$	(15	)	$	(851	)
Impact of Changes in Commodity Derivative Contracts(3)
Income Statement effects (pre-tax)	$	4		$	-		$	4		$	4		$	-		$	4
Balance Sheet effects:
Other comprehensive income (pre-tax)	$	-		$	5		$	5		$	-		$	10		$	10
Regulatory assets (net)	$	(5	)	$	-		$	(5	)	$	(300	)	$	-		$	(300	)

⁽¹⁾ Includes $836 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.

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

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

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Derivatives are included on the Consolidated Balance Sheet as of September 30, 2007 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	-		$	42		$	42
Other liabilities		-			(51	)		(51	)
Non-Current-
Other deferred charges		36			16			52
Other non-current liabilities		(872	)		(22	)		(894	)
Net liabilities	$	(836	)	$	(15	)	$	(851	)

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. Sources of information for the valuation of commodity derivative contracts as of September 30, 2007 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2007(1)			2008			2009			2010			2011			Thereafter			Total
	(In millions)
Prices actively quoted(2)	$	-		$	-		$	-		$	-		$	-		$	-		$	-
Other external sources(3)		(60	)		(239	)		(173	)		(150	)		-			-			(622	)
Prices based on models		-			-			-			-			(114	)		(107	)		(221	)
Total(4)	$	(60	)	$	(239	)	$	(173	)	$	(150	)	$	(114	)	$	(107	)	$	(843	)

⁽¹⁾     For the last quarter of 2007.

⁽²⁾     Exchange traded.

⁽³⁾     Broker quote sheets.

⁽⁴⁾    Includes $836 million in non-hedge commodity derivative contracts (primarily with NUGs), which 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, 2007. Based on derivative contracts held as of September 30, 2007, an adverse 10% change in commodity prices would decrease net income by approximately $6 million during the next 12 months.

Interest Rate Swap Agreements- Fair Value Hedges

FirstEnergy utilizes fixed-for-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk associated with its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues – protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. During the first nine months of 2007, FirstEnergy paid $8 million to terminate swaps with a notional amount $150 million as its subsidiary redeemed the associated hedged debt.  The loss was recognized as interest expense during the nine-month period.  As of September 30, 2007, the debt underlying the $600 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.11%, which the swaps have converted to a current weighted average variable rate of 5.72%.

	September 30, 2007							December 31, 2006
	Notional		Maturity		Fair			Notional		Maturity		Fair
Interest Rate Swaps	Amount		Date		Value			Amount		Date		Value
	(In millions)
Fair value hedges	$	100		2008	$	(1	)	$	100		2008	$	(2	)
		50		2010		-			50		2010		(1	)
		300		2013		(4	)		300		2013		(6	)
		150		2015		(9	)		150		2015		(10	)
		-		2025		-			50		2025		(2	)
		-		2031		-			100		2031		(6	)
	$	600			$	(14	)	$	750			$	(27	)

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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 2007 and 2008. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first nine months of 2007, FirstEnergy terminated forward swaps with an aggregate notional value of $1.6 billion. FirstEnergy paid $20 million in cash related to the terminations, which will be recognized over the terms of the associated future debt. There was no ineffective portion associated with the loss. As of September 30, 2007, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $400 million and an aggregate fair value of $5 million.

	September 30, 2007							December 31, 2006
	Notional		Maturity		Fair			Notional		Maturity		Fair
Forward Starting Swaps	Amount		Date		Value			Amount		Date		Value
	(In millions)
Cash flow hedges	$	25		2015	$	-		$	25		2015	$	-
		300		2017		5			200		2017		(4	)
		25		2018		(1	)		25		2018		(1	)
		50		2020		1			50		2020		1
	$	400			$	5		$	300			$	(4	)

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $1.4 billion as of September 30, 2007 and December 31, 2006. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $139 million reduction in fair value as of September 30, 2007.

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, 2007, the largest credit concentration with one party (currently rated investment grade) represented 10.9% of FirstEnergy‘s total credit risk. Within FirstEnergy’s unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserves, were with investment-grade counterparties as of September 30, 2007.

Outlook

State Regulatory Matters

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

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

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

· providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

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· itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges;

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

· requiring corporate separation of regulated and unregulated business activities.

The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $227 million as of September 30, 2007 (JCP&L - $93 million, Met-Ed - $43 million and Penelec - $91 million). Regulatory assets not earning a current return will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets by company:

	September 30,		December 31,		Increase
Regulatory Assets*	2007		2006		(Decrease)
	(In millions)
OE	$	717	$	741	$	(24	)
CEI		856		855		1
TE		215		248		(33	)
JCP&L		1,758		2,152		(394	)
Met-Ed		459		409		50
ATSI		42		36		6
Total	$	4,047	$	4,441	$	(394	)

 * Penelec had net regulatory liabilities of approximately $77 million and $96 million as of September 30, 2007 and December 31, 2006, 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	2007			2006			(Decrease)
	(In millions)
Regulatory transition costs	$	2,583		$	3,266		$	(683	)
Customer shopping incentives		537			603			(66	)
Customer receivables for future income taxes		257			217			40
Societal benefits charge		(11	)		11			(22	)
Loss on reacquired debt		58			43			15
Employee postretirement benefits		41			47			(6	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(118	)		(145	)		27
Asset removal costs		(177	)		(168	)		(9	)
Property losses and unrecovered plant costs		11			19			(8	)
MISO/PJM transmission costs		309			213			96
Fuel costs - RCP		175			113			62
Distribution costs - RCP		298			155			143
Other		84			67			17
Total	$	4,047		$	4,441		$	(394	)

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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 (PUCO, FERC, NERC and the U.S. – Canada Power System Outage Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training and emergency response preparedness recommended for completion in 2004. On July 14, 2004, NERC independently verified that FirstEnergy had implemented the various initiatives to be completed by June 30 or summer 2004, with minor exceptions noted by FirstEnergy, which exceptions are now essentially complete. FirstEnergy is 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 equipment or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability entities may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future, which could require additional, material expenditures.

As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L’s ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a stipulation that incorporates the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L’s Planning and Operations and Maintenance programs and practices. On February 11, 2005, JCP&L met with the DRA to discuss reliability improvements. The SRM completed his work and issued his final report to the NJBPU on June 1, 2006. JCP&L filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L continues to file compliance reports reflecting activities associated with the MOU and stipulation.

The EPACT served, among other things, partly to amend the Federal Power Act by adding a new Section 215, which requires that a new ERO establish and enforce reliability standards for the bulk-power system, subject to review by the FERC. Subsequently, the FERC certified NERC as the ERO, approved NERC's Compliance Monitoring and Enforcement Program and approved a set of reliability standards, which became mandatory and enforceable on June 18, 2007 with penalties and sanctions for noncompliance. The FERC also approved a delegation agreement between NERC and ReliabilityFirst Corporation, one of eight Regional Entities that carry out enforcement for NERC.  All of FirstEnergy’s facilities are located within the ReliabilityFirst region.

To date, FERC has approved 83 of the 107 reliability standards proposed by NERC. Nevertheless, the FERC has directed NERC to submit improvements to 56 of the 83 approved standards and has endorsed NERC's process for developing reliability standards and its associated work plan. On May 4, 2007, NERC submitted 24 proposed Violation Risk Factors that would operate as a system of weighting the risk to the power grid associated with a particular reliability standard violation. The FERC issued an order approving 22 of those factors on June 26, 2007. Further, NERC adopted eight cyber security standards and filed them with the FERC for approval. On December 11, 2006, the FERC Staff provided its preliminary assessment of the cyber security standards and cited various deficiencies in the proposed standards. Numerous parties, including FirstEnergy, provided comments on the preliminary assessment. The standards remain pending before the FERC. Separately, on July 20, 2007, the FERC issued a NOPR proposing to adopt eight related Critical Infrastructure Protection Reliability Standards. On October 5, 2007, numerous parties, including FirstEnergy, provided comments on the proposed Critical Infrastructure Protection standards. These standards, and FirstEnergy’s comments thereon, are pending before FERC.

FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the FERC's guidance to NERC in its March 16, 2007 Final Rule on Mandatory Reliability Standards, it appears that the FERC may eventually adopt stricter standards than those just approved. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates. If FirstEnergy is unable to meet the reliability standards for its bulk power system in the future, it could have a material adverse effect on FirstEnergy’s and its subsidiaries’ financial condition, results of operations and cash flows.

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On April 18-20, 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy's bulk-power system within the Midwest ISO region and found FirstEnergy to be in full compliance with all audited reliability standards.  Similarly, ReliabilityFirst has scheduled a compliance audit of FirstEnergy's bulk-power system within the PJM region in 2008. FirstEnergy does not expect any material adverse impact to its financial condition as a result of these audits.

Ohio

The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2007 through 2010:

Amortization							Total
Period	OE		CEI		TE		Ohio
	(In millions)
2007	$	176	$	108	$	92	$	376
2008		209		126		113		448
2009		-		217		-		217
2010		-		269		-		269
Total Amortization	$	385	$	720	$	205	$	1,310

Several parties subsequently filed appeals to the Supreme Court of Ohio in connection with certain portions of the RCP approved by the PUCO. In its order, the PUCO authorized the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs, all such costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a 25-year period through distribution rates, which was expected to begin on January 1, 2009 for OE and TE, and approximately May 2009 for CEI.  Through September 30, 2007, the deferred fuel costs, including interest, were $89 million, $61 million and $26 million for OE, CEI and TE, respectively.

On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated certain provisions of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” because fuel costs are a component of generation service, not distribution service, and because the Court concluded the PUCO did not address whether the deferral of fuel costs was anticompetitive.  The Court remanded the matter to the PUCO for further consideration consistent with the Court’s Opinion on this issue and affirmed the PUCO’s Order in all other respects. On September 7, 2007, the Ohio Companies filed a Motion for Reconsideration with the Court. On September 10, 2007 the Ohio Companies filed an Application with the PUCO that requests the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. The Ohio Companies requested the riders become effective in October 2007 and end in December 2008, subject to reconciliation which is expected to continue through the first quarter of 2009. This matter is currently pending before the PUCO. Although unable to predict the ultimate outcome of this matter, the Ohio Companies intend to continue deferring the fuel costs pursuant to the RCP, pending the Court’s disposition of the Motion for Reconsideration and the PUCO’s action with respect to the Ohio Companies’ Application.

On August 31, 2005, the PUCO approved a rider recovery mechanism through which the Ohio Companies may recover all MISO transmission and ancillary service related costs incurred during each year ending June 30. Pursuant to the PUCO’s order, the Ohio Companies, on May 1, 2007, filed revised riders, which became effective on July 1, 2007.  The revised riders represent an increase over the amounts collected through the 2006 riders of approximately $64 million annually.  If it is subsequently determined by the PUCO that adjustments to the rider as filed are necessary, such adjustments, with carrying costs, will be incorporated into the 2008 transmission rider filing.

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On May 8, 2007, the Ohio Companies filed with the PUCO a notice of intent to file for an increase in electric distribution rates. The Ohio Companies filed the application and rate request with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the bill for most Ohio customers.  The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operating and maintenance expenses and recovery of regulatory assets created by deferrals that were approved in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million to the PUCO to establish the test period data that will be used as the basis for setting rates in that proceeding. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in early 2008. The PUCO order is expected to be issued in the second quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Comments by intervenors in the case were filed on September 5, 2007.  The PUCO Staff filed comments on September 21, 2007.  Parties filed reply comments on October 12, 2007. The Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process.

On September 25, 2007, the Ohio Governor’s proposed energy plan was officially introduced into the Ohio Senate. The bill proposes to revise state energy policy to address electric generation pricing after 2008, establish advanced energy portfolio standards and energy efficiency standards, and create GHG emissions reporting and carbon control planning requirements. The bill also proposes to move to a “hybrid” system for determining rates for PLR service in which electric utilities would provide regulated generation service unless they satisfy a statutory burden to demonstrate the existence of a competitive market for retail electricity. The Senate Energy & Public Utilities Committee has been conducting hearings on the bill and receiving testimony from interested parties, including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer groups, utility executives and others. Several proposed amendments to the bill have been submitted, including those from Ohio’s investor-owned electric utilities. A substitute version of the bill, which incorporated certain of the proposed amendments, was introduced into the Senate Energy & Public Utilities Committee on October 25, 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of the Ohio Companies.

Pennsylvania

Met-Ed and Penelec have been purchasing a portion of their PLR requirements from FES through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy requirements during the term of these agreements with FES.

On September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that were substantially higher than the fixed price in the partial requirements agreements.

Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.

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If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its 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.

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 also 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, when new transmission rates were effective, 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 in 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 expenses and the transmission deferral. 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). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part the MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the 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. On June 19, 2007, initial briefs were filed and responsive briefs were filed through September 21, 2007.  Reply briefs were filed on October 5, 2007. Oral arguments are expected to take place in late 2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the financial condition and results of operations of Met-Ed, Penelec and FirstEnergy.

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As of September 30, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $496 million and $58 million, respectively. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in February 2007 and briefing was completed on March 28, 2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.

On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service will be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. On September 28, 2007, Penn filed a Joint Petition for Settlement resolving all but one issue in the case.  Briefs were also filed on September 28, 2007 on the unresolved issue of incremental uncollectible accounts expense. The settlement is either supported, or not opposed, by all parties. The PPUC is expected to act on the settlement and the unresolved issue in late November or early December 2007 for the initial RFP to take place in January 2008.

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation programs to meet demand 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 an optional 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 final form of any legislation arising from the special legislative session is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

New Jersey

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2007, the accumulated deferred cost balance totaled approximately $330 million.

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

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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 PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that would 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. Comments on the alternative proposal were submitted on June 15, 2006. On November 3, 2006, the Staff circulated a revised draft proposal to interested stakeholders. Another revised draft was circulated by the NJBPU Staff on February 8, 2007.

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated with the issuance of a proposed set of objectives which, as to electricity, included the following:

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

·   Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date;

·   Reduce air pollution related to energy use;

·   Encourage and maintain economic growth and development;

·    Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020;

·   Maintain unit prices for electricity to no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia); and

·   Eliminate transmission congestion by 2020.

Comments on the objectives and participation in the development of the EMP have been solicited and a number of working groups have been formed to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing (1) energy efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing issues have completed their assigned tasks of data gathering and analysis and have provided reports to the EMP Committee. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected later in 2007. A final draft of the EMP is expected to be presented to the Governor in late 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of JCP&L.

On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards.  Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff.  On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments which were due on September 26, 2007.  At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such regulations may have on its operations or those of JCP&L.

FERC Matters

On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the fourth quarter of 2007.

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On January 31, 2005, certain PJM transmission owners made three 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. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, BG&E and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. Hearings were held and numerous parties appeared and litigated various issues; including AEP, which filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. At the conclusion of the hearings, the ALJ issued an initial decision adopting the FERC Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate. The ALJ recommended an April 1, 2006 effective date for this change in rate design. Numerous parties, including FirstEnergy, submitted briefs opposing the ALJ’s decision and recommendations.  On April 19, 2007, the FERC issued an order rejecting the ALJ’s findings and recommendations in nearly every respect. The FERC found that the PJM transmission owners’ existing “license plate” 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 socialized 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.  Nevertheless, 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.  Subsequently, FirstEnergy and other parties filed pleadings opposing the requests for rehearing. The FERC’s Orders on PJM rate design, if sustained on rehearing and appeal, will prevent the allocation of the cost 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 future transmission costs shifting to the JCP&L, Met-Ed and Penelec zones.

    New FERC Transmission Rate Design Filings

On August 1, 2007, a number of filings were made with the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.

FirstEnergy joined in a filing made by the MISO transmission owners that would maintain the existing “license plate” rates for transmission service within MISO provided over existing transmission facilities.  FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to continue the elimination of transmission rates associated with service over existing transmission facilities between MISO and PJM.  If adopted by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities.  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 be maintained (known as the RECB Process). Each of these filings was supported by the majority of transmission owners in either MISO or PJM, as applicable.

The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV and higher transmission facilities be spread throughout the entire MISO footprint.  Further, Indianapolis Power and Light Company separately moved the FERC to reopen the record to address the cost allocation for the RECB Process.  If either proposal is adopted by the FERC, it could shift a greater portion of the cost of new 345 kV and higher transmission facilities to the FirstEnergy footprint in MISO, and increase the transmission rates paid by load-serving FirstEnergy affiliates in MISO.

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “SuperRegion” that regionalizes the cost of new and existing transmission facilities operated at voltages of 345 kV and above.  Lower voltage facilities would continue to be recovered in the host utility transmission rate zone through a license plate rate.  AEP requests a refund effective October 1, 2007, or alternatively, February 1, 2008.  The effect of this proposal, if adopted by FERC, would be to shift significant costs to the FirstEnergy zones in MISO and PJM.  FirstEnergy believes that most of these costs would ultimately be recoverable in retail rates. On October 12, 2007, BG&E filed a motion to dismiss AEP’s complaint. On October 16, 2007, the Organization of MISO States filed comments urging the FERC to dismiss AEP’s complaint. Interventions and protests to AEP’s complaint and answers to BG&E’s motion to dismiss were due October 29, 2007. FirstEnergy and other transmission owners filed protests to AEP’s complaint and support for BG&E’s motion to dismiss. AEP has asked for consolidation of its complaint with the cases above, and FirstEnergy expects it to be resolved on the same timeline as those cases.

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Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC.  All or some of these proceedings may be consolidated by the FERC and set for hearing.  The outcome of these cases cannot be predicted.  Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates.  FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates.  Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.

    MISO Ancillary Services Market and Balancing Area Consolidation Filing

MISO made a filing on September 14, 2007 to establish Ancillary Services markets for regulation, spinning and supplemental reserves to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region.  An effective date of June 1, 2008 was requested in the filing.

MISO’s previous filing to establish an Ancillary Services market was rejected without prejudice by FERC on June 22, 2007, subject to MISO making certain modifications in its filing. FirstEnergy believes that MISO’s September 14 filing generally addresses the FERC’s directives.  FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas, but filed objections on specific aspects of the MISO proposal.  Interventions and protests to MISO’s filing were made with FERC on October 15, 2007.

    Order No. 890 on Open Access Transmission Tariffs

On February 16, 2007, the FERC issued a final rule (Order No. 890) that revises its decade-old open access transmission regulations and policies.  The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process.  The final rule became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffs to comply with the FERC’s order. MISO, PJM and ATSI submitted tariff filings to the FERC on October 11, 2007. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.

Environmental Matters

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

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006 alleging violations to various sections of the Clean Air Act. FirstEnergy has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.

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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. NO_X 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 NO_X reductions at FirstEnergy's facilities. The EPA's NO_X Transport Rule imposes uniform reductions of NO_X emissions (an approximate 85% reduction in utility plant NO_X 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 NO_X emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NO_X budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act, alleging violations of air pollution laws at the Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 16, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. FirstEnergy is currently studying PennFuture’s complaint.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. 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 allowed each affected state until 2006 to develop implementing regulations to achieve additional reductions of NO_X and SO₂ emissions in two phases (Phase I in 2009 for NO_X, 2010 for SO₂ and Phase II in 2015 for both NO_X and SO₂). FirstEnergy's Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO₂ and NO_X emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on NO_X emissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_X emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_X cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

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, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO₂ and NO_X emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FirstEnergy would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FirstEnergy will be disadvantaged if these model rules were implemented as proposed because FirstEnergy’s substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

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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. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. 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 Mansfield Plant, FirstEnergy’s only coal-fired Pennsylvania power plant, until 2015, if at all.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn, and is now owned by FGCO. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as the New Source Review, or NSR, cases.

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NO_X and SO₂ emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreement are currently estimated to be $1.7 billion for 2007 through 2011 ($400 million of which is expected to be spent during 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009).

The Sammis NSR Litigation consent decree also requires FirstEnergy to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.

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 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. At the international level, efforts have begun to develop climate change agreements for post-2012 GHG reductions. 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.

At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States.  State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO₂ emissions from automobiles as “air pollutants” under the Clean Air Act. Although this decision did not address CO₂ emissions from electric generating plants, the EPA has similar authority under the Clean Air Act to regulate “air pollutants” from those and other facilities. Also 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, the EPA proposed to change the NSR regulations, on May 8, 2007, to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.

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

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Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. On January 26, 2007, the federal Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to EPA for further rulemaking and eliminated the restoration option from 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 (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. FirstEnergy is evaluating various control options and their costs and effectiveness. Depending on the outcome of such studies, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future cost of compliance with these standards may require material capital expenditures.

Regulation of Hazardous Waste

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

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.  As of September 30, 2007, FirstEnergy had approximately $1.5 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry.  As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans to seek for these facilities.

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are 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, 2007, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $89 million have been accrued through September 30, 2007.

Other Legal Proceedings

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

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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.  FirstEnergy is defending this class action but is unable to predict the outcome of this matter.  No liability has been accrued as of September 30, 2007.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. – Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

78

FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Two other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and AEP, as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. The four cases remaining were consolidated for hearing by the PUCO in an order dated March 7, 2006.  In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on January 8, 2008.

FirstEnergy is defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although FirstEnergy is unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Nuclear Plant Matters

On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information 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 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 Demand for Information reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. The NRC held a public meeting on June 27, 2007 with FENOC to discuss FENOC’s response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC’s compliance with these commitments is subject to future NRC review.

Other Legal Matters

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

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

79

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. The arbitration panel provided additional rulings regarding damages during a September 2007 hearing and it is anticipated that he will issue a final order in late 2007. JCP&L intends to re-file an appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 157 – “Fair Value Measurements”

In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

SFAS 159 – “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”

In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value.  This Statement requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings.  The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet.  This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157 and SFAS 107. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

EITF 06-11 – “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”

In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R).  The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to APIC. This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement.  The consensus is effective for income tax benefits of dividends declared during fiscal years beginning after December 15, 2007.  EITF 06-11 is not expected to have a material effect on FirstEnergy’s financial statements.

FSP FIN 39-1 – “Amendment of FASB Interpretation No. 39”

In April 2007, the FASB issued Staff Position (FSP) FIN 39-1, which permits an entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement as the derivative instruments.  This FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. The effects of applying the guidance in this FSP should be recognized as a retrospective change in accounting principle for all financial statements presented. FirstEnergy is currently evaluating the impact of this FSP on its financial statements but it is not expected to have a material impact.

80

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(In thousands)
REVENUES:
Electric sales to affiliates	$	805,372		$	762,106		$	2,209,743		$	1,997,096
Other		365,536			347,474			1,048,189			1,063,026
Total revenues		1,170,908			1,109,580			3,257,932			3,060,122
EXPENSES:
Fuel		301,786			315,521			804,201			844,913
Purchased power from non-affiliates		228,755			173,620			577,831			477,249
Purchased power from affiliates		62,508			55,647			209,576			188,698
Other operating expenses		235,033			198,716			731,774			774,767
Provision for depreciation		48,500			46,894			145,030			135,414
General taxes		22,242			17,609			64,870			55,550
Total expenses		898,824			808,007			2,533,282			2,476,591
OPERATING INCOME		272,084			301,573			724,650			583,531
OTHER INCOME (EXPENSE):
Miscellaneous income		12,655			27,662			47,756			44,843
Interest expense to affiliates		(9,641	)		(41,416	)		(61,904	)		(122,664	)
Interest expense - other		(31,794	)		(7,914	)		(70,845	)		(17,880	)
Capitalized interest		5,131			2,389			12,763			8,698
Total other expense		(23,649	)		(19,279	)		(72,230	)		(87,003	)
INCOME BEFORE INCOME TAXES		248,435			282,294			652,420			496,528
INCOME TAXES		93,671			106,175			243,736			184,572
NET INCOME		154,764			176,119			408,684			311,956
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(1,360	)		-			(4,080	)		-
Unrealized gain (loss) on derivative hedges		4,863			(6,257	)		9,451			(6,376	)
Change in unrealized gain on available for sale securities		21,263			20,945			80,053			29,266
Other comprehensive income		24,766			14,688			85,424			22,890
Income tax expense related to other
comprehensive income		8,915			5,453			30,474			8,548
Other comprehensive income, net of tax		15,851			9,235			54,950			14,342
TOTAL COMPREHENSIVE INCOME	$	170,615		$	185,354		$	463,634		$	326,298
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part of
these statements.

81

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,		December 31,
	2007		2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	2
Receivables-
Customers (less accumulated provisions of $8,007,000 and $7,938,000,
respectively, for uncollectible accounts)		144,443		129,843
Associated companies		285,462		235,532
Other (less accumulated provisions of $9,000 and $5,593,000,
respectively, for uncollectible accounts)		5,416		4,085
Notes receivable from associated companies		242,612		752,919
Materials and supplies, at average cost		441,066		460,239
Prepayments and other		83,825		57,546
		1,202,826		1,640,166
PROPERTY, PLANT AND EQUIPMENT:
In service		8,183,578		8,355,344
Less - Accumulated provision for depreciation		3,852,896		3,818,268
		4,330,682		4,537,076
Construction work in progress		596,879		339,886
		4,927,561		4,876,962
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		1,342,083		1,238,272
Long-term notes receivable from associated companies		62,900		62,900
Other		39,964		72,509
		1,444,947		1,373,681
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		240,182		-
Goodwill		24,248		24,248
Property taxes		44,111		44,111
Pension assets		9,449		-
Other		70,638		39,839
		388,628		108,198
	$	7,963,962	$	7,999,007
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,469,721	$	1,469,660
Short-term borrowings-
Associated companies		237,070		1,022,197
Accounts payable-
Associated companies		432,695		556,049
Other		177,820		136,631
Accrued taxes		537,060		113,231
Other		163,239		100,941
		3,017,605		3,398,709
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 750 shares-
7 and 8 shares outstanding, respectively		1,163,934		1,050,302
Accumulated other comprehensive income		166,673		111,723
Retained earnings		1,038,412		697,338
Total common stockholder's equity		2,369,019		1,859,363
Long-term debt		505,196		1,614,222
		2,874,215		3,473,585
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		1,068,769		-
Accumulated deferred income taxes		-		121,449
Accumulated deferred investment tax credits		62,275		65,751
Asset retirement obligation		797,357		760,228
Retirement benefits		53,505		103,027
Property taxes		44,433		44,433
Other		45,803		31,825
		2,072,142		1,126,713
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	7,963,962	$	7,999,007
The preceding Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral part of these
balance sheets.

82

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	September 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	408,684		$	311,956
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		145,030			135,414
Nuclear fuel and lease amortization		75,102			66,360
Deferred income taxes and investment tax credits, net		(381,042	)		47,188
Investment impairment		14,296			-
Accrued compensation and retirement benefits		3,414			13,704
Commodity derivative transactions, net		4,913			46,500
Gain on asset sales		(12,105	)		(35,973	)
Cash collateral, net		(19,798	)		20,643
Pension trust contribution		(64,020	)		-
Decrease (increase) in operating assets:
Receivables		(30,172	)		(46,063	)
Materials and supplies		48,123			(1,683	)
Prepayments and other current assets		(5,118	)		211
Increase (decrease) in operating liabilities:
Accounts payable		(108,949	)		(162,502	)
Accrued taxes		424,100			77,524
Accrued interest		14,355			2,431
Other		(36,498	)		(17,605	)
Net cash provided from operating activities		480,315			458,105
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			251,945
Equity contributions from parent		710,468			-
Short-term borrowings, net		-			66,817
Redemptions and Repayments-
Common stock		(600,000	)		-
Long-term debt		(1,110,174	)		(253,240	)
Short-term borrowings, net		(785,127	)		-
Common stock dividend payments		(67,000	)		-
Net cash provided from (used for) financing activities		(1,851,833	)		65,522
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(482,907	)		(427,298	)
Proceeds from asset sales		12,990			20,437
Proceeds from sale and leaseback transaction		1,328,919			-
Sales of investment securities held in trusts		521,535			886,863
Purchases of investment securities held in trusts		(521,535	)		(886,863	)
Loan repayments from (loans to) associated companies, net		510,307			(88,292	)
Other		2,209			(28,474	)
Net cash provided from (used for) investing activities		1,371,518			(523,627	)
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 preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an
integral part of these statements.

83

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, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  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, 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, 2006, 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 (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006 as discussed in Note 3 to those consolidated financial statements) dated April 11, 2007,except as to Note 12, which is as of August 6, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

October 31, 2007

84

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 requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and TE to supply each of their PLR 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 PLR 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 the majority of the PLR requirements of Penn at market-based rates as a result of a competitive solicitation conducted by Penn. FES’ existing contractual obligations to Penn expire on May 31, 2008, but could continue if FES successfully bids in future competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, Maryland and Michigan.

Results of Operations

In the first nine months of 2007, net income increased to $409 million from $312 million in the first nine months of 2006. The increase in net income was primarily due to higher revenues and lower fuel and other operating expenses, partially offset by higher purchased power costs.

Revenues

Revenues increased by $198million in the first nine months of 2007 compared to the same period in 2006 due to increases in revenues from non-affiliated retail generation sales and affiliated wholesale sales, partially offset by lower non-affiliated wholesale sales. Retail generation sales revenues increased as a result of higher unit prices and increased KWH sales. Higher unit prices primarily reflected higher generation rates in the MISO and PJM markets where FES is an alternative supplier. Increased KWH sales to FES’ commercial and industrial customers during the first nine months of 2007 were partially offset by a decrease in sales to residential customers returning to FES’ Ohio utility affiliates for their generation requirements. Affiliated wholesale revenues were higher as a result of increased sales and higher unit prices for sales to the Ohio Companies.

Non-affiliated wholesale revenues decreased as a result of lower generation available for the non-affiliated market due to increased affiliated company power sales requirements under the Ohio Companies’ full-requirements PSA and the partial-requirements power sales agreement with Met-Ed and Penelec.

The increase in sales to the Ohio Companies was due to their higher retail generation sales requirements. Higher unit prices resulted from the provision of the full-requirements PSA under which PSA rates reflect the increase in the Ohio Companies’ retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn as a result of the implementation of its competitive solicitation process in 2007.

Transmission revenue decreased $25 million due to reduced retail load in the MISO market, lower transmission rates and reduced financial transmission rights auction revenue.

Changes in revenues in the first nine months of 2007 from the same period of 2006 are summarized below:

85

	Nine  Months Ended
	Sept 30,				Increase
Revenues by Type of Service	2007		2006		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	547	$	445	$	102
Wholesale		425		509		(84	)
Total Non-Affiliated Generation Sales		972		954		18
Affiliated Generation Sales		2,210		1,997		213
Transmission		71		96		(25	)
Other		5		13		(8	)
Total Revenues	$	3,258	$	3,060	$	198

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated sales in the first nine months of 2007 compared to the same period last year:

	Increase
Source of Change in Non-Affiliated Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 12% increase in sales volumes	$	52
Change in prices		50
		102
Wholesale:
Effect of 26% decrease in sales volumes		(131	)
Change in prices		47
		(84	)
Net Increase in Non-Affiliated Generation Revenues	$	18

Source of Change in Affiliated Generation Revenues	Increase
	(In millions)
Ohio Companies:
Effect of 4% increase in sales volumes	$	56
Change in prices		89
		145
Pennsylvania Companies:
Effect of 12% increase in sales volumes		54
Change in prices		14
		68
Net Increase in Affiliated Generation Revenues	$	213

Expenses

Total expenses increased by $57 million in the first nine months of 2007 compared with the same period of 2006. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first nine months of 2007 from the same period last year:

Source of Change in Fuel and Purchased Power	Increase  (Decrease)
	(In millions)
Nuclear Fuel:
Change due to increased unit costs	$	3
Change due to volume consumed		5
		8
Fossil Fuel:
Change due to decreased unit costs		(4	)
Change due to volume consumed		(45	)
		(49	)
Purchased Power:
Change due to increased unit costs		51
Change due to volume purchased		71
		122
Net Increase in Fuel and Purchased Power Costs	$	81

86

Fossil fuel costs decreased $49 million in the first nine months of 2007 primarily as a result of reduced coal and emission allowance costs. Coal costs were lower due to a $14 million inventory adjustment as a result of an interim physical inventory and $23 million from reduced coal consumption reflecting lower generation as a result of planned maintenance outages at Sammis Units 6 and 7 and Eastlake Unit 5 and forced outage at Mansfield Unit 1.

The lower fossil fuel costs were partially offset by higher nuclear fuel costs of $8 million. Higher nuclear fuel costs were due to higher unit costs and increased nuclear generation in the first nine months of 2007 as compared to the same period of 2006.

Purchased power costs increased as a result of increased volumes purchased and higher unit prices. Volumes purchased in the first nine months of 2007 increased by 10.6% due to the outages at the Sammis, Eastlake, Mansfield and Perry plants.  Other operating expenses decreased by $43 million in the first nine months of 2007 from the same period of 2006 primarily due to lower nuclear operating costs as a result of fewer outages in 2007 compared to 2006 and reduced employee benefit costs.

Depreciation expense increased by $10 million in the first nine months of 2007 primarily due to fossil and nuclear property additions subsequent to the third quarter of 2006.

General taxes increased by $9 million in the first nine months of 2007 compared to the same period of 2006 as a result of higher property taxes and gross receipts taxes.

Other Expense

Other expense decreased by $15 million in the first nine months of 2007 from the same periods of 2006 primarily as a result of lower interest expense. Lower interest expense reflected the repayment of GAT-related notes to associated companies, partially offset by the issuance of lower-cost pollution control debt subsequent to October 1, 2006.

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.

87

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
STATEMENTS OF INCOME	(In thousands)
REVENUES:
Electric sales	$	638,336		$	642,294		$	1,802,110		$	1,745,699
Excise tax collections		30,472			31,379			89,077			87,269
Total revenues		668,808			673,673			1,891,187			1,832,968
EXPENSES:
Fuel		2,821			2,954			8,148			8,726
Purchased power		364,709			395,560			1,037,200			971,613
Nuclear operating costs		41,783			44,995			130,951			129,585
Other operating costs		100,265			108,362			285,871			290,776
Provision for depreciation		19,482			18,399			57,440			53,962
Amortization of regulatory assets		53,026			49,717			144,569			147,022
Deferral of new regulatory assets		(41,417	)		(44,962	)		(132,410	)		(123,285	)
General taxes		46,158			47,826			141,296			137,652
Total expenses		586,827			622,851			1,673,065			1,616,051
OPERATING INCOME		81,981			50,822			218,122			216,917
OTHER INCOME (EXPENSE):
Investment income		19,827			32,993			67,803			98,853
Miscellaneous income		670			1,639			3,362			835
Interest expense		(20,311	)		(24,597	)		(62,749	)		(60,195	)
Capitalized interest		136			698			398			1,832
Subsidiary's preferred stock dividend requirements		-			(156	)		-			(467	)
Total other income		322			10,577			8,814			40,858
INCOME BEFORE INCOME TAXES		82,303			61,399			226,936			257,775
INCOME TAXES		34,089			17,902			79,074			91,239
NET INCOME		48,214			43,497			147,862			166,536
PREFERRED STOCK DIVIDEND REQUIREMENTS AND
REDEMPTION PREMIUM		-			51			-			4,297
EARNINGS ON COMMON STOCK	$	48,214		$	43,446		$	147,862		$	162,239
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	48,214		$	43,497		$	147,862		$	166,536
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirment benefits		(3,423	)		-			(10,270	)		-
Change in unrealized gain on available for sale securities		2,442			3,795			7,415			5,467
Other comprehensive income (loss)		(981	)		3,795			(2,855	)		5,467
Income tax expense (benefit) related to other
comprehensive income		(573	)		1,369			(1,688	)		1,972
Other comprehensive income (loss), net of tax		(408	)		2,426			(1,167	)		3,495
TOTAL COMPREHENSIVE INCOME	$	47,806		$	45,923		$	146,695		$	170,031
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
statements.

88

OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,		December 31,
	2007		2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	727	$	712
Receivables-
Customers (less accumulated provisions of $8,518,000 and $15,033,000,
respectively, for uncollectible accounts)		271,680		234,781
Associated companies		167,686		141,084
Other (less accumulated provisions of $5,548,000 and $1,985,000,
respectively, for uncollectible accounts)		20,093		13,496
Notes receivable from associated companies		626,841		458,647
Prepayments and other		17,148		13,606
		1,104,175		862,326
UTILITY PLANT:
In service		2,722,468		2,632,207
Less - Accumulated provision for depreciation		1,053,942		1,021,918
		1,668,526		1,610,289
Construction work in progress		42,494		42,016
		1,711,020		1,652,305
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		365,767		1,219,325
Investment in lease obligation bonds		274,077		291,393
Nuclear plant decommissioning trusts		128,168		118,209
Other		36,756		38,160
		804,768		1,667,087
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		717,311		741,564
Pension assets		106,682		68,420
Property taxes		60,080		60,080
Unamortized sale and leaseback costs		46,384		50,136
Other		44,457		18,696
		974,914		938,896
	$	4,594,877	$	5,120,614
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	442,264	$	159,852
Short-term borrowings-
Associated companies		-		113,987
Other		52,609		3,097
Accounts payable-
Associated companies		200,104		115,252
Other		17,766		13,068
Accrued taxes		141,516		187,306
Accrued interest		17,435		24,712
Other		101,543		64,519
		973,237		681,793
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 and 80 shares outstanding, respectively		1,220,173		1,708,441
Accumulated other comprehensive income		2,041		3,208
Retained earnings		257,870		260,736
Total common stockholder's equity		1,480,084		1,972,385
Long-term debt and other long-term obligations		836,430		1,118,576
		2,316,514		3,090,961
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		676,784		674,288
Accumulated deferred investment tax credits		17,856		20,532
Asset retirement obligations		92,157		88,223
Retirement benefits		159,096		167,379
Deferred revenues - electric service programs		59,255		86,710
Other		299,978		310,728
		1,305,126		1,347,860
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	4,594,877	$	5,120,614
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of
these balance sheets.

89

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	September 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	147,862		$	166,536
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		57,440			53,962
Amortization of regulatory assets		144,569			147,022
Deferral of new regulatory assets		(132,410	)		(123,285	)
Amortization of lease costs		28,567			28,600
Deferred income taxes and investment tax credits, net		(29,155	)		(27,850	)
Accrued compensation and retirement benefits		(34,572	)		2,985
Pension trust contribution		(20,261	)		-
Decrease (increase) in operating assets-
Receivables		(70,098	)		26,198
Prepayments and other current assets		(3,542	)		(4,172	)
Increase (decrease) in operating liabilities-
Accounts payable		89,550			(24,937	)
Accrued taxes		(37,355	)		(27,826	)
Accrued interest		(7,277	)		12,839
Electric service prepayment programs		(27,455	)		(24,975	)
Other		7,260			2,570
Net cash provided from operating activities		113,123			207,667
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			592,763
Equity contributions from parent		11,621			-
Redemptions and Repayments-
Common stock		(500,000	)		(500,000	)
Preferred stock		-			(63,893	)
Long-term debt		(1,190	)		(138,085	)
Short-term borrowings, net		(64,475	)		(177,595	)
Dividend Payments-
Common stock		(150,000	)		(73,000	)
Preferred stock		-			(1,369	)
Net cash used for financing activities		(704,044	)		(361,179	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(109,461	)		(94,278	)
Sales of investment securities held in trusts		31,624			32,826
Purchases of investment securities held in trusts		(33,586	)		(34,209	)
Loan repayments from associated companies, net		685,364			148,199
Cash investments		17,316			93,900
Other		(321	)		6,848
Net cash provided from investing activities		590,936			153,286
Net increase (decrease) in cash and cash equivalents		15			(226	)
Cash and cash equivalents at beginning of period		712			929
Cash and cash equivalents at end of period	$	727		$	703
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral
part of these statements.

90

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, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006,  and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 3, Note 2(G) and Note 11 to the consolidated financial statements) dated February 27, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

October 31, 2007

91

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. OE also provides generation services to those customers electing to retain OE as their power supplier. OE’s power supply requirements are provided by FES – an affiliated company.

Results of Operations

In the first nine months of 2007, earnings on common stock decreased to $148 million from $162 million in the same period of 2006. The decrease in earnings primarily resulted from higher purchased power costs and lower other income, partially offset by higher electric sales revenues.

Revenues

Revenues increased by $58 million or 3.2% in the first nine months of 2007 compared with the same period in 2006, primarily due to a $65 million increase in retail generation revenues, partially offset by decreases in revenues from distribution throughput of $16 million.

Higher retail generation revenues from residential customers reflected increased sales volume and the impact of higher average unit prices. Weather conditions in the  first nine months of 2007 compared to the same period in 2006 contributed to the higher KWH sales to residential customers (heating degree days increased 11.5% and 8.4% and cooling degree days increased by 26.9% and 25.2% in OE’s and Penn’s service territories, respectively). Commercial retail generation revenues increased primarily due to higher average unit prices, partially offset by reduced KWH sales. Average prices increased due to the higher generation prices that were effective in January 2007 under Penn’s competitive RFP process. Retail generation revenues from the industrial sector decreased primarily due to an increase in customer shopping in Penn’s service territory in the first nine months of 2007 as compared to the same period in 2006. The percentage of shopping customers increased to 27.7 percent in the first nine months of 2007 from 15.8 percent in the first nine months of 2006.

Changes in retail generation sales and revenues in the first nine months of 2007 from the corresponding period of 2006 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)
Residential		7.4	%
Commercial		(1.4	)%
Industrial		(16.0	)%
Net Decrease in Generation Sales		(3.7	)%

Retail Generation Revenues	Increase (Decrease)
	(In millions)
Residential	$	80
Commercial		23
Industrial		(38	)
Net Increase in Generation Revenues	$	65

A small increase in distribution revenues from residential customers was more than offset by decreases in distribution revenues from commercial and industrial customers. The increase from residential customers reflected higher deliveries due to the favorable weather conditions described above in the first nine months of 2007 as compared to the same period in 2006, partially offset by lower composite unit prices. Reduced distribution revenues from commercial customers in the first nine months of 2007 resulted from lower unit prices, partially offset by increased KWH deliveries. Distribution revenues from industrial customers decreased in the first nine months of 2007 as a result of lower unit prices and reduced KWH deliveries.

92

Changes in distribution KWH deliveries and revenues in the first nine months of 2007 from the corresponding period of 2006 are summarized in the following tables.

Distribution KWH Deliveries	Increase (Decrease)
Residential		5.8	%
Commercial		3.3	%
Industrial		(2.2	)%
Net Increase in Distribution Deliveries		2.2	%

Distribution Revenues	Increase (Decrease)
	(In millions)
Residential	$	2
Commercial		(5	)
Industrial		(13	)
Net Decrease in Distribution Revenues	$	(16	)

Expenses

Total expenses increased by $57 million in the first nine months of 2007 from the same period of 2006. The following table presents changes from the prior year by expense category.

Expenses – Changes	Increase (Decrease)
		(In millions)
Purchased power costs	$	65
Nuclear operating costs		1
Other operating costs		(5	)
Provision for depreciation		3
Amortization of regulatory assets		(2	)
Deferral of new regulatory assets		(9	)
General taxes		4
Net Increase in Expenses	$	57

Higher purchased power costs in the first nine months of 2007 primarily reflected higher unit prices under Penn’s competitive RFP process and OE’s PSA with FES. The decrease in other operating costs for the first nine months of 2007 was primarily due to lower employee benefit expenses, partially offset by higher transmission expenses related to MISO operations. Higher depreciation expense in the first nine months of 2007 reflected capital additions subsequent to the third quarter of 2006. The increase in the deferral of new regulatory assets for the first nine months of 2007 was primarily due to increases in MISO cost deferrals and RCP distribution cost deferrals, partially offset by lower RCP fuel cost deferrals. General taxes were higher in the first nine months of 2007 as compared to the same period last year as a result of higher real and personal property taxes and KWH excise taxes.

Other Income

Other income decreased $32 million in the first nine months of 2007 as compared with the same period of 2006 primarily due to reductions in interest income on notes receivable resulting from principal payments from associated companies since the third quarter of 2006. Higher interest expense also contributed to the decrease in other income in the first nine months of 2007, with interest expense associated with OE’s issuance of $600 million of long-term debt in June 2006 being partially offset by debt redemptions since the third quarter of 2006.

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.

93

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(In thousands)
REVENUES:
Electric sales	$	510,577		$	497,336		$	1,366,396		$	1,304,525
Excise tax collections		18,514			18,587			53,009			51,579
Total revenues		529,091			515,923			1,419,405			1,356,104
EXPENSES:
Fuel		12,160			12,748			39,683			39,724
Purchased power		216,194			229,779			575,520			531,490
Other operating costs		85,114			81,510			243,140			222,841
Provision for depreciation		18,913			17,524			56,094			45,775
Amortization of regulatory assets		42,077			38,826			110,253			99,832
Deferral of new regulatory assets		(37,692	)		(39,060	)		(114,708	)		(101,283	)
General taxes		37,930			34,228			110,922			100,808
Total expenses		374,696			375,555			1,020,904			939,187
OPERATING INCOME		154,395			140,368			398,501			416,917
OTHER INCOME (EXPENSE):
Investment income		13,805			24,715			47,816			76,325
Miscellaneous income (expense)		(760	)		813			3,197			6,209
Interest expense		(34,423	)		(34,774	)		(107,430	)		(104,140	)
Capitalized interest		309			836			655			2,346
Total other expense		(21,069	)		(8,410	)		(55,762	)		(19,260	)
INCOME BEFORE INCOME TAXES		133,326			131,958			342,739			397,657
INCOME TAXES		54,610			48,496			131,525			150,730
NET INCOME		78,716			83,462			211,214			246,927
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		1,202			-			3,607			-
Income tax expense related to other comprehensive income		356			-			1,068			-
Other comprehensive income, net of tax		846			-			2,539			-
TOTAL COMPREHENSIVE INCOME	$	79,562		$	83,462		$	213,753		$	246,927
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral
part of these statements.

94

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2007			2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	234		$	221
Receivables-
Customers (less accumulated provisions of $8,057,000 and $6,783,000
respectively, for uncollectible accounts)		304,608			245,193
Associated companies		53,564			249,735
Other		21,331			14,240
Notes receivable from associated companies		41,054			27,191
Prepayments and other		1,510			2,314
		422,301			538,894
UTILITY PLANT:
In service		2,199,913			2,136,766
Less - Accumulated provision for depreciation		844,600			819,633
		1,355,313			1,317,133
Construction work in progress		55,382			46,385
		1,410,695			1,363,518
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		265,660			486,634
Investment in lessor notes		463,433			519,611
Other		10,302			13,426
		739,395			1,019,671
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,688,521			1,688,521
Regulatory assets		855,618			854,588
Pension assets		16,791			-
Property taxes		65,000			65,000
Other		42,993			33,306
		2,668,923			2,641,415
	$	5,241,314		$	5,563,498
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	266,271		$	120,569
Short-term borrowings-
Associated companies		73,459			218,134
Other		100,000			-
Accounts payable-
Associated companies		237,072			365,678
Other		6,194			7,194
Accrued taxes		132,941			128,829
Accrued interest		41,393			19,033
Lease market valuation liability		58,750			60,200
Other		44,931			52,101
		961,011			971,738
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding		873,037			860,133
Accumulated other comprehensive loss		(101,892	)		(104,431	)
Retained earnings		620,155			713,201
Total common stockholder's equity		1,391,300			1,468,903
Long-term debt and other long-term obligations		1,670,898			1,805,871
		3,062,198			3,274,774
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		461,410			470,707
Accumulated deferred investment tax credits		18,994			20,277
Lease market valuation liability		491,085			547,800
Retirement benefits		110,620			122,862
Deferred revenues - electric service programs		34,768			51,588
Other		101,228			103,752
		1,218,105			1,316,986
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	5,241,314		$	5,563,498
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these balance sheets.

95

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	September 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	211,214		$	246,927
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		56,094			45,775
Amortization of regulatory assets		110,253			99,832
Deferral of new regulatory assets		(114,708	)		(101,283	)
Deferred rents and lease market valuation liability		(46,327	)		(55,166	)
Deferred income taxes and investment tax credits, net		(40,964	)		(9,513	)
Accrued compensation and retirement benefits		2,575			2,681
Pension trust contribution		(24,800	)		-
Decrease (increase) in operating assets-
Receivables		140,359			189
Prepayments and other current assets		661			(387	)
Increase (decrease) in operating liabilities-
Accounts payable		(143,210	)		29,681
Accrued taxes		4,545			(14,588	)
Accrued interest		22,360			12,427
Electric service prepayment programs		(16,819	)		(13,623	)
Other		2,996			(5,270	)
Net cash provided from operating activities		164,229			237,682
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		247,424			-
Equity contributions from parent		12,756			-
Redemptions and Repayments-
Long-term debt		(223,555	)		(118,295	)
Short-term borrowings, net		(59,328	)		(58,819	)
Dividend Payments-
Common stock		(304,000	)		(118,000	)
Net cash used for financing activities		(326,703	)		(295,114	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(100,583	)		(89,771	)
Loan repayments from (loans to) associated companies, net		(13,863	)		108,034
Collection of principal on long-term notes receivable		220,974			-
Redemption of lessor notes		56,177			44,553
Other		(218	)		(5,368	)
Net cash provided from investing activities		162,487			57,448
Net increase in cash and cash equivalents		13			16
Cash and cash equivalents at beginning of period		221			207
Cash and cash equivalents at end of period	$	234		$	223
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.

96

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, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  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, 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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 11 to those consolidated financial statements) dated February 27, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

October 31, 2007

97

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 2007 decreased to $211 million from $247 million in the same period of 2006. The decrease resulted primarily from higher purchased power costs and other operating costs, partially offset by higher revenues.

Revenues

Revenues increased by $63 million or 5% in the first nine months of 2007 compared to the same period of 2006 primarily due to higher retail generation and wholesale revenues.  Retail generation revenues increased by $38 million due to increased KWH sales and higher composite unit prices for all customer classes.  More weather-related usage in the first nine months of 2007 compared to the same period of 2006 primarily contributed to the increased KWH sales in the residential and commercial sectors (cooling degree days increased 19% and heating degree days increased 15% from the same period in 2006).  Increased KWH sales in the industrial sector reflected a slight decrease in customer shopping.

Wholesale generation revenues increased by $17 million in the first nine months of 2007 compared to the corresponding period of 2006.  The increase was primarily due to higher unit prices for PSA sales. CEI sells power from its leasehold interests in the Bruce Mansfield plant to FGCO.

Increases in retail generation sales and revenues in the first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables:

Retail Generation KWH Sales	Increase
Residential		4.3	%
Commercial		6.0	%
Industrial		1.2	%
Increase in Retail Generation Sales		3.2	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	9
Commercial		15
Industrial		14
Increase in Generation Revenues	$	38

Revenues from distribution throughput increased by $5 million in the first nine months of 2007 compared to the same period of 2006 primarily due to increased KWH deliveries to all customer classes, partially offset by lower composite unit prices for the industrial sector. Increased KWH deliveries were primarily a result of the weather in 2007 as described above.

Changes in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables.

Distribution KWH Deliveries	Increase
Residential		4.5	%
Commercial		3.7	%
Industrial		0.7	%
Increase in Distribution Deliveries		2.5	%

98

Distribution Revenues	Increase (Decrease)
	(In millions)
Residential	$	6
Commercial		6
Industrial		(7	)
Net Increase in Distribution Revenues	$	5

Expenses

Total expenses increased by $82 million in the first nine months of 2007 compared to the same period of 2006. The following table presents the change from the prior year by expense category:

Expenses  - Changes	Increase (Decrease)
	(in millions)
Purchased power costs	$	44
Other operating costs		20
Provision for depreciation		10
Amortization of regulatory assets		11
Deferral of new regulatory assets		(13	)
General taxes		10
Net Increase in Expenses	$	82

Higher purchased power costs in the first nine months of 2007 compared to the corresponding period of 2006 primarily reflect higher unit prices associated with the PSA with FES and an increase in purchased power to meet CEI’s higher retail generation sales requirements. Higher other operating costs in the first nine months of 2007 compared to the same period of 2006 reflect increases in MISO transmission related expenses due to increased transmission volumes. The increased depreciation in the first nine months of 2007 is primarily due to property additions since the third quarter of 2006 and the absence of a credit adjustment in the second quarter of 2006 that related to prior periods ($6.5 million pre-tax, $4 million net of tax).

The increased amortization of regulatory assets in the first nine months of 2007 compared to the corresponding period of 2006 was due to increased transition cost amortization reflecting the higher KWH sales discussed above.  The increase in the deferral of new regulatory assets in the first nine months of 2007 reflect a higher level of MISO costs that were deferred in excess of transmission revenues recognized and increased distribution cost deferrals under CEI’s RCP. General taxes were higher in the first nine months of 2007 compared to the same period of 2006 primarily as a result of higher real and personal property taxes.

Other Expense

Other expense increased by $37 million in the first nine months of 2007 compared to the corresponding period of 2006 primarily due to lower investment income on associated company notes receivable in 2007. CEI received principal repayments from FGCO and NGC subsequent to the third quarter of 2006 on notes receivable related to the generation asset transfers.

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.

99

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
STATEMENTS OF INCOME	(In thousands)
REVENUES:
Electric sales	$	261,736		$	254,979		$	728,429		$	684,992
Excise tax collections		7,926			7,858			22,026			21,420
Total revenues		269,662			262,837			750,455			706,412
EXPENSES:
Fuel		8,784			9,399			29,392			28,799
Purchased power		112,502			112,389			304,947			268,468
Nuclear operating costs		17,705			19,252			53,272			54,450
Other operating costs		47,212			44,253			136,297			124,396
Provision for depreciation		9,231			8,386			27,475			24,723
Amortization of regulatory assets		30,460			27,336			79,284			73,909
Deferral of new regulatory assets		(15,645	)		(15,340	)		(47,373	)		(43,186	)
General taxes		11,912			13,406			38,646			38,590
Total expenses		222,161			219,081			621,940			570,149
OPERATING INCOME		47,501			43,756			128,515			136,263
OTHER INCOME (EXPENSE):
Investment income		6,721			9,724			21,255			28,449
Miscellaneous expense		(2,153	)		(1,933	)		(7,309	)		(6,543	)
Interest expense		(8,786	)		(4,940	)		(25,205	)		(13,614	)
Capitalized interest		220			277			467			835
Total other income (expense)		(3,998	)		3,128			(10,792	)		9,127
INCOME BEFORE INCOME TAXES		43,503			46,884			117,723			145,390
INCOME TAXES		18,435			17,706			44,924			54,834
NET INCOME		25,068			29,178			72,799			90,556
PREFERRED STOCK DIVIDEND REQUIREMENTS		-			1,161			-			3,597
EARNINGS ON COMMON STOCK	$	25,068		$	28,017		$	72,799		$	86,959
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	25,068		$	29,178		$	72,799		$	90,556
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		574			-			1,720			-
Change in unrealized gain on available for sale securities		1,946			1,379			1,656			432
Other comprehensive income		2,520			1,379			3,376			432
Income tax expense related to other
comprehensive income		902			498			1,193			156
Other comprehensive income, net of tax		1,618			881			2,183			276
TOTAL COMPREHENSIVE INCOME	$	26,686		$	30,059		$	74,982		$	90,832
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of
these statements.

100

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2007			2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	20		$	22
Receivables-
Customers		335			772
Associated companies		31,180			13,940
Other (less accumulated provisions of $518,000 and $430,000,
respectively, for uncollectible accounts)		3,600			3,831
Notes receivable from associated companies		79,188			100,545
Prepayments and other		627			851
		114,950			119,961
UTILITY PLANT:
In service		913,191			894,888
Less - Accumulated provision for depreciation		406,949			394,225
		506,242			500,663
Construction work in progress		26,665			16,479
		532,907			517,142
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		154,674			169,493
Long-term notes receivable from associated companies		92,700			128,858
Nuclear plant decommissioning trusts		64,598			61,094
Other		1,778			1,871
		313,750			361,316
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		500,576			500,576
Regulatory assets		214,896			247,595
Pension assets		5,962			-
Property taxes		22,010			22,010
Other		29,427			30,042
		772,871			800,223
	$	1,734,478		$	1,798,642
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	55,134		$	30,000
Accounts payable-
Associated companies		103,250			84,884
Other		4,043			4,021
Notes payable to associated companies		190,758			153,567
Accrued taxes		52,865			47,318
Lease market valuation liability		23,655			24,600
Other		32,906			37,551
		462,611			381,941
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		172,949			166,786
Accumulated other comprehensive loss		(34,621	)		(36,804	)
Retained earnings		157,139			204,423
Total common stockholder's equity		442,477			481,415
Long-term debt		303,220			358,281
		745,697			839,696
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		141,813			161,024
Accumulated deferred investment tax credits		10,389			11,014
Lease market valuation liability		192,774			218,800
Retirement benefits		77,275			77,843
Asset retirement obligations		27,899			26,543
Deferred revenues - electric service programs		15,896			23,546
Other		60,124			58,235
		526,170			577,005
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	1,734,478		$	1,798,642
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are
an integral part of these balance sheets.

101

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	September 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	72,799		$	90,556
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		27,475			24,723
Amortization of regulatory assets		79,284			73,909
Deferral of new regulatory assets		(47,373	)		(43,186	)
Deferred rents and lease market valuation liability		(23,551	)		(27,114	)
Deferred income taxes and investment tax credits, net		(32,530	)		(28,603	)
Accrued compensation and retirement benefits		3,493			2,766
Pension trust contribution		(7,659	)		-
Decrease (increase) in operating assets-
Receivables		(13,368	)		(25,069	)
Prepayments and other current assets		224			(75	)
Increase (decrease) in operating liabilities-
Accounts payable		9,515			1,102
Accrued taxes		7,463			3,458
Accrued interest		3,444			(709	)
Electric service prepayment programs		(7,650	)		(6,744	)
Other		1,953			1,716
Net cash provided from operating activities		73,519			66,730
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		37,191			113,886
Equity contribution from parent		6,125			-
Redemptions and Repayments-
Preferred stock		-			(30,000	)
Long-term debt		(30,014	)		(53,650	)
Dividend Payments-
Common stock		(120,000	)		(50,000	)
Preferred stock		-			(3,597	)
Net cash used for financing activities		(106,698	)		(23,361	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(41,573	)		(45,661	)
Loan repayments from (loans to) associated companies, net		21,438			(61,549	)
Collection of principal on long-term notes receivable		36,077			53,766
Redemption of lessor notes		14,819			9,275
Sales of investment securities held in trusts		39,260			50,255
Purchases of investment securities held in trusts		(39,557	)		(50,433	)
Other		2,713			983
Net cash provided from (used for) investing activities		33,177			(43,364	)
Net increase (decrease) in cash and cash equivalents		(2	)		5
Cash and cash equivalents at beginning of period		22			15
Cash and cash equivalents at end of period	$	20		$	20
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an
integral part of these statements.

102

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, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  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, 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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006 as discussed in Note 3 to those consolidated financial statements) dated February 27, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

October 31, 2007

103

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

Earnings on common stock in the first nine months of 2007 decreased to $73 million from $87 million in the same period of 2006. The decrease resulted primarily from higher purchased power and other operating costs and increased interest expense, partially offset by higher electric sales revenues.

Revenues

Revenues increased $44 million or 6.2% in the first nine months of 2007 compared to the same period of 2006 primarily due to increases in retail generation revenues ($24 million), wholesale generation revenues ($11 million) and distribution revenues ($6 million). Retail generation revenues increased in the first nine months of 2007 due to higher average prices and increased sales volume across all customer classes compared to the same period of 2006. Average prices increased primarily due to higher composite unit prices for retail generation shopping customers returning to TE. The increase in sales volume also reflects increased weather-related usage in the first nine months of 2007 (heating and cooling degree days increased 15.2% and 7.2%, respectively, from the same period of 2006).

The increase in wholesale revenues resulted primarily from increased KWH sales to associated companies and higher unit prices. TE sells KWH from its leasehold interests in Beaver Valley Unit 2 and the Bruce Mansfield Plant to CEI and FGCO, respectively.

Increases in retail electric generation KWH sales and revenues in the first nine months of 2007 from the same period of 2006 are summarized in the following tables.

Retail Generation KWH Sales	Increase
Residential		8.0	%
Commercial		3.1	%
Industrial		1.0	%
Increase in Retail Generation  Sales		3.1	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	8
Commercial		4
Industrial		12
Increase in Retail Generation Revenues	$	24

Revenues from distribution throughput increased by $6 million in the first nine months of 2007 compared to the same period in 2006 due to higher KWH deliveries to all customer sectors, partially offset by lower average unit prices for industrial customers. The higher KWH deliveries to residential and commercial customers in the first nine months of 2007 reflected the weather impacts described above.

Changes in distribution KWH deliveries and revenues in the first nine months of 2007 from the same period of 2006 are summarized in the following tables.

Distribution KWH Deliveries	Increase
Residential		5.5	%
Commercial		2.6	%
Industrial		1.1	%
Increase in Distribution Deliveries		2.5	%

104

Distribution Revenues	Increase (Decrease)
	(In millions)
Residential	$	7
Commercial		3
Industrial		(4	)
Net Increase in Distribution Revenues	$	6

Expenses

Total expenses increased $52 million in the first nine months of 2007 from the same period of 2006. The following table presents changes from the prior year by expense category:

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	37
Nuclear operating costs		(1	)
Other operating costs		12
Provision for depreciation		3
Amortization of regulatory assets		5
Deferral of new regulatory assets		(4	)
Net increase in expenses	$	52

Higher purchased power costs in the first nine months of 2007 compared to the same period of 2006 reflected higher unit prices associated with the PSA with FES and an increase in KWH purchases to meet the higher retail generation sales requirements. Other operating costs were higher due to an $11 million increase in MISO network transmission expenses in the first nine months of 2007. Depreciation expense was higher due to an increase in depreciable property, reflecting plant additions since the third quarter of 2006. Higher amortization of regulatory assets was due to increased amortization of transition cost deferrals ($3 million) and MISO transmission deferrals ($2 million). The change in the deferral of new regulatory assets was primarily due to increased deferrals for MISO transmission expenses ($7 million) and RCP distribution costs ($4 million), partially offset by lower RCP fuel cost deferrals ($5 million).

Other Expense

Other expense increased $20 million in the first nine months of 2007 compared to the same period of 2006 primarily due to lower investment income and higher interest expense. The decrease in investment income resulted primarily from the principal repayments since the third quarter of 2006 on notes receivable from associated companies. The higher interest expense is principally associated with new long-term debt issued in November 2006.

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.

105

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
STATEMENTS OF INCOME	(In thousands)
REVENUES:
Electric sales	$	1,018,049		$	895,389		$	2,457,146		$	2,059,499
Excise tax collections		15,168			15,679			39,849			38,845
Total revenues		1,033,217			911,068			2,496,995			2,098,344
EXPENSES:
Purchased power		654,418			546,125			1,505,420			1,204,880
Other operating costs		87,010			90,578			236,225			245,711
Provision for depreciation		22,032			21,099			63,867			62,553
Amortization of regulatory assets		107,837			78,052			296,955			210,323
General taxes		18,631			19,187			51,183			49,691
Total expenses		889,928			755,041			2,153,650			1,773,158
OPERATING INCOME		143,289			156,027			343,345			325,186
OTHER INCOME (EXPENSE):
Miscellaneous income		2,967			2,091			9,266			8,162
Interest expense		(24,666	)		(21,437	)		(71,576	)		(62,420	)
Capitalized interest		483			1,004			1,559			2,933
Total other expense		(21,216	)		(18,342	)		(60,751	)		(51,325	)
INCOME BEFORE INCOME TAXES		122,073			137,685			282,594			273,861
INCOME TAXES		46,275			58,316			118,637			120,506
NET INCOME		75,798			79,369			163,957			153,355
PREFERRED STOCK DIVIDEND REQUIREMENTS		-			917			-			1,167
EARNINGS ON COMMON STOCK	$	75,798		$	78,452		$	163,957		$	152,188
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	75,798		$	79,369		$	163,957		$	153,355
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(2,114	)		-			(6,344	)		-
Unrealized gain on derivative hedges		69			100			235			207
Other comprehensive income (loss)		(2,045	)		100			(6,109	)		207
Income tax expense (benefit) related to other
comprehensive income		(994	)		41			(2,973	)		84
Other comprehensive income (loss), net of tax		(1,051	)		59			(3,136	)		123
TOTAL COMPREHENSIVE INCOME	$	74,747		$	79,428		$	160,821		$	153,478
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral
part of these statements.

106

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2007			2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	77		$	41
Receivables-
Customers (less accumulated provisions of $4,821,000 and $3,524,000,
respectively, for uncollectible accounts)		396,700			254,046
Associated companies		369			11,574
Other (less accumulated provisions of $718,000 and $204,000,
respectively, for uncollectible accounts)		62,235			40,023
Notes receivable - associated companies		22,734			24,456
Materials and supplies, at average cost		1,915			2,043
Prepaid taxes		41,670			13,333
Other		14,080			18,076
		539,780			363,592
UTILITY PLANT:
In service		4,122,325			4,029,070
Less - Accumulated provision for depreciation		1,490,846			1,473,159
		2,631,479			2,555,911
Construction work in progress		84,199			78,728
		2,715,678			2,634,639
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		172,278			171,045
Nuclear plant decommissioning trusts		177,217			164,108
Other		2,075			2,047
		351,570			337,200
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		1,757,516			2,152,332
Goodwill		1,826,190			1,962,361
Pension assets		43,183			14,660
Other		15,124			17,781
		3,642,013			4,147,134
	$	7,249,041		$	7,482,565
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	26,680		$	32,683
Short-term borrowings-
Associated companies		155,395			186,540
Accounts payable-
Associated companies		22,399			80,426
Other		211,788			160,359
Accrued taxes		25,793			1,451
Accrued interest		27,520			14,458
Cash collateral from suppliers		68			32,311
Other		85,746			96,139
		555,389			604,367
CAPITALIZATION:
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares-
14,421,637 and 15,009,335 shares outstanding, respectively		144,216			150,093
Other paid-in capital		2,657,775			2,908,279
Accumulated other comprehensive loss		(47,390	)		(44,254	)
Retained earnings		266,342			145,480
Total common stockholder's equity		3,020,943			3,159,598
Long-term debt and other long-term obligations		1,568,296			1,320,341
		4,589,239			4,479,939
NONCURRENT LIABILITIES:
Power purchase contract loss liability		872,305			1,182,108
Accumulated deferred income taxes		762,782			803,944
Nuclear fuel disposal costs		190,524			183,533
Asset retirement obligations		88,334			84,446
Other		190,468			144,228
		2,104,413			2,398,259
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	7,249,041		$	7,482,565
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an
integral part of these balance sheets.

107

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	September 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	163,957		$	153,355
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		63,867			62,553
Amortization of regulatory assets		296,955			210,323
Deferred purchased power and other costs		(157,201	)		(213,621	)
Deferred income taxes and investment tax credits, net		(23,786	)		25,217
Accrued compensation and retirement benefits		(17,543	)		(4,196	)
Cash collateral returned to suppliers		(32,243	)		(108,926	)
Pension trust contribution		(17,800	)		-
Decrease (increase) in operating assets-
Receivables		(153,660	)		(50,337	)
Materials and supplies		127			86
Prepaid taxes		(28,337	)		(29,923	)
Other current assets		2,079			(2,118	)
Increase (decrease) in operating liabilities-
Accounts payable		(6,598	)		(8,131	)
Accrued taxes		29,318			(16,992	)
Accrued interest		13,062			16,296
Tax collections payable		(12,478	)		(10,316	)
Other		(7,440	)		(4,814	)
Net cash provided from operating activities		112,279			18,456
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		549,999			382,400
Equity contribution from parent		4,636			-
Redemptions and Repayments-
Long-term debt		(324,256	)		(162,157	)
Short-term borrowings, net		(31,145	)		(44,162	)
Common stock		(125,000	)		-
Preferred stock		-			(13,461	)
Dividend Payments-
Common stock		(43,000	)		(45,000	)
Preferred stock		-			(354	)
Net cash provided from financing activities		31,234			117,266
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(144,668	)		(123,540	)
Loan repayments from (loans to) associated companies, net		1,722			(8,638	)
Sales of investment securities held in trusts		169,649			169,676
Purchases of investment securities held in trusts		(171,820	)		(171,847	)
Other		1,640			(1,417	)
Net cash used for investing activities		(143,477	)		(135,766	)
Net increase (decrease) in cash and cash equivalents		36			(44	)
Cash and cash equivalents at beginning of period		41			102
Cash and cash equivalents at end of period	$	77		$	58
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.

108

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, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  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, 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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, as discussed in Note 3 to those consolidated financial statements) dated February 27, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

October 31, 2007

109

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

Results of Operations

Earnings on common stock increased to $164 million in the first nine months of 2007 compared to $152 million for the same period in 2006. The increase was primarily due to higher revenues and lower other operating costs, partially offset by higher purchased power costs and increased amortization of regulatory assets.

Revenues

Revenues increased $399 million or 19% in the first nine months of 2007 compared with the same period of 2006. Retail and wholesale generation revenues increased by $250 million and $49 million, respectively, in the first nine months of 2007.

Retail generation revenues from all customer classes increased in the first nine months of 2007 compared to 2006 due to higher unit prices resulting from the BGS auctions effective June 1, 2006 and June 1, 2007 and higher retail generation KWH sales. Sales volume increased as a result of weather conditions in the first nine months of 2007 (heating degree days were 15.8% higher than the first nine months of 2006 and cooling degree days decreased slightly). Industrial generation KWH sales declined in the first nine months of 2007 from the same period in 2006 due to an increase in customer shopping.

Wholesale generation revenues increased $49 million in the first nine months of 2007 due to higher market prices, partially offset by a 3.0% decrease in sales volume compared with the first nine months of 2006.

Changes in retail generation KWH sales and revenues by customer class in the first nine months of 2007 compared to the same period of 2006 are summarized in the following table:

Retail Generation KWH Sales	Increase (Decrease)
Residential		2.3	%
Commercial		1.6	%
Industrial		(7.0	)%
Net Increase in Generation Sales		1.6	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	145
Commercial		100
Industrial		5
Increase in Generation Revenues	$	250

Distribution revenues increased in the first nine months of 2007 compared to the same period of 2006 due to higher composite unit prices and increased KWH deliveries, reflecting the weather impacts described above. The higher unit prices resulted from an NUGC rate increase effective in December 2006.

Changes in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables.

Distribution KWH Deliveries	Increase
Residential		2.3	%
Commercial		3.3	%
Industrial		1.1	%
Increase in Distribution Deliveries		2.6	%

110

Distribution Revenues	Increase
	(In millions)
Residential	$	35
Commercial		38
Industrial		6
Increase in Distribution Revenues	$	79

The higher revenues for the first nine months of 2007 also included $20 million of increased revenues resulting from the August 2006 securitization of deferred costs associated with JCP&L’s BGS supply.

Expenses

Total expenses increased by $380 million in the first nine months of 2007 as compared to the same period of 2006. The following table presents changes from the prior year by expense category:

Expenses  - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	300
Other operating costs		(9	)
Provision for depreciation		1
Amortization of regulatory assets		87
General Taxes		1
Net increase in expenses	$	380

The increase in purchased power costs primarily reflected higher unit prices resulting from the June 2006 and June 2007 BGS auctions. Other operating costs decreased $9 million in the first nine months of 2007 primarily due to lower employee benefit costs. Amortization of regulatory assets increased $87 million in the first nine months of 2007 due to higher cost recovery associated with the December 2006 NUGC rate increase.

Other Expenses

Other expenses increased $9 million in the first nine months of 2007 from the same period in 2006 primarily due to interest expense associated with JCP&L’s $550 million issuance of Senior Notes in May 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 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.

111

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(In thousands)
REVENUES:
Electric sales	$	391,083		$	337,750		$	1,087,460		$	898,320
Gross receipts tax collections		19,524			18,431			55,146			51,293
Total revenues		410,607			356,181			1,142,606			949,613
EXPENSES:
Purchased power		209,842			184,508			584,249			487,465
Other operating costs		106,104			108,740			315,227			229,394
Provision for depreciation		11,154			10,197			31,969			31,390
Amortization of regulatory assets		36,853			33,560			101,965			89,277
Deferral of new regulatory assets		(19,151	)		(44,213	)		(93,772	)		(89,794	)
General taxes		21,986			21,362			63,208			60,578
Total expenses		366,788			314,154			1,002,846			808,310
OPERATING INCOME		43,819			42,027			139,760			141,303
OTHER INCOME (EXPENSE):
Interest income		7,239			8,053			22,740			25,767
Miscellaneous income		1,366			1,477			3,973			5,881
Interest expense		(13,291	)		(12,291	)		(38,471	)		(35,546	)
Capitalized interest		292			355			940			966
Total other expense		(4,394	)		(2,406	)		(10,818	)		(2,932	)
INCOME BEFORE INCOME TAXES		39,425			39,621			128,942			138,371
INCOME TAXES		14,737			14,631			53,145			55,390
NET INCOME		24,688			24,990			75,797			82,981
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(1,452	)		-			(4,357	)		-
Unrealized gain on derivative hedges		83			83			251			251
Other comprehensive income (loss)		(1,369	)		83			(4,106	)		251
Income tax expense (benefit) related to other
comprehensive income		(693	)		34			(2,078	)		104
Other comprehensive income (loss), net of tax		(676	)		49			(2,028	)		147
TOTAL COMPREHENSIVE INCOME	$	24,012		$	25,039		$	73,769		$	83,128
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of
these statements.

112

METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2007			2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	126		$	130
Receivables-
Customers (less accumulated provisions of $4,740,000 and $4,153,000,
respectively, for uncollectible accounts)		154,622			127,084
Associated companies		23,728			3,604
Other		18,043			8,107
Notes receivable from associated companies		34,620			31,109
Prepaid taxes		5,755			13,533
Other		1,976			1,424
		238,870			184,991
UTILITY PLANT:
In service		1,976,453			1,920,563
Less - Accumulated provision for depreciation		755,018			739,719
		1,221,435			1,180,844
Construction work in progress		21,124			18,466
		1,242,559			1,199,310
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		290,349			269,777
Other		1,360			1,362
		291,709			271,139
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		426,368			496,129
Regulatory assets		458,566			409,095
Pension assets		26,239			7,261
Other		38,653			46,354
		949,826			958,839
	$	2,722,964		$	2,614,279
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	-		$	50,000
Short-term borrowings-
Associated companies		254,826			141,501
Other		80,000			-
Accounts payable-
Associated companies		24,807			100,232
Other		55,186			59,077
Accrued taxes		9,033			11,300
Accrued interest		7,343			7,496
Other		26,960			22,825
		458,155			392,431
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,500 shares outstanding		1,207,634			1,276,075
Accumulated other comprehensive loss		(28,544	)		(26,516	)
Accumulated deficit		(158,873	)		(234,620	)
Total common stockholder's equity		1,020,217			1,014,939
Long-term debt and other long-term obligations		542,100			542,009
		1,562,317			1,556,948
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		393,169			387,456
Accumulated deferred investment tax credits		8,623			9,244
Nuclear fuel disposal costs		43,038			41,459
Asset retirement obligations		158,302			151,107
Retirement benefits		15,830			19,522
Other		83,530			56,112
		702,492			664,900
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	2,722,964		$	2,614,279
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part
of these balance sheets.

113

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	September 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	75,797		$	82,981
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		31,969			31,390
Amortization of regulatory assets		101,965			89,277
Deferred costs recoverable as regulatory assets		(53,276	)		(53,406	)
Deferral of new regulatory assets		(93,772	)		(89,794	)
Deferred income taxes and investment tax credits, net		20,514			27,895
Accrued compensation and retirement benefits		(14,404	)		(6,007	)
Cash collateral		1,650			(21,500	)
Pension trust contribution		(11,012	)		-
Decrease (increase) in operating assets-
Receivables		(57,599	)		27,680
Prepayments and other current assets		7,227			(8,247	)
Increase (decrease) in operating liabilities-
Accounts payable		(79,316	)		(1,553	)
Accrued taxes		1,787			(10,451	)
Accrued interest		(153	)		(308	)
Other		5,436			(1,777	)
Net cash provided from (used for) operating activities		(63,187	)		66,180
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		193,324			116,624
Equity contribution from parent		1,237			-
Redemptions and Repayments-
Long-term debt		(50,000	)		(100,000	)
Dividend Payments-
Common Stock		-			(5,000	)
Net cash provided from financing activities		144,561			11,624
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(74,812	)		(65,332	)
Sales of investment securities held in trusts		153,943			146,841
Purchases of investment securities held in trusts		(156,623	)		(153,953	)
Loans to associated companies, net		(3,511	)		(4,853	)
Other		(375	)		(494	)
Net cash used for investing activities		(81,378	)		(77,791	)
Net increase (decrease) in cash and cash equivalents		(4	)		13
Cash and cash equivalents at beginning of period		130			120
Cash and cash equivalents at end of period	$	126		$	133
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these statements.

114

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, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  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, 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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

October 31, 2007

115

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 for the first nine months of 2007 decreased to $76 million from $83 million in the first nine months of 2006. The decrease was primarily due to higher purchased power costs and other operating costs, partially offset by higher revenues.

Revenues

Revenues increased by $193 million, or 20.3%, in the first nine months of 2007 compared with the first nine months of 2006. This increase was primarily due to higher distribution revenues and wholesale generation revenues.

In the first nine months of 2007, retail generation revenues increased by $19 million primarily due to higher KWH sales in all customer sectors. The increase in retail generation revenues in the residential and commercial sectors primarily resulted from higher weather-related usage in the first nine months of 2007 as compared to the same period of 2006 (heating degree days increased by 17.1% and cooling degree days increased by 7.1%).

Increases in retail generation sales and revenues in the first nine months of 2007 compared to the same period of 2006 are summarized in the following tables:

Retail Generation KWH Sales	Increase
Residential		5.6	%
Commercial		4.0	%
Industrial		0.6	%
Increase in Retail Generation Sales		3.6	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	11
Commercial		8
Industrial		-
Increase in Retail Generation Revenues	$	19

Wholesale revenues increased by $107 million in the first nine months of 2007 compared with the same period of 2006 due to Met-Ed selling additional available power into the PJM market beginning in January 2007.

Revenues from distribution throughput increased by $55 million in the first nine months of 2007 compared to the same period in 2006. The increase was due to higher KWH deliveries, reflecting the effect of the weather discussed above, and an increase in composite unit prices resulting from the January 2007 PPUC authorization to increase transmission rates, partially offset by a decrease in distribution rates.

Increases in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the same period of 2006 are summarized in the following tables:

Distribution KWH Deliveries	Increase
Residential		5.6	%
Commercial		4.0	%
Industrial		0.2	%
Increase in Distribution Deliveries		3.5	%

116

Distribution Revenues	Increase
	(In millions)
Residential	$	38
Commercial		5
Industrial		12
Increase in Distribution Revenues	$	55

PJM transmission revenues increased by $18 million in the first nine months of 2007 as a result of higher transmission volumes and additional PJM auction revenue rights, compared to the prior year period. Met-Ed defers the difference between revenue from its transmission rider and transmission costs incurred, resulting in no material effect to current period earnings.

Expenses

Total expenses increased by $195 million in the first nine months of 2007 compared to the same period of 2006. The following table presents changes from the prior year by expense category:

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	97
Other operating costs		86
Amortization of regulatory assets		13
Deferral of new regulatory assets		(4	)
General taxes		3
Net increase in expenses	$	195

Purchased power costs increased in the first nine months of 2007 by $97 million due to higher volumes purchased to source higher generation sales, combined with higher composite unit costs. Other operating costs increased in the first nine months of 2007 primarily due to higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above ($83 million) and increased expenses ($3 million) related to Met-Ed’s customer assistance programs.

Amortization of regulatory assets increased in the first nine months of 2007 primarily due to the recovery (through Met-Ed’s transmission rider discussed above) of certain transmission costs deferred in 2006 and the amortization of the Saxton nuclear research facility’s decommissioning costs as authorized by the PPUC in January 2007. The deferral of new regulatory assets increased in the first nine months of 2007 primarily due to the deferral of previously expensed Saxton decommissioning costs of $15 million (see Legal Proceedings), partially offset by lower PJM transmission deferrals.

In the first nine months of 2007, general taxes increased primarily due to higher gross receipts taxes.

On October 1, 2007, Met-Ed sold 100% of its interest in York Haven Power Company for $5 million. The sale is subject to regulatory accounting and will not have a material impact on Met-Ed’s earnings in the fourth 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 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.

117

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(In thousands)
REVENUES:
Electric sales	$	336,798		$	287,633		$	991,769		$	813,860
Gross receipts tax collections		16,637			15,787			48,989			46,311
Total revenues		353,435			303,420			1,040,758			860,171
EXPENSES:
Purchased power		203,247			165,921			588,583			474,437
Other operating costs		51,571			65,165			169,299			151,640
Provision for depreciation		12,566			11,828			36,678			36,269
Amortization of regulatory assets, net		20,861			3,825			32,648			19,804
General taxes		19,433			18,593			57,634			55,440
Total expenses		307,678			265,332			884,842			737,590
OPERATING INCOME		45,757			38,088			155,916			122,581
OTHER INCOME (EXPENSE):
Miscellaneous income		1,483			2,182			5,035			6,179
Interest expense		(14,017	)		(11,840	)		(38,426	)		(33,975	)
Capitalized interest		194			363			737			1,132
Total other expense		(12,340	)		(9,295	)		(32,654	)		(26,664	)
INCOME BEFORE INCOME TAXES		33,417			28,793			123,262			95,917
INCOME TAXES		10,387			10,733			49,025			39,251
NET INCOME		23,030			18,060			74,237			56,666
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(2,825	)		-			(8,475	)		-
Unrealized gain on derivative hedges		16			17			49			49
Change in unrealized gain on available for sale securities		10			14			(6	)		(4	)
Other comprehensive income (loss)		(2,799	)		31			(8,432	)		45
Income tax expense (benefit) related to other
comprehensive income		(1,294	)		13			(3,894	)		20
Other comprehensive income (loss), net of tax		(1,505	)		18			(4,538	)		25
TOTAL COMPREHENSIVE INCOME	$	21,525		$	18,078		$	69,699		$	56,691
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral
part of these statements.

118

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2007			2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	38		$	44
Receivables-
Customers (less accumulated provisions of $4,094,000 and $3,814,000
respectively, for uncollectible accounts)		138,007			126,639
Associated companies		21,872			49,728
Other		19,047			16,367
Notes receivable from associated companies		17,170			19,548
Prepaid taxes		7,268			3,016
Other		1,724			1,220
		205,126			216,562
UTILITY PLANT:
In service		2,188,553			2,141,324
Less - Accumulated provision for depreciation		824,141			809,028
		1,364,412			1,332,296
Construction work in progress		26,835			22,124
		1,391,247			1,354,420
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		137,896			125,216
Non-utility generation trusts		147,745			99,814
Other		531			531
		286,172			225,561
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		777,904			860,716
Pension assets		34,484			11,474
Other		34,371			36,059
		846,759			908,249
	$	2,729,304		$	2,704,792
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Short-term borrowings-
Associated companies	$	187,313		$	199,231
Other		65,000			-
Accounts payable-
Associated companies		107,666			92,020
Other		46,283			47,629
Accrued taxes		3,091			11,670
Accrued interest		13,832			7,224
Other		24,481			21,178
		447,666			378,952
CAPITALIZATION:
Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
4,427,577 and 5,290,596 shares outstanding, respectively		88,552			105,812
Other paid-in capital		925,229			1,189,434
Accumulated other comprehensive loss		(11,731	)		(7,193	)
Retained earnings		39,195			90,005
Total common stockholder's equity		1,041,245			1,378,058
Long-term debt and other long-term obligations		777,020			477,304
		1,818,265			1,855,362
NONCURRENT LIABILITIES:
Regulatory liabilities		77,441			96,151
Asset retirement obligations		80,589			76,924
Accumulated deferred income taxes		183,598			193,662
Retirement benefits		51,289			50,328
Other		70,456			53,413
		463,373			470,478
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	2,729,304		$	2,704,792
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
integral part of these balance sheets.

119

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	September 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	74,237		$	56,666
Adjustments to reconcile net income to net cash from operating activities
Provision for depreciation		36,678			36,269
Amortization of regulatory assets		43,601			40,854
Deferral of new regulatory assets		(10,953	)		(21,050	)
Deferred costs recoverable as regulatory assets		(54,228	)		(56,272	)
Deferred income taxes and investment tax credits, net		8,065			14,518
Accrued compensation and retirement benefits		(16,032	)		2,807
Cash collateral		50			-
Pension trust contribution		(13,436	)		-
Decrease (increase) in operating assets
Receivables		13,809			22,719
Prepayments and other current assets		(4,757	)		(2,977	)
Increase (decrease) in operating liabilities
Accounts payable		14,299			(15,555	)
Accrued taxes		(6,191	)		(9,841	)
Accrued interest		6,608			5,468
Other		2,653			(2,188	)
Net cash provided from operating activities		94,403			71,418
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing
Long-Term Debt		297,149			-
Short-term borrowings, net		53,082			21,278
Equity contribution from parent		1,261			-
Redemptions and Repayments
Common Stock		(200,000	)		-
Dividend Payments
Common Stock		(125,000	)		(5,000	)
Net cash provided from financing activities		26,492			16,278
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(70,076	)		(81,228	)
Loan repayments from (loans to) associated companies, net		2,378			(2,976	)
Sales of investment securities held in trust		94,292			83,601
Purchases of investment securities held in trust		(144,167	)		(83,601	)
Other, net		(3,328	)		(3,480	)
Net cash used for investing activities		(120,901	)		(87,684	)
Net increase (decrease) in cash and cash equivalents		(6	)		12
Cash and cash equivalents at beginning of period		44			35
Cash and cash equivalents at end of period	$	38		$	47
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
integral part of these statements.

120

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, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.  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, 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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

October 31, 2007

121

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

In the first nine months of 2007, net income increased to $74 million, compared to $57 million in the first nine months of 2006. The increase in net income was primarily due to higher revenues, partially offset by increased purchased power costs and other operating costs.

Revenues

Revenues increased by $181 million, or 21.0%, in the first nine months of 2007 compared to the same period last year. The increase was primarily due to higher distribution revenues and wholesale generation revenues.

Retail generation revenues increased $15 million for the first nine months of 2007 primarily due to higher KWH sales to all customer classes. The increase in retail generation revenues in the residential and commercial sectors was primarily impacted by weather in the first nine months of 2007 (heating degree days increased 11.0% and cooling degree days increased 14.1% as compared to the same time period of 2006).

Increases in retail generation sales and revenues in first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables:

Retail Generation KWH Sales	Increase
Residential		3.6	%
Commercial		3.6	%
Industrial		0.1	%
Increase in Retail Generation Sales		2.5	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	6
Commercial		8
Industrial		1
Increase in Retail Generation Revenues	$	15

Wholesale revenues increased $123 million in the first nine months of 2007, compared with the same period of 2006 due to Penelec selling additional available power into the PJM market beginning in January 2007.

Revenues from distribution throughput increased $37 million in the first nine months of 2007 due to higher KWH deliveries to residential and commercial customers reflecting the effect of the weather discussed above and an increase in composite unit prices for residential and industrial customers resulting from a January 2007 PPUC authorization to increase transmission rates, partially offset by a decrease in distribution rates.

Changes in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the same period in 2006 are summarized in the following tables:

	Increase
Distribution KWH Deliveries	(Decrease)
Residential		3.6	%
Commercial		3.6	%
Industrial		(1.3	)%
Net Increase in Distribution Deliveries		1.9	%

122

	Increase
Distribution  Revenues	(Decrease)
	(In millions)
Residential	$	37
Commercial		(4	)
Industrial		4
Net Increase in Distribution Revenues	$	37

PJM transmission revenues increased by $6 million in the first nine months of 2007 compared to the same period in 2006 due to higher transmission volumes and additional PJM auction revenue rights in 2007. Penelec defers the difference between revenue from its transmission rider and transmission costs incurred, with no material effect to current period earnings.

Expenses

Total expenses increased by $147 million in the first nine months of 2007 compared with the same period in 2006. The following table presents changes from the prior year by expense category:

Expenses - Changes	Increase
	(In millions)
Purchased power costs	$	114
Other operating costs		18
Amortization of regulatory assets, net		13
General taxes		2
Increase in Expenses	$	147

Purchased power costs increased by $114 million, or 24.1% in the first nine months of 2007, compared to the same period of 2006. The increase was due primarily to higher volumes purchased to source higher retail and wholesale generation sales combined with higher composite unit costs. Other operating costs increased by $18 million in the first nine months of 2007 principally due to higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above.

Net amortization of regulatory assets increased in the first nine months of 2007 primarily due to the recovery (through Penelec’s transmission rider discussed above) of certain transmission costs deferred in 2006 and lower transmission cost deferrals in 2007, partially offset by the deferral of new regulatory assets for previously expensed decommissioning costs of $12 million associated with the Saxton nuclear research facility as authorized by the PPUC in January 2007 (see Legal Proceedings).

General taxes increased $2 million in the first nine months of 2007 as compared to 2006, primarily due to higher gross receipts taxes.

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.

123

COMBINED MANAGEMENT’S DISCUSSION

AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain disclosures referenced in Management’s Narrative Analysis of Results of Operations of FES and the Companies. This information should be read in conjunction with (i) FES’ and the Companies’ respective Consolidated Financial Statements and Management’s Narrative Analysis of Results of Operations; (ii) the Notes to Consolidated Financial Statements as they relate to FES and the Companies; and (iii) the Companies’ respective 2006 Annual Reports on Form 10-K.

Regulatory Matters (Applicable to each of the Companies)

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

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

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

· providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

· itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges;

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

· requiring corporate separation of regulated and unregulated business activities.

The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $227 million as of September 30, 2007 (JCP&L - $93 million, Met-Ed - $43 million and Penelec - $91 million). Regulatory assets not earning a current return will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets by company:

	September 30,		December 31,		Increase
Regulatory Assets*	2007		2006		(Decrease)
	(In millions)
OE	$	717	$	741	$	(24	)
CEI		856		855		1
TE		215		248		(33	)
JCP&L		1,758		2,152		(394	)
Met-Ed		459		409		50
ATSI		42		36		6
Total	$	4,047	$	4,441	$	(394	)

* Penelec had net regulatory liabilities of approximately $77 million and $96 million as of September 30, 2007 and December 31, 2006, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

124

Ohio (Applicable to OE, CEI and TE)

The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2007 through 2010:

Amortization							Total
Period	OE		CEI		TE		Ohio
	(In millions)
2007	$	176	$	108	$	92	$	376
2008		209		126		113		448
2009		-		217		-		217
2010		-		269		-		269
Total Amortization	$	385	$	720	$	205	$	1,310

Several parties subsequently filed appeals to the Supreme Court of Ohio in connection with certain portions of the RCP approved by the PUCO. In its order, the PUCO authorized the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs, all such costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a 25-year period through distribution rates, which was expected to begin on January 1, 2009 for OE and TE, and approximately May 2009 for CEI.  Through September 30, 2007, the deferred fuel costs, including interest, were $89 million, $61 million and $26 million for OE, CEI and TE, respectively.

On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated certain provisions of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” because fuel costs are a component of generation service, not distribution service, and because the Court concluded the PUCO did not address whether the deferral of fuel costs was anticompetitive.  The Court remanded the matter to the PUCO for further consideration consistent with the Court’s Opinion on this issue and affirmed the PUCO’s Order in all other respects. On September 7, 2007, the Ohio Companies filed a Motion for Reconsideration with the Court. On September 10, 2007 the Ohio Companies filed an Application with the PUCO that requests the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. The Ohio Companies requested the riders become effective in October 2007 and end in December 2008, subject to reconciliation which is expected to continue through the first quarter of 2009. This matter is currently pending before the PUCO. Although unable to predict the ultimate outcome of this matter, the Ohio Companies intend to continue deferring the fuel costs pursuant to the RCP, pending the Court’s disposition of the Motion for Reconsideration and the PUCO’s action with respect to the Ohio Companies’ Application.

On August 31, 2005, the PUCO approved a rider recovery mechanism through which the Ohio Companies may recover all MISO transmission and ancillary service related costs incurred during each year ending June 30. Pursuant to the PUCO’s order, the Ohio Companies, on May 1, 2007, filed revised riders, which became effective on July 1, 2007.  The revised riders represent an increase over the amounts collected through the 2006 riders of approximately $64 million annually.  If it is subsequently determined by the PUCO that adjustments to the rider as filed are necessary, such adjustments, with carrying costs, will be incorporated into the 2008 transmission rider filing.

On May 8, 2007, the Ohio Companies filed with the PUCO a notice of intent to file for an increase in electric distribution rates. The Ohio Companies filed the application and rate request with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the bill for most Ohio customers.  The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operating and maintenance expenses and recovery of regulatory assets created by deferrals that were approved in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million to the PUCO to establish the test period data that will be used as the basis for setting rates in that proceeding. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in early 2008. The PUCO order is expected to be issued in the second quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

125

On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Comments by intervenors in the case were filed on September 5, 2007.  The PUCO Staff filed comments on September 21, 2007.  Parties filed reply comments on October 12, 2007. The Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process.

On September 25, 2007, the Ohio Governor’s proposed energy plan was officially introduced into the Ohio Senate. The bill proposes to revise state energy policy to address electric generation pricing after 2008, establish advanced energy portfolio standards and energy efficiency standards, and create GHG emissions reporting and carbon control planning requirements. The bill also proposes to move to a “hybrid” system for determining rates for PLR service in which electric utilities would provide regulated generation service unless they satisfy a statutory burden to demonstrate the existence of a competitive market for retail electricity. The Senate Energy & Public Utilities Committee has been conducting hearings on the bill and receiving testimony from interested parties, including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer groups, utility executives and others. Several proposed amendments to the bill have been submitted, including those from Ohio’s investor-owned electric utilities. A substitute version of the bill, which incorporated certain of the proposed amendments, was introduced into the Senate Energy & Public Utilities Committee on October 25, 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of the Ohio Companies.

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

Met-Ed and Penelec have been purchasing a portion of their PLR requirements from FES through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy requirements during the term of these agreements with FES.

On September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that were substantially higher than the fixed price in the partial requirements agreements.

Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.

If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its 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.

126

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 also 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, when new transmission rates were effective, 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 in 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 expenses and the transmission deferral. 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). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part the MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the 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. On June 19, 2007, initial briefs were filed and responsive briefs were filed through September 21, 2007.  Reply briefs were filed on October 5, 2007. Oral arguments are expected to take place in late 2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the financial condition and results of operations of Met-Ed, Penelec and FirstEnergy.

As of September 30, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $496 million and $58 million, respectively. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in February 2007 and briefing was completed on March 28, 2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.

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On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service will be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. On September 28, 2007, Penn filed a Joint Petition for Settlement resolving all but one issue in the case.  Briefs were also filed on September 28, 2007, on the unresolved issue of incremental uncollectible accounts expense. The settlement is either supported, or not opposed, by all parties. The PPUC is expected to act on the settlement and the unresolved issue in late November or early December 2007 for the initial RFP to take place in January 2008.

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation programs to meet demand 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 an optional 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 final form of any legislation arising from the special legislative session is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

New Jersey (Applicable to JCP&L)

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2007, the accumulated deferred cost balance totaled approximately $330 million.

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

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that would 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. Comments on the alternative proposal were submitted on June 15, 2006. On November 3, 2006, the Staff circulated a revised draft proposal to interested stakeholders. Another revised draft was circulated by the NJBPU Staff on February 8, 2007.

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated with the issuance of a proposed set of objectives which, as to electricity, included the following:

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

·   Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date;

 · Reduce air pollution related to energy use;

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 · Encourage and maintain economic growth and development;

·   Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020;

·   Maintain unit prices for electricity to no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia); and

 ·Eliminate transmission congestion by 2020.

Comments on the objectives and participation in the development of the EMP have been solicited and a number of working groups have been formed to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing (1) energy efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing issues have completed their assigned tasks of data gathering and analysis and have provided reports to the EMP Committee. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected later in 2007. A final draft of the EMP is expected to be presented to the Governor in late 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of JCP&L.

On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards.  Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff.  On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments which were due on September 26, 2007.  At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such regulations may have on its operations or those of JCP&L.

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

On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the fourth quarter of 2007.

On January 31, 2005, certain PJM transmission owners made three 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. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, BG&E and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. Hearings were held and numerous parties appeared and litigated various issues; including AEP, which filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. At the conclusion of the hearings, the ALJ issued an initial decision adopting the FERC Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate. The ALJ recommended an April 1, 2006 effective date for this change in rate design. Numerous parties, including FirstEnergy, submitted briefs opposing the ALJ’s decision and recommendations.  On April 19, 2007, the FERC issued an order rejecting the ALJ’s findings and recommendations in nearly every respect. The FERC found that the PJM transmission owners’ existing “license plate” 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 socialized 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.  Nevertheless, 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.

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On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 Order.  Subsequently, FirstEnergy and other parties filed pleadings opposing the requests for rehearing. The FERC’s Orders on PJM rate design, if sustained on rehearing and appeal, will prevent the allocation of the cost 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 future transmission costs shifting to the JCP&L, Met-Ed and Penelec zones.

New FERC Transmission Rate Design Filings

On August 1, 2007, a number of filings were made with the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.

FirstEnergy joined in a filing made by the MISO transmission owners that would maintain the existing “license plate” rates for transmission service within MISO provided over existing transmission facilities.  FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to continue the elimination of transmission rates associated with service over existing transmission facilities between MISO and PJM.  If adopted by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities.  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 be maintained (known as the RECB Process). Each of these filings was supported by the majority of transmission owners in either MISO or PJM, as applicable.

The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV and higher transmission facilities be spread throughout the entire MISO footprint.  Further, Indianapolis Power and Light Company separately moved the FERC to reopen the record to address the cost allocation for the RECB Process.  If either proposal is adopted by the FERC, it could shift a greater portion of the cost of new 345 kV and higher transmission facilities to the FirstEnergy footprint in MISO, and increase the transmission rates paid by load-serving FirstEnergy affiliates in MISO.

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “SuperRegion” that regionalizes the cost of new and existing transmission facilities operated at voltages of 345 kV and above.  Lower voltage facilities would continue to be recovered in the host utility transmission rate zone through a license plate rate. AEP requests a refund effective October 1, 2007, or alternatively, February 1, 2008.  The effect of this proposal, if adopted by FERC, would be to shift significant costs to the FirstEnergy zones in MISO and PJM.  FirstEnergy believes that most of these costs would ultimately be recoverable in retail rates. On October 12, 2007, BG&E filed a motion to dismiss AEP’s complaint. On October 16, 2007, the Organization of MISO States filed comments urging the FERC to dismiss AEP’s complaint. Interventions and protests to AEP’s complaint and answers to BG&E’s motion to dismiss were due October 29, 2007. FirstEnergy and other transmission owners filed protests to AEP’s complaint and support for BG&E’s motion to dismiss. AEP has asked for consolidation of its complaint with the cases above, and FirstEnergy expects it to be resolved on the same timeline as those cases.

Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC.  All or some of these proceedings may be consolidated by the FERC and set for hearing.  The outcome of these cases cannot be predicted.  Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates.  FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates.  Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.

MISO Ancillary Services Market and Balancing Area Consolidation Filing

MISO made a filing on September 14, 2007 to establish Ancillary Services markets for regulation, spinning and supplemental reserves to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region.  An effective date of June 1, 2008 was requested in the filing.

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MISO’s previous filing to establish an Ancillary Services market was rejected without prejudice by FERC on June 22, 2007, subject to MISO making certain modifications in its filing. FirstEnergy believes that MISO’s September 14 filing generally addresses the FERC’s directives.  FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas, but filed objections on specific aspects of the MISO proposal.  Interventions and protests to MISO’s filing were made with FERC on October 15, 2007.

Order No. 890 on Open Access Transmission Tariffs

On February 16, 2007, the FERC issued a final rule (Order No. 890) that revises its decade-old open access transmission regulations and policies.  The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process.  The final rule became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffs to comply with the FERC’s order. MISO, PJM and ATSI submitted tariff filings to the FERC on October 11, 2007. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.

Environmental Matters

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

Clean Air Act Compliance (Applicable to FES)

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

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006 alleging violations to various sections of the Clean Air Act. FES has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.

FES complies with SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO_X 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 NO_X reductions at FES' facilities. The EPA's NO_X Transport Rule imposes uniform reductions of NO_X emissions (an approximate 85% reduction in utility plant NO_X 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 NO_X emissions are contributing significantly to ozone levels in the eastern United States. FES believes its facilities are also complying with the NO_X budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act, alleging violations of air pollution laws at the Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 16, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. FirstEnergy is currently studying PennFuture’s complaint.

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National Ambient Air Quality Standards (Applicable to FES)

In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. 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 allowed each affected state until 2006 to develop implementing regulations to achieve additional reductions of NO_X and SO₂ emissions in two phases (Phase I in 2009 for NO_X, 2010 for SO₂ and Phase II in 2015 for both NO_X and SO₂). FES’ Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO₂ and NO_X emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on NO_X emissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_X emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_X cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FES operates affected facilities.

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, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO₂ and NO_X emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. FES' future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FES operates affected facilities.

The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FES would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FES will be disadvantaged if these model rules were implemented as proposed because FES’ substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

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. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. 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 Mansfield Plant, FES’ only coal-fired Pennsylvania power plant, until 2015, if at all.

W. H. Sammis Plant (Applicable to FES, OE and Penn)

In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn, and is now owned by FGCO. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as the New Source Review, or NSR, cases.

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NO_X and SO₂ emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreement are currently estimated to be $1.7 billion for 2007 through 2011 ($400 million of which is expected to be spent during 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009).

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The Sammis NSR Litigation consent decree also requires FirstEnergy to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.

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 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. At the international level, efforts have begun to develop climate change agreements for post-2012 GHG reductions. 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.

At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States.  State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO₂ emissions from automobiles as “air pollutants” under the Clean Air Act. Although this decision did not address CO₂ emissions from electric generating plants, the EPA has similar authority under the Clean Air Act to regulate “air pollutants” from those and other facilities. Also 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, the EPA proposed to change the NSR regulations, on May 8, 2007, to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.

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 federal Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to EPA for further rulemaking and eliminated the restoration option from 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 (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. FES is evaluating various control options and their costs and effectiveness. Depending on the outcome of such studies, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future cost of compliance with these standards may require material capital expenditures.

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

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous 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, 2007, FirstEnergy had approximately $1.5 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry.  As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans to seek for these facilities.

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are 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, 2007, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $89 million (JCP&L - $60 million, TE - $3 million, CEI - $1 million, and FirstEnergy Corp. - $25 million) have been accrued through September 30, 2007.

Other Legal Proceedings

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

Power Outages and Related Litigation (Applicable to FES and each of the Companies)

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New 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.  FirstEnergy is defending this class action but is unable to predict the outcome of this matter.  No liability has been accrued as of September 30, 2007.

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On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. – Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Two other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and AEP, as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. The four cases remaining were consolidated for hearing by the PUCO in an order dated March 7, 2006.  In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on January 8, 2008.

FirstEnergy is defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although FirstEnergy is unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, 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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Nuclear Plant Matters (Applicable to FES)

On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information 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 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 Demand for Information reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. The NRC held a public meeting on June 27, 2007 with FENOC to discuss FENOC’s response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC’s compliance with these commitments is subject to future NRC review.

Other Legal Matters (Applicable to OE and JCP&L)

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

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. The arbitration panel provided additional rulings regarding damages during a September 2007 hearing and it is anticipated that he will issue a final order in late 2007. JCP&L intends to re-file an appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

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

SFAS 157 – “Fair Value Measurements”

In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FES and the Companies are currently evaluating the impact of this Statement on their financial statements.

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SFAS 159 – “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”

In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value.  This Statement requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings.  The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet.  This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157 and SFAS 107. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FES and the Companies are currently evaluating the impact of this Statement on their financial statements.

EITF 06-11 – “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”

In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R).  The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to additional paid-in capital (APIC). This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement.  The consensus is effective for income tax benefits of dividends declared during fiscal years beginning after December 15, 2007.  EITF 06-11 is not expected to have a material impact on FES’ or the Companies’ financial statements.

FSP FIN 39-1 – “Amendment of FASB Interpretation No. 39”

In April 2007, the FASB issued Staff Position (FSP) FIN 39-1, which permits an entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement as the derivative instruments.  This FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. The effects of applying the guidance in this FSP should be recognized as a retrospective change in accounting principle for all financial statements presented. FES and the Companies are currently evaluating the impact of this FSP on their financial statements but it is not expected to have a material impact.

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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

The applicable registrant'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 applicable 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, 2007, 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.

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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

See Item 1A RISK FACTORS in Part I of the Form 10-K for the year ended December 31, 2006 for a discussion of the risk factors of FirstEnergy and the subsidiary registrants. For the quarter ended September 30, 2007, there have been no material changes to these risk factors.

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
	2007		2007		2007		Quarter
Total Number of Shares Purchased (a)	29,656		83,448		253,701		366,805
Average Price Paid per Share	$66.00		$62.95		$61.85		$62.44
Total Number of Shares Purchased
As Part of Publicly Announced Plans
or Programs (b)		-		-		-		-
Maximum Number (or Approximate Dollar
Value) of Shares that May Yet Be
Purchased Under the Plans or Programs		1,629,890		1,629,890		1,629,890		1,629,890

(a)

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

(b)

FirstEnergy publicly announced, on January 30, 2007, a plan to repurchase up to 16 million shares of its common stock through June 30, 2008. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock under this plan through an accelerated share repurchase program with an affiliate of Morgan Stanley and Co., Incorporated at an initial price of $62.63 per share.

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ITEM 6.         EXHIBITS

Exhibit         Number
FirstEnergy
	10.1		Amendment to Agreement for Engineering, Procurement and Construction of Air Quality Control Systems by and between FirstEnergy Generation Corp. and Bechtel Power Corporation dated September 14, 2007 (Form 8-K dated September 18, 2007)*
	10.2		FirstEnergy Corp. Executive Deferred Compensation Plan as amended September 18, 2007 (Form 8-K dated September 21, 2007)
	10.3		FirstEnergy Corp. Supplemental Executive Retirement Plan as amended September 18, 2007 (Form 8-K dated September 21, 2007)
	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
		12	Fixed charge ratios
		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
		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
		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
		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
		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
		12	Fixed charge ratios
		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
		4.1	Form of Pennsylvania Electric Company 6.05% Senior Notes due 2017 (incorporated by reference to a Form 8-K dated August 31, 2007)
		10.1	Registration Rights Agreement, dated as of August 30, 2007, among Pennsylvania Electric Company and Citigroup Global Markets Inc., Lehman Brothers Inc. and Scotia Capital (USA) Inc., as representatives of the several initial purchasers named in the Purchase Agreement (incorporated by reference to a Form 8-K dated August 31, 2007)
		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

* Confidential treatment has been requested for certain portions of the Exhibit. Omitted portions have been filed separately with the SEC.

Pursuant to reporting requirements of respective financings, FirstEnergy, FES, OE, 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.

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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.

October 31, 2007

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)

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EX-10.1

THIS EXHIBIT IS THE SUBJECT OF A CONFIDENTIAL TREATMENT REQUEST. THE CONFIDENTIAL INFORMATION HAS BEEN SO OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. IN PLACE OF SUCH OMITTED CONFIDENTIAL INFORMATION, "******" HAS BEEN INSERTED.

AMENDMENT TO EPC AGREEMENT

(W. H. Sammis Plant AQC Systems)

THIS AMENDMENT (“Amendment”) is entered into as of September __, 2007, by and between FirstEnergy Generation Corp. (“FirstEnergy”), and Bechtel Power Corporation (“Contractor”).  FirstEnergy and Contractor are sometimes referred to herein individually as a “Party” or collectively as the “Parties.”

R E C I T A L S:

A.       FirstEnergy and Contractor entered into General Terms and Conditions for Engineering, Procurement, and Construction of Air Quality Control (AQC) Systems, dated August 26, 2005 (the “EPC Agreement”), by which FirstEnergy has retained Contractor to engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions at FirstEnergy’s W. H. Sammis Plant.

B.      During the Development Phase of each Subproject, the Parties have mutually determined the Target Construction Cost, Work Scope, Guaranteed Final Completion Date, Project Schedule, and certain other issues with respect to such Subproject.  FirstEnergy has issued to Contractor a Notice to Proceed with full construction of the Subprojects, effective on the same date as this Amendment.

C.      In connection with the determinations made during the Development Phase and issuance of the Notice to Proceed, the Parties desire to amend the terms of the EPC Agreement as described below.  The EPC Agreement, as amended hereby, is referred to herein as the “Agreement.”

FOR GOOD AND VALUABLE CONSIDERATION, and intending to be legally bound, the Parties agree to amend the EPC Agreement as follows:

1.     Priority of Interpretation.  Section 1.3 of the EPC Agreement shall be deleted in its entirety, and the following inserted in its place:

 1.3           Priority.  The documents making up this Agreement are intended to be complementary and mutually explanatory of one another.  For the purposes of interpretation, the priority of the documents shall be in accordance with the following sequence:

  (A)           Purchase Order #45161617;

  (B)           these General Terms and Conditions;

  (C)           the Scope Book

  (D)           FirstEnergy’s Requirements;

  (E)           the Drawings and Specifications;

  (F)           any other documents forming a part of this Agreement.

As to any FirstEnergy’s Requirements issued after the date of this Amendment, the Parties acknowledge and agree (i) any such items shall only be issued by the individuals identified in the Parties’ Notice of Direction on Designated Representatives and Official Communications (TCM-GAM-00240, or any future amendment thereof) and further (ii) such items may qualify as an Owner-directed Change, to be evaluated for a Change Order in accordance with Section 8.1.

The latest dated amendment or Change Order shall take precedence over that part of the foregoing documents that it supersedes.  Either Party, upon becoming aware of any such conflict or variance, shall promptly notify the other Party in writing.

2.Subsurface Conditions.  The following shall be added as a new Section 8.2(A)(7) of the EPC Agreement:

  (7)           discovery at the Site of unknown: (A) subsurface natural conditions of an unusual nature, differing materially from those ordinarily encountered or generally recognized as inherent in work similar to the Project and from those subsurface natural conditions established by First Energy Reliable Information or the geotechnical survey reports included or referenced in the Scope Book; or (B) subsurface man-made conditions differing from those man-made conditions established by First Energy Information or the subsurface man-made conditions reports included or referenced in the Scope Book, provided Contractor has used Good Practices in investigating the Site; which materially affects Contractor’s direct cost to perform the Work under this Agreement or delays the time of performance of such Work.

3.Force Majeure.  The following shall be added as a new Section 9.1(C) of the EPC Agreement:

  9.1(C)     Force Majeure Granted under NSR Consent Decree for Labor Unavailability.  Notwithstanding the foregoing, if FirstEnergy is granted, by stipulation of the parties to the NSR Consent Decree or by final unappealable judgment of a court pursuant to the dispute resolution procedures of the NSR Consent Decree, an extension of deadlines for performance of FirstEnergy’s compliance requirements under the NSR Consent Decree, as a result of a force majeure event arising out of unavailability of labor, then Contractor shall be entitled to seek a similar extension of the Project Schedule (including the Guaranteed Final Completion Date) as a result of such labor unavailability circumstances as a Force Majeure Event under this Agreement.

                  If FirstEnergy elects to seek a claim for force majeure relief under the NSR Consent Decree, then Contractor agrees to provide reasonable assistance in presenting such claim.  FirstEnergy retains sole discretion over whether and how to seek force majeure relief under the NSR Consent Decree.

4.FE Vendors/Subcontractors.  The supply contracts described on Appendix A hereto  (entitled “FE Vendors”) will be contracted directly by FirstEnergy as FE Vendors.    If additional required supply scope is identified after the date hereof, FirstEnergy and Contractor will determine whether such suppliers will be FE Vendors or Subcontractors on a case-by-case basis in a manner consistent with the EPC Agreement and shall update Appendix A.

5.Automatic Assignment of Certain Subcontracts; Chimney Subcontract Default.

                          (A)           In addition to FirstEnergy’s right to request assignment of any Subcontract under Section 2.3(C) of the EPC Agreement, FirstEnergy hereby grants to Contractor the right to request assignment to FirstEnergy or its designee of the Subcontracts listed below (including all payment obligations) in the event of any termination or cancellation of the EPC Agreement.  FirstEnergy hereby prospectively accepts, and shall cause its designee(s) to accept, all such assignments.

25186-000-HC1-CP00-00001   (Piling)

25186-000-HC1-DB51-00001  (Chimney)

25186-000-POA-SS01-00001   (Structural Steel)

25186-000-POA-MD00-00001 (Duct - Dynasteel)

25186-000-POB-MD00-00001 (Duct - PSP)

2

                         (B)          To the extent that the Subcontractor defaults under Subcontract 25186-000-HC1-DB51-00001 (Chimney) (the “Chimney Subcontract”), FirstEnergy agrees that all amounts expended or incurred by Contractor (including any un-recovered backcharges or other un-recovered costs) in excess of the amount allocated to the Chimney Subcontract in the TCC , to address such Subcontractor default that would have been recoverable by Contractor under or pursuant to a payment and performance bond had such a bond been secured for the Chimney Subcontract, shall be the subject of a Change Order between the Parties that will increase the Target Construction Cost by the amounts so expended; provided Contractor shall pursue recovery of such amounts as may be recoverable from the associated Subcontractor; and further provided, the Change Order described above shall be only in the amount that is not recoverable from the Subcontractor or amounts recovered by First Energy that are not applied to reduce the Final Construction Cost.  FirstEnergy shall be subrogated to the rights of Contractor under the Chimney Subcontract to recover from the Subcontractor the amount of such excess cost.

6.Delineation of Subprojects.  The Project will be made up of three Subprojects:

                          (A)           Subproject #1 is comprised of Scrubber C (which serves the gas flow from Generating Units 1-4), including the ID booster fans serving Scrubber C.

                         (B)           Subproject #2 is comprised of either Scrubber A or Scrubber B, whichever is the first to achieve Final Completion (which serves an amount of gas flow equivalent to ½ of the gas flow from Generating Units 5, 6, and 7), excluding the ID booster fans serving Scrubber A and Scrubber B (provided however, notwithstanding the foregoing definition, sufficient ID fan capacity must be available to support Performance Testing of Subproject #2).

                         (C)          Subproject #3 is comprised of either Scrubber A or Scrubber B, whichever is the last to achieve Final Completion (which serves an amount of gas flow equivalent to ½ of the gas flow from Generating Units 5, 6, and 7), including the ID booster fans serving Scrubbers A and B, and all common facilities and equipment not included within Scrubbers A, B, and C.

For purposes of this Section, a “Scrubber” shall include the WFGD absorber tower, ID booster fans (except as noted above in the case of Subproject #2), ductwork, and other equipment and systems dedicated to that absorber tower.  A schematic of each Subproject is attached hereto as Appendix B.

7.Guaranteed Final Completion Date.  The Guaranteed Final Completion Date for Subproject #1 shall be September 1, 2010.  The Guaranteed Final Completion Date for Subproject #2 shall be October 31, 2010.  The Guaranteed Final Completion Date for Subproject #3 shall be November 15, 2010.

8.Target Construction Cost; Final Construction Cost; Fee.

                           (A)         The sixth paragraph of Exhibit 5.1 of the EPC Agreement shall be deleted in its entirety, and the following inserted in its place:

The "Target Construction Cost" of the Subprojects will include the Professional Construction Labor (and associated G&A and Engineering Technology Charge), Purchased Equipment and Materials, Fabricated Items, Freight, Craft Labor, Consumables, Major Equipment & Tool Rental, Temporary Facilities, Subcontractors, premiums for bonds and insurances as provided in the EPC Agreement, and taxes on Contractor’s construction equipment and Consumables.  The “Target Construction Cost” excludes Professional Engineering and Graphics labor and Other Professional labor (with the associated Engineering Technology Charge and G&A), travel and living expenses, Engineering Subcontracts, additional insurances or bonds other than those provided in the EPC Agreement, all FE Vendor costs (other than B&W costs) and all other taxes.  The Target Construction Cost shall be exclusive of any Fee.  The “Final Construction Cost” of the Subprojects shall be the aggregate amount of costs associated with the Target Construction Cost that, with respect to each Subproject, is actually incurred prior to Final Completion of that Subproject.

3

CONFIDENTIAL TREATMENT REQUESTED

                          (B)          The aggregate Target Construction Cost for Subprojects #1, #2, and #3 is provided in Appendix C-1.

                          (C)          The Target Construction Cost, the Final Construction Cost and the ultimate value of the earned Target Construction Cost Fee shall be administered and determined on an aggregate basis among all three Subprojects.  Therefore, any adjustments of the Target Construction Cost Fee as described in Exhibits 5.1 through 5.1-3 to the EPC Agreement shall be determined and made on an aggregate basis for Subprojects #1, #2, and #3, by comparing the aggregate Final Construction Cost for all three Subprojects to the aggregate Target Construction Cost for all three Subprojects.  All other Fees (the Engineering/Graphics & Other Professional & Specialists Labor Cost Fee and the Professional Construction (Field Non Manual Labor Fee)) shall also be administered and determined on an aggregate basis among all three Subprojects as described above.

                          (D)        For purposes of the liability cap described in Section 18.4 of the EPC Agreement, (i) the earned Fee associated with Subproject #1 shall be equal to [******%] of the  actual final value of the total earned Fees on the Project;  (ii) the earned Fee associated Subproject #2 shall be equal to [******%] of the actual final value of the total earned Fees on the Project; and (iii) the earned Fee associated with Subproject #3 shall be equal to [******%] of the actual final value of the total earned Fees on the Project.  The parties acknowledge and agree that the actual final value of the earned Fees associated with  the Project will be determined through a jointly conducted reconciliation of all applicable adjustments to the aggregate Fees that will be completed as promptly as practicable, and in no case later than ninety (90) Days, after all Subprojects have achieved Final Completion.  Upon completion of the foregoing reconciliation, the actual final value of the total earned Fees shall be allocated among Subprojects #1, #2, and #3 in accordance with the percentages provided in the first sentence hereof.  To the extent that the foregoing reconciliation results in any amount previously paid by Contractor on any Subproject being an overpayment in light of the value of the total earned Fee applicable to such Subproject, FirstEnergy shall reimburse to Contractor any such overpaid amounts as part of the next billing cycle.  Similarly, to the extent that the foregoing reconciliation results in any amount previously paid by Contractor on any Subproject being an underpayment in light of the value of the total earned Fee applicable to such Subproject, Contractor shall pay to FirstEnergy any such underpaid amounts as part of the next billing cycle.  A work sheet attached hereto as Appendix C-2 provides illustrative examples of how the earned Fee will be determined and apportioned in accordance with the process described above.

  9.Performance Tests.  Testing for Performance Guarantees shall be performed independently for Subprojects #1, #2, and #3.  Testing for the Reliability Standard shall be performed independently for Subprojects #1 and #3 and there shall be no Reliability Standard required to be tested or demonstrated with respect to Subproject #2.  The common systems will be tested in conjunction with the Reliability Test performed on Subproject #3, and must not cause the output of any Sammis Generating Unit to be restricted during the duration of the test.

               10.Schedule Liquidated Damages;  Final Document Delivery.  Exhibit 6.5 of the EPC Agreement shall be deleted in its entirety and replaced with the new form of Exhibit 6.5 attached hereto as Appendix D.

11.TCC Deadband.  Exhibit 5.1-3 of the EPC Agreement shall be deleted in its entirety and replaced with the new form of Exhibit 5.1-3 attached hereto as Appendix E.  The [******%] deadband below the Target Construction Cost shall be eliminated.

12.Additional Incentive.  FirstEnergy will pay to Contractor an “Additional Incentive Fee” in the amount of [$******] for each [$******] by which the final Overall Project Cost is below a fixed target amount of [$******] (the “Additional Incentive Target”).  The Additional Incentive Target is not subject to adjustment up or down for any reason whatsoever.  The “Overall Project Cost” is intended to be the total of all costs actually incurred by FirstEnergy in connection with the Project, and shall be equal to the total aggregate amount of the Final Construction Cost, plus the amount payable to Contractor for Engineering & Graphics Labor, Other Professional Labor, the Engineering Technology Charge associated with Engineering & Graphics Labor and Other Professional Labor, Engineering Subcontracts, Travel & Living Expenses, and G&A (each of the foregoing as described in Exhibit 5.1 of the EPC Agreement), plus all amounts payable to FE Vendors identified in Appendix A.

In addition, if Contractor loses its entitlement to earn any portion of the Target Construction Cost Fee due to an overrun of the Target Construction Cost, then the amount of the Additional Deadband Adjustment will be subtracted from the Final Construction Cost for purposes of determining adjustment of the Target Construction Cost Fee, as described in Exhibit 5.1-3.  The “Additional Deadband Adjustment” shall be the amount equal to the difference of: (a) [$******] minus (b) the Overall Project Cost less the Final Construction Cost.

4

CONFIDENTIAL TREATMENT REQUESTED

The actual final total value of the Overall Project Cost, the Additional Incentive Fee, and the Additional Deadband Adjustment shall be calculated as part of the reconciliation provided in Section 8(D) of this Amendment.  The Additional Incentive Fee shall be payable with the immediately following billing cycle.

13.          Schedules.  The Project Schedule and Critical Path Schedule referenced in Section 6.4 of the EPC Agreement, as recognized by the Parties as of the date of this Amendment,  is attached hereto as Appendix F.

14.         Additional Contract Clarifications.  For the avoidance of doubt, the Parties acknowledge that:

(A)Contractor is not liable for Performance Liquidated Damages or Schedule Liquidated Damages attributable to performance deficiencies or delays to the extent caused by a Subcontractor   (but is liable for Liquidated Damages to the extent such are assessable due to any Professional Services, and construction labor services provided as part of the Work except where such is provided by a Subcontractor supplying Materials or equipment).

(B)The cost of products and services supplied by Subcontractors are included in the Target Construction Cost, and the [******]% Target Construction Cost Fee applies to these items.  The cost of products and services supplied by Babcock & Wilcox as OEM under the Agreement for Flue Gas Desulfurization Systems dated August 25, 2006 (the “FGD Agreement”), are included in the Target Construction Cost (provided, if any change orders  to the FGD Agreement adjust the costs thereunder, such price adjustments shall be made (up or down) to the Target Construction Cost and the Parties shall memorialize a revision to the Target Construction Cost and the related [******%] Target Construction Cost Fee, which applies to this item).  The cost of products and services supplied by FE Vendors (other than costs paid to Babcock & Wilcox under the FGD Agreement) are not included in the Target Construction Cost, and the [******%] Target Construction Cost Fee does not apply to these items.  Notwithstanding the foregoing, costs paid to Babcock & Wilcox for the SO₃ control system are not included in the Target Construction Cost, and the [******%] Target Construction Cost Fee does not apply to this item.

(C)      FirstEnergy, Contractor, the FE Vendors, and the Subcontractors shall each have separate and independent obligations to achieve the key milestones assigned to any such Persons in accordance with the schedule and by the dates provided in the Project Schedule and the Critical Path Schedule for achievement thereof.  In addition, the Parties acknowledge and agree that the failure of B&W to achieve the milestones assigned to B&W described in Appendix G by the date set forth therein shall be considered a delay within the meaning of Section 9.2 of the EPC Agreement.

(D)For purposes of clarity, the Parties confirm that, as provided in Exhibit 5.1-3 and notwithstanding the description of the Professional Cost Fee on page 7 of Exhibit 5.1 of the EPC Agreement, Contractor’s [******%] Target Construction Cost Fee shall be the sole component of Contractor’s Fee that will be adjusted for variance from the Target Construction Cost.

(E)In allocating float as described in Section 6.4(A)(3) of the EPC Agreement, in the event that float associated with an activity is used and such usage delays the critical path of the Critical Path Schedule and materially affects Contractor’s ability to meet the Critical Path Schedule, the Parties will review in good faith the impacts resulting from such usage of float to ensure that each Party is treated fairly in consideration of the issue(s) that caused float to be used and in consideration of any efforts taken to mitigate the impacts.

15.        Work Scope; Scope Book.  Attachment A of the EPC Agreement shall be deleted in its entirety and replaced with the new form of Attachment A attached hereto as Appendix H.  The Scope Book referenced in Section 1 hereof is Document Number 25186-000-G80-GGG-00001-002, which document shall be updated as provided in Appendix I hereto.

16.         Design Coal.  Exhibit 7.2-1 of the EPC Agreement shall be deleted in its entirety; and the Parties agree that the Design Fuel range for purposes of the Performance Guarantees shall be as provided in the Design Fuel Specifications set forth in the Scope Book.

5

17.           Miscellaneous.

(A)Definitions;  Agreement in Full Force and Effect.  Capitalized terms used but not otherwise defined in this Amendment shall have the meanings given to such terms in the EPC Agreement.  Except as otherwise expressly modified hereby, the EPC Agreement remains in full force and effect, and the Parties hereby restate each and every term, condition, and agreement of the Parties as contained in the EPC Agreement as if fully written out herein.  The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of any party under the EPC Agreement, except as specifically set forth herein.

(B)Governing Law.  This Amendment shall be governed by and construed in accordance with the laws of the State of Ohio.

(C)Interpretation. The section and other headings in this Amendment are inserted solely as a matter of convenience and for reference, and shall be given no effect in the construction or interpretation of this Amendment.  Upon the effectiveness of this Amendment, each reference in the Agreement to “this Agreement,” “hereunder,” “hereof,” “herein,” “hereby” or words of like import shall mean and be a reference to the Agreement as amended hereby, and each reference to the Agreement in any other document, instrument or agreement executed and/or delivered in connection with the Agreement shall mean and be a reference to the Agreement as amended hereby.  When used herein, the words “include” and “including” shall be construed as “include, without limitation” and “including, without limitation.”  This Amendment has been freely negotiated by all Parties and in the event there is any controversy, dispute, or claim involving the meaning, interpretation, validity, or enforceability of this Amendment or any of its terms or conditions, there shall be no inference, presumption, or conclusion drawn against a Party by virtue of such Party having drafted this Amendment or any portion hereof.

(D)Execution and Counterparts.  This Amendment may be executed in multiple counterparts, which taken together shall constitute an original without the necessity of all parties signing the same page or the same documents, and may be executed by signatures to electronically or telephonically transmitted counterparts in lieu of original printed or photocopied documents.  Signatures transmitted by facsimile shall be considered original signatures.

IN WITNESS WHEREOF, the undersigned have caused this Amendment to be duly executed as of the date first written above.

FirstEnergy Generation Corp.
By:
	Richard R. Grigg, Executive Vice
	President and Chief Operating Officer
Bechtel Power Corporation
By:
	Robert L. Kasper, Jr.
	Principal Vice President

6

      

        Amendment to EPC Agreement      

        Appendix A      

    

Appendix A

EQUIPMENT AND MATERIALS PROVIDED BY FE VENDORS

Description

CIVIL / STRUCTURAL / ARCHITECTURAL

CIVIL / STRUCTURAL

Inspection of Deck over Route 7

MACHINERY

ROTATING EQUIPMENT

Booster Fans / ID Fans

ID Fan Centrifugal - Mods to Existing Fans (Rotor Replacement)

General Purpose Pumps (Water)

Fire Pumps / Jockey Pumps/ Water Pumps

Sump Pumps

WATER TREATMENT/PACKAGED SYSTEMS

Raw/Service Water Filtration System

Wastewater Treatment

MATERIAL HANDLING

Limestone and Gypsum Handling System

POWER GENERATION

SO3 Control System

Wet Scrubber FGD System

      

        Amendment to EPC Agreement      

        Appendix A      

    

ELECTRICAL

ELECTRICAL EQUIPMENT

Motor Control Centers < 1 kV  ANSI  and AC Distribution Panel

Elect  Equip  Module / Powerhouse - Building Only

Unit Substation < 1 kV - ANSI / Loadcenter 480 kV (Incl Trans.)

13.8 kV Switchgear - ANSI (Includes MCCs> 1 kV)

4160 V Switchgear - ANSI (Includes MCCs> 1 kV)

Cranking Transformer

Transformers, Power (Oil Filled, MV/MV)

Dry Type Transformer for double ended MCCs (DEMCCs)

Inverter, UPS Panel & Regulating Transformer, Batteries & Battery Chargers

and DC Switchboard

ELECTRICAL SWITCHYARD

High Voltage  Breakers  (Swyd - AIS)

HV Swyd Disconnect Switches (AIS)

HV Surge Arrestors

CONTROL SYSTEMS

CEMS

DCS

SPECIALTY CONTRACTS

Scaffold, Furnish & Install / Furnish Only

      

        Amendment to EPC Agreement      

        Appendix B      

    

Appendix B

[See Attached Appendix B]

      

        Amendment to EPC Agreement      

        Appendix C      

    

Appendix C-1

[See Attached Appendix C-1]

CONFIDENTIAL TREATMENT REQUESTED

Sammis Project, Job No. 25186-810, Rev. 7
Wet FGD Units 1-7
APPENDIX C - 1 (pg. 1)
Description	Material Cost	Labor Cost	S/C Cost	Total Cost	Total Hours
…………………………………………………………………	…………………	…………………	…………………	…………………	………………………
FGD System	[$******]	[$******]	[$******]	[$******]	[******]
FGD Ductwork	[$******]	[$******]	[$******]	[$******]	[******]
Material Handling	[$******]	[$******]	[$******]	[$******]	[******]
Water Treatment & Tanks	[$******]	[$******]	[$******]	[$******]	[******]
Chimney	[$******]	[$******]	[$******]	[$******]	[******]
Rotating Equipment	[$******]	[$******]	[$******]	[$******]	[******]
Other Mechanical Equipment	[$******]	[$******]	[$******]	[$******]	[******]
Electrical Equipment	[$******]	[$******]	[$******]	[$******]	[******]
T-Lines & Switchyard	[$******]	[$******]	[$******]	[$******]	[******]
Site Work	[$******]	[$******]	[$******]	[$******]	[******]
Concrete Related	[$******]	[$******]	[$******]	[$******]	[******]
Steel Work & Other Structural	[$******]	[$******]	[$******]	[$******]	[******]
Architectural	[$******]	[$******]	[$******]	[$******]	[******]
Piping Bulks	[$******]	[$******]	[$******]	[$******]	[******]
Painting & Insulation	[$******]	[$******]	[$******]	[$******]	[******]
Electrical Bulks	[$******]	[$******]	[$******]	[$******]	[******]
Instrumentation	[$******]	[$******]	[$******]	[$******]	[******]
Demolition only	[$******]	[$******]	[$******]	[$******]	[******]
Demolition and Relocation	[$******]	[$******]	[$******]	[$******]	[******]
Milestone Incentives (Craft/SCs/FE Personnel)	[$******]	[$******]	[$******]	[$******]	[******]
Tie-ins (Units 1-7)	[$******]	[$******]	[$******]	[$******]	[******]
Traffic & Logistics	[$******]	[$******]	[$******]	[$******]	[******]
To-Go Escalation - Direct Costs	[$******]	[$******]	[$******]	[$******]	[******]
Unidentified Trends	[$******]	[$******]	[$******]	[$******]	[******]
………………………………………………………………R 30;	…………………	…………………	…………………	…………………	………………………
Total Direct Costs	[$******]	[$****[$******]	[$**[$******]	[$******]	[******]
Temp Facilities	[$******]	[$******]	[$******]	[$******]	[******]
Misc Services	[$******]	[$******]	[$******]	[$******]	[******]
Equipment, Tools & Supplies	[$******]	[$******]	[$******]	[$******]	[******]
Small Tools	[$******]	[$******]	[$******]	[$******]	[******]
Consumables	[$******]	[$******]	[$******]	[$******]	[******]
Startup Manual Personnel	[$******]	[$******]	[$******]	[$******]	[******]
To-Go Escalation - Field Indirects	[$******]	[$******]	[$******]	[$******]	[******]
………………………………………………………………R 30;	…………………	…………………	…………………	…………………	………………………
Total Field Indirect Costs	[$******]	[$*[$******]	[$******]	[$******]	[******]
FNM - Construction	[$******]	[$******]	[$******]	[$******]	[******]
SU NM	[$******]	[$******]	[$******]	[$******]	[******]
To-Go Escalation - Field Services	[$******]	[$******]	[$******]	[$******]	[******]
Other Billable Costs - Travel, Relo, Computers, SCs, etc	[$******]	[$******]	[$******]	[$******]	[******]
………………………………………………………………R 30;	…………………	…………………	…………………	………………………	……………………………
Total Field Services	[$******]	[$******]	[$******]	[$******]	[******]
TOTAL CONSTRUCTED COST	[$******]	[$*[$******]	[$******]	[$*[$******]
Securities - Bond for Highway 7 Repairs due to Barge offloading				[$******]
Project Insurance: Builders Risk - By FE; Marine Cargo & Liability @ [$******]				[$******]
Warranty Engr				[$******]
Other Becthel Costs: Bldg Inspections @ $******], Sales Tax for Construction Equip @ [$******]				[$******]
To-Go Escalation - Other				[$******]
………………………………………………………………R 30;	…………………	…………………	…………………	………………………
TOTAL OTHER COST				[$******]
Contingency	[******]%	of Total Cost		[$******]
………………………………………………………………R 30;	…………………	…………………	…………………	…………………
TOTAL COST WITH CONTINGENCY				[$[$******]
G&A rate - Prof. Construction Labor	[******]%	of FNM/SUNM Labor Cost		[$******]
Fee - Prof. Construction Labor	[******]%	of FNM/SUNM Labor Cost		[$******]
Fee - Target Construction Costs	[******]%	of Construction Costs		[$******]
………………………………………………………………R 30;	…………………	…………………	…………………	…………………
TARGET CONSTRUCTION COST				[$[$******]

Appendix C-1 pg. 1

CONFIDENTIAL TREATMENT REQUESTED

 

Sammis Project, Job No. 25186-810, Rev. 7
COST AND FEES NOT INCLUDED IN TCC
APPENDIX C - 1 (pg. 2)
Description	Material Cost	Labor Cost	S/C Cost	Total Cost	Total Hours
……………………………………………………………… ……	…………………	…………………	…………………	……………………	…………………
Engineering	[$******]	[$******]	[$******]	[$******]	[******]
Other Home Office	[$******]	[$******]	[$******]	[$******]	[******]
Nexant/GSG	[$******]	[$******]	[$******]	[$******]	[******]
To-Go Escalation - HO Services	[$******]	[$******]	[$******]	[$******]	[******]
Other Billable Costs - Travel, Relo, SCs, etc	[$******]	[$******]	[$******]	[$******]	[******]
……………………………………………………………… ……	…………………	…………………	…………………	……………………	…………………
Contingency	[******]%	of Total Cost		[$******]
G&A rate - Engr/Other Prof. Labor	[******]%	of Engr/OHO Labor Cost		[$******]
………………………………………………………………… …	…………………	…………………	…………………	……………………
TOTAL ENGR/OTHER PROFESSIONAL LABOR				[$[$******]
Wet FGD Units 1-7
OTHER NON TCC COMPONENTS
Description	Material Cost	Labor Cost	S/C Cost	Total cost
……………………………………………………………… ……	…………………	…………………	…………………	……………………
Securities - Bond for Highway 7 Repairs due to Barge offloading				[$******]
Project Insurance: Builders Risk - By FE; Marine Cargo & Liability @ [$******]				[$******]
FE Vendor Materials including Escalation				[$******]
……………………………………………………………… ……	…………………	…………………	…………………	……………………
TOTAL  - NON TCC COMPONENTS				[$******]
SUB-TOTAL - OVERALL PROJECT COST				[$******]
Wet FGD Units 1-7
FEE COMPONENTS
Fee - Engr/Other Prof. Labor				[$******]
Fee - Prof. Construction Labor				[$******]
Fee - Target Construction Costs				[$******]
……………………………………………………………… ……	…………………	…………………	…………………	……………………
TOTAL FEES				[$*[$******]
TOTAL PROJECT PRICE				[$*[$******]

Appendix C-1 pg. 2

      

        Amendment to EPC Agreement      

        Appendix C      

    

Appendix C-2

[See Attached Appendix C-2]

CONFIDENTIAL TREATMENT REQUESTED

Sammis Project
Subproject Fee Estimated Allocation at time of Notice to Proceed
FEE Status
Units 1-4	Base	Alloc. of 1-7	Total
Initial Value of TCC Fee	[$******]	[$******]	[$******]
Initial Value of HO Fee (Allocated per 12/06 est.)	[$******]	[$******]	[$******]
Initial Value of FNM Fee	[$******]	[$******]	[$******]
Initial Value of Subproject 1 Fees	[$******]	[$******]	[$******]	[******]%
Units 5-7	Base	Alloc. of 1-7	Total
Initial Value of TCC Fee	[$******]	[$******]	[$******]
Initial Value of HO Fee (Allocated per 12/06 est.)	[$******]	[$******]	[$******]
Initial Value of FNM Fee	[$******]	[$******]	[$******]
Initial Value of Subproject 2 Fees	[$******]	[$******]	[$******]	[******]%
Units 5-7		Alloc. of 1-7	Total
Initial Value of TCC Fee	[$******]	[$******]	[$******]
Initial Value of HO Fee (Allocated per 12/06 est.)	[$******]	[$******]	[$******]
Initial Value of FNM Fee	[$******]	[$******]	[$******]
Initial Value of Subproject 3 Fees	[$******]	[$******]	[$******]	[******]%
Units 1-7 Common
Direct and Distribs (Exc. FE Vendor)	[$******]
HO FEE	[$******]
FNM FEE	[$******]
Initial Value of Common Systems Fees (To be Allocated to Subprojects 1 and 3 only as shown above)	[$******]
Initial aggregate value of Fees			[$******]

CONFIDENTIAL TREATMENT REQUESTED

Scenario #1
Basis of this example is TCC overrun of [$******] on an assumed
TCC value of [$******]. No schedule slippage.  ( Assumes no subtraction of Additional Deadband Adjustment from the Final Construction Cost ) *
A	TCC Value	[$******]
B	TCC Overrun	[$******]
C	% of Overrun (B / A)	[******]%
D	Adjustment per table Exhibit 5.1-3 Fee Table	[******]%
E	Unadjusted Total TCC Fee (Direct and Distribs)	[******]%
F	% reduction of TCC Fee (D / E)	[******]%
G	Fee at Risk for Cost Overrun ([******]% TCC Fee)	[$******]
H	TCC Fee adjustment (F * G)	[$******]
I	Aggregate Earned TCC Fee	[$******]
	Reallocation of Earned Fee (fee at risk)
	Subproject 1
	Earned TCC Fee (I * [******]%)	[$******]
	Earned HO Fee	[$******]
	Earned FNM Fee	[$******]
	Earned Fee (fee at risk) for Subproject 1	[$******]
	Subproject 2
	Earned TCC Fee (I * [******]%)	[$******]
	Earned HO Fee	[$******]
	Earned FNM Fee	[$******]
	Earned Fee (fee at risk) for Subproject 2	[$******]
	Subproject 3
	Earned TCC Fee (I * [******]%)	[$******]
	Earned HO Fee	[$******]
	Earned FNM Fee	[$******]
	Earned Fee (fee at risk) for Subproject 3	[$******]
	Final Aggregate Earned Fee	[$******]

 * Non-TCC underruns can be used to offset TCC Overruns as provided in Secion 12 of the Amendment.

CONFIDENTIAL TREATMENT REQUESTED

 

Scenario #2
Basis is TCC overrun of [$******] on a TCC value of [$******] with a 3 day slip on
Subproject 1, HO underrun in hours, and HO scorecard adjustment of [$******]. (Assumes no subtraction of additional Deadband Adjustment from the Final Construction Cost.)  *
A	TCC Value	[$******]
B	TCC Overrun	[$******]
C	% of Overrun (B / A)	[******]%
D	Adjustment per table	[******]%
E	Unadjusted Total TCC Fee	[******]%
F	% reduction of TCC Fee (D / E)	[******]%
	HO FEE adjustment
	Base HO Fee (Base is [$******]k - [$******]k for reduced hours expended=[$******] adjusted Fee )	[$******]
	Scorecard calc increase of [$******] in HO Fee	[$******]
	Final HO Fee	[$******]
	FC occurs 3 days later than Subproject 1 GFCD date of 9/1/2010	[******]
	Identified LD rate	[$******]
	Total Earned Fee deducted from Subproject 1	[$******]
	Final Earned Fee values by subproject
	Subproject 1:
	Unadjusted Earned Fee	[$******]
	Adjustment for TCC overrun	[$******]
	HO Earned Fee Adjustment for Scorecard ([******]% of $******])	[$******]
	HO Earned Fee Adjustment for Reduced Manhours ([******]% of $******])	[$******]
	Liquidated Damages	[$******]
	Subproject 1 (Earned Fee adjusted for TCC Overrun, Schedule LD above and [******]% of HO Fee adjustment)	[$******]
	Subproject 2 (Earned Fee adjusted [******]% of HO Fee adjustment)	[$******]
	Subproject 3 (Earned Fee adjusted [******]% of HO Fee adjustment)	[$******]
	Final Aggregate Earned Fee	[$******]

 * Non-TCC underruns can be used to offset TCC Overruns as provided in Secion 12 of the Amendment.

      

        Amendment to EPC Agreement      

        Appendix D – Amended Exhibit 6.5      

    

CONFIDENTIAL TREATMENT REQUESTED

Appendix D

Amended Exhibit 6.5

SCHEDULE LIQUIDATED DAMAGES

Subproject #1:

With respect to Subproject #1 (defined in Section 6 of the Amendment), for each day after such Subproject’s Guaranteed Final Completion Date, but prior to December 31, 2010 (the “NSR Consent Decree Date”), that Final Completion is delayed for such Subproject, but only for that portion of such delay caused by the Contractor, the Contractor shall pay FirstEnergy as Liquidated Damages [$******] for each day of delay. For each day after the NSR Consent Decree Date that the Final Completion of Subproject #1 is delayed, but only for that portion of such delay caused by the Contractor, the Contractor shall pay FirstEnergy as Liquidated Damages, calculated on a daily basis, an amount equal to the greater of:  (a) [$******] for each day of delay, or (b) [$******] for each megawatt hour by which any affected Generating Unit(s) in the subject Subproject operates below its full NDC (defined in Exhibit 7.2) as a result of the event(s) or condition(s) causing, or efforts undertaken to cure, the failure to achieve Final Completion, but not to exceed [$******] per day of delay for such Subproject.

Notwithstanding the foregoing, from the time that all elements of Final Completion have been met other than achievement of the Reliability Standard, Contractor shall pay FirstEnergy as Liquidated Damages for delay in achieving the Reliability Standard after the Guaranteed Final Completion Date for Subproject #1 an amount equal to [$******] for each megawatt hour by which any affected Generating Unit(s) in the subject Subproject operates below its full NDC (defined in Exhibit 7.2) as a result of the event(s) or condition(s) causing, or efforts undertaken to cure, the failure to achieve the Reliability Standard, but only for that portion of such megawatt hour reduction caused by the Contractor, such amount not to exceed [$******] per day for such Subproject prior to the NSR Consent Decree Date and [$******] per day for such Subproject after the NSR Consent Decree Date.

For the avoidance of doubt, and without limiting other reasons therefor, for purposes of the two preceding paragraphs, a Generating Unit shall be considered to be operating below its full NDC if the terms of the NSR Consent Decree regarding emission reduction and control requirements or other Applicable Law prohibit operation of the Generating Unit at its full NDC.

Subproject #2:

With respect to Subproject #2 (defined in Section 6 of the Amendment), for each day after such Subproject’s Guaranteed Final Completion Date, but prior to the NSR Consent Decree Date, that Final Completion is delayed, but only for that portion of such delay caused by the Contractor, the Contractor shall pay FirstEnergy as Liquidated Damages [$******] for each day of delay.  For each day after the NSR Consent Decree Date that the Final Completion of Subproject #2 is delayed, but only for that portion of such delay caused by the Contractor, the Contractor shall pay FirstEnergy as Liquidated Damages, calculated on a daily basis, an amount equal to the greater of:  (a) [$******] for each day of delay, or (b) [$******] for each megawatt hour by which any affected Generating Unit(s) in the subject Subproject operates below its full NDC (defined in Exhibit 7.2) as a result of the event(s) or condition(s) causing, or efforts undertaken to cure, the failure to achieve Final Completion, but not to exceed [$******] per day of delay for such Subproject.

For the avoidance of doubt, and without limiting other reasons therefor, for purposes of the preceding paragraph, a Generating Unit shall be considered to be operating below its full NDC if the terms of the NSR Consent Decree regarding emission reduction and control requirements or other Applicable Law prohibit operation of the Generating Unit at its full NDC.

      

        Amendment to EPC Agreement      

        Appendix D – Amended Exhibit 6.5      

    

CONFIDENTIAL TREATMENT REQUESTED

Subproject #3:

With respect to Subproject #3 (defined in Section 6 of the Amendment), for each day after such Subproject’s Guaranteed Final Completion Date, but prior to the Adjusted NSR Consent Decree Date, that Final Completion is delayed for such Subproject, but only for that portion of such delay caused by the Contractor, the Contractor shall pay FirstEnergy as Liquidated Damages [$******] for each day of delay. For each day after the Adjusted NSR Consent Decree Date that the Final Completion of Subproject #3 is delayed, but only for that portion of such delay caused by the Contractor, the Contractor shall pay FirstEnergy as Liquidated Damages, calculated on a daily basis, an amount equal to the greater of:  (a) [$******] for each day of delay, or (b) [$******] for each megawatt hour by which any affected Generating Unit(s) in the subject Subproject operates below its full NDC (defined in Exhibit 7.2) as a result of the event(s) or condition(s) causing, or efforts undertaken to cure, the failure to achieve Final Completion, but not to exceed [$******] per day of delay for such Subproject.

Notwithstanding the foregoing, from the time that all elements of Final Completion have been met other than achievement of the Reliability Standard, Contractor shall pay FirstEnergy as Liquidated Damages for delay in achieving the Reliability Standard after the Guaranteed Final Completion Date for Subproject #3 an amount equal to [$******] for each megawatt hour by which any affected Generating Unit(s) in the subject Subproject operate below their full NDC (defined in Exhibit 7.2) as a result of the event(s) or condition(s) causing, or efforts undertaken to cure, the failure to achieve the Reliability Standard, but only for that portion of such megawatt hour reduction caused by the Contractor; such amount not to exceed [$******] per day for such Subproject prior to the Adjusted NSR Consent Decree Date and [$******] per day for such Subproject after the Adjusted NSR Consent Decree Date.

For purposes of this Section, the “Adjusted NSR Consent Decree Date” shall be the earlier of (A) the date that is forty-five (45) days after the Guaranteed Final Completion Date for Subproject #3 (as adjusted for any Change Order issued in response to any of the occurrences described in Sections 8.1 or 8.2 of the EPC Agreement); and (B) February 15, 2011.

For the avoidance of doubt, and without limiting other reasons therefor, for purposes of the first two paragraphs under “Subproject 3”, a Generating Unit shall be considered to be operating below its full NDC if the terms of the NSR Consent Decree regarding emission reduction and control requirements or other Applicable Law prohibit operation of the Generating Unit at its full NDC.

All Subprojects:

In addition, with respect to any AQC Unit, for each Outage Day (defined in Exhibit 7.2) beyond 16 days the Contractor uses during the Corrective Action Period (defined in Exhibit 7.2), the Contractor shall pay FirstEnergy as liquidated damages, but only for that portion of such Outage Days caused by the Contractor, [$******] for each megawatt of NDC on the affected Generating Unit for each Outage Day (e.g. for the 300 MW Sammis Unit 5, the rate would be [$******] for each additional Outage Day).

In addition, with respect to each Subproject, in the event that Final Document Delivery has not been achieved by the date that Final Completion is achieved (or in the case of the documentation described below, within 90 days after Final Completion), Contractor shall pay FirstEnergy as Liquidated Damages [$******] per day until Final Document Delivery occurs.

·   As built and final record turnover of Bechtel or Subcontractor documents defined in Section 2.9 and Appendix D of the Scope Book, which were issued, or had change documents issued against them, within 120 days prior to the date Final Completion is or was achieved.

·   Documents including certain discrete data (e.g., emissions and fuel analyses) that must be verified, if required, through the use of third-party laboratories.  (With respect to such circumstances, data measured at the Facility using installed systems and other testing apparatus brought to the Facility will be used to determine the test results for Final Completion.  All reasonable efforts would then be made to submit the final report within 60 calendar days after Final Completion).

·   Final Lien Releases of Purchase Orders and Subcontracts as required.

      

        Amendment to EPC Agreement      

        Appendix E – Amended Exhibit 5.1-3      

    

CONFIDENTIAL TREATMENT REQUESTED

Appendix E

Amended Exhibit 5.1-3

FEE TABLE

The Fee associated with the Target Construction Cost will be adjusted according to the table below:

Final Construction Cost	FE Vendor Arrangement Free Adjustment
(% of Target Construction Cost)	(% of Target Construction Cost)
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
¦                  [******%]	[******%]
¦                  [******%]	[******%]
Deadband          [******%]	[******%]
¦                  [******%]	[******%]
¦                  [******%]	[******%]
¦                  [******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]
[******%]	[******%]

The maximum [******] adjustment is equal to the original Target Construction Cost Fee.

Values on the table shall be interpolated for actual costs between those shown on the table.

      

        Amendment to EPC Agreement       

        Appendix F      

    

Appendix F

Project Schedule; Critical Path Schedule

[See attached electronic media containing Project Schedule and Critical Path Schedule — data date of August 27, 2007;  backup date of September 4, 2007]

The attached disclosure respresents a comprehensive summary and compilation of all the material terms of Appendix F.

      

        Amendment to EPC Agreement      

        Appendix G      

    

Appendix G

FE Vendor Critical Milestones

Company	Event	Schedule Date
The Babcock & Wilcox Company	Set first absorber ring on its final foundation	April 11, 2008
	Late Finish, final absorber shell complete	March 30, 2009
	Pre-Mechanical Completion #1	February 1, 2009
	Pre-Mechanical Completion #2	July 21, 2009
	B&W Guaranteed Performance Final Completion (#1)	April 23, 2010
	B&W Guaranteed Performance Final Completion (#2)	August 26, 2010

      

        Amendment to EPC Agreement      

        Appendix H – Amended Attachment A      

    

Appendix H

Amended Attachment A

1.0       PLANT/UNIT DESCRIPTIONS

1.1   The 2,220 MW Sammis Plant is located in Stratton, OH and is made up of 7 generating units that draw cooling water from the Ohio River.

1.1.1   Units 1-4 are 180 MW single reheat, sub-critical drum units placed in service in the years 1959 though 1962 respectively.  The Foster Wheeler P.C. boilers generate 1,250,000 lbs./hr. of 2450 psig, 1050°F main steam (1000°F reheat).

1.1.2   Unit 5 is a 300 MW sub-critical, once-through unit placed in service in 1967.  The Babcock and Wilcox coal fired, single reheat boiler generates 2,355,000 lbs./hr. of 2625 psig, 1005°F main steam (1005°F reheat).

1.1.3   Units 6 and 7 are 600 MW super-critical, once-through units placed in service in 1969 and 1971 respectively.  The Babcock and Wilcox coal fired, single reheat boilers generate 4,628,000 lbs./hr. of 3785 psig, 1005°F main steam and 3,900,000 lbs/hr. of 654 psig, 1005°F reheat steam.  Both Units will be up-rated to 650 MW within a year of the FGD system startups.

1.2   AE-Constructor Work Scope

1.2.1   During the Development Phase, the Parties will work to develop a detailed Project work scope that will include, but not necessarily be limited to, the following:

·     Project Management

·       Prepare Project Execution Plan document

·       Support technology application decisions

·       Support FGD OEM selection

·       Establish Project performance parameters

·       Complete site evaluations and layouts

·       Constructability reviews

·       Complete Project design basis

·       Prepare estimating documents

·       Prepare cost estimate

·       Support permitting process

·       Support reagent supply discussions

·       Detailed engineering

·       Procurement

·       Construction

·       Checkout, Startup & Commissioning

·       Training

·       Documentation

·       Performance testing

·       Security

      

        Amendment to EPC Agreement      

        Appendix H – Amended Attachment A      

    

2.0       EXECUTION OF THE WORKSCOPE

The AE-Constructor will be expected to execute the Project (engineering, design, fabrication, procurement, construction, startup and commissioning) in an open, collaborative and safe manner resulting in the most competitive overall cost (construction and future O&M) and optimal performance of the air quality control systems.  This objective will be accomplished by meeting the following goals:

·   Mutually developing Project designs to minimize construction costs and future O&M costs while ensuring the highest overall operational reliability.

·   Each stakeholder being responsive to the needs of the other parties to insure actions and decisions are made in a manner consistent with all Project goals.

·   The AE-Constructor will be expected to develop, evaluate and report Project information as close to real time as practical, insuring actions necessary to address safety, design, cost and scheduling issues are implemented promptly upon recognition.

2.1   Project Management

2.1.1   The AE-Constructor will be responsible for all Project Management related to the Project including management of all Subcontractors, FE Vendors and the OEM.

2.2   Prepare Project Execution Plan

2.2.1   The AE-Constructor will work with the FirstEnergy Project team to develop an overall Project Execution Plan.  The plan will establish a Project Team and organization chart as well as project controls including:

2.2.1.1   Owner releases - FirstEnergy will be integrally involved in all areas and Phases of the Project and therefore will require a review process be established that gives adequate time for that review without unduly affecting the Project schedule.

2.2.1.2   Status reporting requirements - FirstEnergy will require access to Project progress information including schedule, budget, significant issues and work completed on a continuous basis through a web based electronic platform.  FirstEnergy requires the Contractor establish a system that allows as close to real time updates as possible.

2.2.1.3   Invoicing - Invoicing and payment will be by electronic means (including submittal of timesheets).

2.2.1.4   Payment procedures - payment will be made based on FirstEnergy verification of AE-Constructor expenses and supporting documentation.

2.2.1.5   Changes to scope - FirstEnergy will require access to estimates, including schedule impacts, and scope change descriptions as part of an approval process for changes to scope for both the AE-Constructor & it's Subcontractors as well as the OEM.

2.2.1.6   Design review - FirstEnergy will perform a detailed, ongoing design review during all Phases of the Project.  The AE-Constructor should be prepared to support FirstEnergy technical and support staff in the AE-Constructor's offices during the design portion of each Subproject.  Such review will include Subcontractor design efforts, where applicable.

2.2.1.7   Design practices - the AE-Constructor will be required to submit the Engineering Procedures Manual and Project specific criteria documents for FE review.  In addition, Contractor shall provide, as requested by FirstEnergy, access to their design practices on Contractor’s premises.  Final drawings must be provided per the requirements listed in this specification.

      

        Amendment to EPC Agreement      

        Appendix H – Amended Attachment A      

    

2.2.1.8   Communications - FirstEnergy prefers the implementation of a centralized, web based document control system.  The system will provide real-time access to the Project Team (AE-Constructor, OEM and FirstEnergy) to key Project documents.

2.2.1.9   Document control - FirstEnergy utilizes FileNet P8 3.0 as a document storage system.  The AE-Constructor will be required to maintain a complete set of all permits, design documents, O&M manuals, drawings, bid documents, correspondence and reports as part of the official Project file.  Once the Project is complete, the documents are to be provided to FirstEnergy in native format if electronic.  If they are non-CAD drawings they shall be provided as .tif images and if they are scanned documents, they shall be provided as .pdf documents format.

2.2.1.10   Procurement and Subcontracting procedures - FirstEnergy will require a competitive process which may include electronic reverse auctions, for selecting Subcontractors, equipment suppliers, tools, rentals and service suppliers to obtain the lowest life cycle cost for the Project.  The procedure must include FirstEnergy review and release steps.  The Procurement and Subcontracting procedures should allow for exceptions when bidders are limited.

2.2.1.11   Safety programs - The AE-Constructor is expected to utilize "world class" site/Project specific safety programs, practices and procedures and enforce them across the site. While zero (0) safety incidents is the goal for this Project, the Safety Program should result in an OSHA recordable IR rate <3.0 for non-manual and field labor.  The program should address site housekeeping as a method of improving safety.  FirstEnergy will review and release the AE-Constructor's safety program which must be consistent with Exhibit 3.5 (E)–1, Contractor Safety Guide, Air Quality Compliance.

In addition, the AE-Constructor must administer and enforce a Drug and Alcohol Testing Program consistent with the attached FirstEnergy Generation Corp. Substance Abuse Testing Program (See Exhibit 3.4 (D)) and meet the requirements of Exhibits 3.8 (E)-1, 3.8 (E)-2, 3.8 (E)-3 & 3.5 (E)-2 dealing with Asbestos, Inorganic Arsenic, Lead and OSHA Compliance.

2.2.1.12   Quality assurance - FirstEnergy expects the Project to be completed with a high degree of quality.  The AE-Constructor will have FirstEnergy reviewed and approved quality assurance programs in place for both field and shop work.  In addition, the AE-Constructor will be expected to monitor and track the quality of major equipment as it is fabricated in the various Vendors' shops.  FirstEnergy is to be notified of all significant inspections and may participate, as FirstEnergy deems necessary.  In any case, all quality program reports will be provided to FirstEnergy.

2.2.1.13   Scheduling - Scheduling is to be done in an electronic format (Primavera) and is to be made available to FirstEnergy electronically in native format.  FirstEnergy requires all schedules, including those provided by Subcontractors, be in Primavera.  In any case, the Primavera integrated master schedule shall be kept by the AE-Constructor and will include all activities required to complete the Project regardless of the responsible party (AE-Constructor, FirstEnergy, OEM, Subcontractor, equipment supplier, etc.) or the form in which the individual schedules are provided.

      

        Amendment to EPC Agreement      

        Appendix H – Amended Attachment A      

    

2.2.1.14   Estimating - All estimates will be completed using accepted estimating practices common to the industry.  The basis for all labor rates, equipment prices, indices, adjustments, contingencies, labor-hour quantities, ratios etc. will be provided and stated clearly in the estimate.  FirstEnergy will be provided access to the method of calculation and the Project specific data used in the creation of any such estimates.  FirstEnergy will review and release all estimates.

2.3   Complete site evaluations and layouts

2.3.1   The AE-Constructor will be required to review the Sammis site for interferences, construction issues and existing undergrounds.  From that review, the AE-Constructor will work with FirstEnergy to develop layout options, taking into account the potential configurations and the timing for their application.  The various options will then be evaluated jointly by the AE-Constructor and FirstEnergy.

2.4   Complete Project design basis

2.4.1   The AE-Constructor will work with the FirstEnergy Project team and Sammis Plant operations personnel to develop a Project design basis.

2.4.2   The AE-Constructor will perform optimization studies, as directed by FirstEnergy.

2.5   Prepare estimating documents

2.5.1   The estimating documents will include site layouts, design basis documents, mass & energy balances, process flow diagrams, piping and instrumentation diagrams, Vendor quotes for major equipment, material estimates, detailed local labor surveys and Subcontractor estimates.

2.5.2   The level and detail of estimating documents that will be prepared in advance will be based upon FirstEnergy’s desired estimate accuracy for a given Subproject.

2.6   Prepare cost estimate

2.6.1   The Project estimate will be a collaborative effort between FirstEnergy, the AE-Constructor and the OEM and will be prepared in an "open book" manner.  All of the estimating documents will be available to each of the parties for review and for their use in preparing their own portion of the estimate as well as to come to their own conclusions as to the accuracy of the overall estimate.

2.6.2   FirstEnergy reserves the right to retain the services of a mutually acceptable third party to review the estimates.  All of the materials provided to FirstEnergy will be provided to the third party.

2.6.3   It is FirstEnergy’s expectation that there will be “continuous improvement” in the design/engineering and construction of the series of AQC Systems to be installed.  This “continuous improvement” should be reflected in all aspects of the Subprojects including pricing, schedule, final quality and safety.

      

        Amendment to EPC Agreement      

        Appendix H – Amended Attachment A      

    

2.7   Support Permitting Process

2.7.1   The AE-Constructor will establish a Permit list.  This list will include all permits required to construct and operate the proposed facilities, the responsible party, permitting duration, applicable permitting agency as well as what activities are dependent on the permit.

2.7.2   The AE-Constructor is to include all the necessary permitting activities in the project schedule.

2.7.3   The AE-Constructor will be responsible for obtaining all of the construction permits.

2.7.4   The AE-Constructor will work with FirstEnergy to develop an environmental permitting strategy and will be responsible for managing the environmental permitting process, the creation and submission of all permit applications and providing responses to information requests from the agencies as required.  The permits will be obtained in the name of FirstEnergy and FirstEnergy will be the official interface for the project with the permitting agencies.

2.8   Support reagent supply discussions

2.8.1   The AE-Constructor will be required to provide input and be present at times for reagent supply discussions that pertain to the quality, quantity, form and delivery of reagent.

2.8.2   The AE-Constructor will provide input on the effect of various reagents on the process performance and its cost effectiveness as well as its impact on design and operating parameters.

2.9   Detailed engineering

2.9.1   The AE-Constructor will prepare working drawings and specifications setting forth in detail the requirements for the construction of the Project.  The design and engineering documents shall include all drawings, specifications schedules, diagrams and plans and such content and detail as is necessary to obtain required permits and governmental approvals and to properly complete the construction of the Project.  The working drawings and specifications shall include information customarily necessary for the use of such documents by those in the building trades. Design drawings in the following categories are typically provided for Owner review:

·   Site Grading/Roadway Drawings

·   Logic Diagrams, Instrument Control Diagrams, Panel Layout Drawings

·   Single Line Diagrams, Control Schematic Diagrams

·   Piping and Instrument Diagrams, System Descriptions, Piping Class Sheets

·   General Arrangement Drawings

·   Major Equipment Specifications, Design Criteria Documents

A specific list of the design and engineering documents to be reviewed and released by FirstEnergy will be created during the Project Development Phase.

2.9.2   The Design and engineering documents must meet the requirements of applicable laws including Professional Certifications (e.g. Engineer stamps, etc.) as required.

      

        Amendment to EPC Agreement      

        Appendix H – Amended Attachment A      

    

2.10  Procurement

2.10.1   FirstEnergy reserves the right to purchase equipment and materials for the Project directly.

2.10.2   The AE-Constructor will be responsible for issuing purchase orders for all equipment and material in the AE-Constructor's scope of procurement.  The AE-Constructor will be responsible for material control and handling of all equipment and materials purchased including any directly purchased by FirstEnergy.  FirstEnergy will have direct input on the review and final selection of Vendors and equipment suppliers and on the type and quality of the equipment to be purchased for this Project.

2.10.3   FirstEnergy and the AE-Constructor will mutually agree upon the best method of contracting for labor services. Subject to section 2.3(A) of the Agreement, FirstEnergy will approve all Subcontractors and will be involved in the final bid evaluations.  The AE-Constructor will develop the bidders list with FirstEnergy's approval, solicit bids, and present final bid evaluations to FirstEnergy for final review.  FirstEnergy and the AE-Constructor will mutually agree to the final selection of the bidders.

2.11  Construction

2.11.1   FirstEnergy will provide oversight of the construction work performed at the applicable site.

2.11.2   FirstEnergy site construction personnel will have the option to attend AE-Constructor site meetings, that must be held daily, relating to Project planning and/or progress.

2.11.3   AE-Constructor will hold weekly status update meetings with FirstEnergy site construction personnel to review Project safety statistics, schedule, cost, productivity, and any other relevant Project topics.  AE-Constructor to provide Gantt charts, cost and productivity reports, “S” curves, etc. as needed to clearly communicate current Project status and trends.

2.11.4   AE-Constructor will be required to utilize the National Maintenance Agreement.  Discussions on specific Labor Requirements for this work are in progress.  FirstEnergy's current standard Labor Requirements are listed in Exhibit 3.4 (E), Labor Requirements.

2.11.5   The AE-Constructor will be required to supply all temporary facilities, construction tools and equipment for each of the Subprojects.

2.11.6   With the exception of pre-existing Hazardous Substances addressed in Article 3, Paragraph 3.8 of the Terms and Conditions, the AE-Constructor will be responsible for all demolition required for this Project.  The AE-Constructor will identify the facilities to be demolished, engineer the demolition, schedule the demolition taking into account operating plant requirements and develop any safety procedures that may be required.

2.12  Checkout, Start-Up, Commissioning

2.12.1   AE-Constructor shall have responsibility for checkout, start-up, and commissioning of all systems within their work scope.  Site specific procedures shall be developed by the AE-Constructor and submitted to FirstEnergy for review and approval.

      

        Amendment to EPC Agreement      

        Appendix H – Amended Attachment A      

    

2.12.2   FirstEnergy shall assign a Start-up Coordinator to interface with AE-Constructor and FirstEnergy plant personnel relating to the start-up process.  At FirstEnergy’s option, FirstEnergy personnel may be integrated into the Start-up and Commissioning Team (participation to be under the management of and in support of AE-Constructor personnel).

2.13  Training

2.13.1   The AE-Constructor will be required to provide training for FirstEnergy operations and maintenance personnel for all portions of the new AQC Systems.  The training program will be developed in conjunction with FirstEnergy operations and maintenance personnel in accordance with FirstEnergy standard practices and will include training material development, classroom training development and execution along with hands on training in the field.

2.13.1.1   Training programs and materials for plant non-operational support personnel will also be required.

2.13.1.2   The AE-Constructor will be responsible for working with FirstEnergy operations personnel to create Operating Procedures for each of the two Subprojects.  The AE-Constructor will take the lead in the development of the Operating Procedures.

2.14  Documentation

2.14.1   All Project related documentation including; reports, correspondence, drawings, specifications, purchasing documents, O&M manuals, calculations, permits, etc. will be controlled by the AE-Constructor throughout the Project.  At Project completion, all documentation controlled by the AE-Constructor will be provided to FirstEnergy in electronic format as follows:

2.14.1.1   All documents are to be provided in native format.  In the case of drawings, native format is .dwg.  Scanned non-drawing documents are to be provided in .pdf while scanned drawings (for which the .dwg format is unavailable) shall be provided in .tif format.

2.14.1.2   Two separate formatted excel spreadsheets will be provided by FirstEnergy that the AE-Constructor will use to create an index of all drawings (.dwg and .tif) and a separate index of all other documents.  Those indexes will allow FirstEnergy to electronically populate its internal document management system.

2.14.1.3   FirstEnergy drawings that interface with the existing facilities will be provided to the AE-Constructor when required.  The AE-Constructor will modify non-CAD drawings (provided as .tif files by FirstEnergy) with Autodesk CAD Overlay software to create hybrid revisions.

2.14.1.4   The AE-Constructor will be responsible for providing final "as-built" drawings for the Project including assuring that all drawings provided by subcontractors, in the field or shop, and all equipment drawings are as-built.  The specific as-built drawing requirements will be established during the Project Development Phase.

      

        Amendment to EPC Agreement      

        Appendix H – Amended Attachment A      

    

2.15  Performance testing

2.15.1   The AE-Constructor will be responsible for coordinating all AQC system performance test scheduling, procedure development and testing including tests to be provided by the OEM.

2.15.1.1   Performance testing, although coordinated by the AE-Constructor will be performed by an independent, third party as selected by FirstEnergy.

2.15.1.2   FirstEnergy will review all test procedures, witness all tests and review and release all test reports.

3.0       SCHEDULE

3.1   The AE-Constructor will support overall Project scheduling including various design/construction options for each of the Subprojects as required to determine the optimum Project schedule.

4.0       GENERAL REQUIREMENTS

4.1   Professional Standards & Sufficient Personnel

4.1.1   The AE-Constructor will be responsible to provide adequate and qualified resources in all disciplines required to define the tasks, gather all facts relating to the tasks and coordinate all permitting, engineering, procurement, construction, commissioning, startup and testing of each of the Subprojects.

4.1.2   The AE-Constructor shall, at all times, keep sufficient personnel employed and dedicated to the Project so that the services to be performed by the AE-Constructor herein are completed on schedule and in an efficient, safe, economical and professional manner.

4.1.3   The AE-Constructor will provide adequate opportunity for FirstEnergy to examine all studies, reports, sketches, drawings, specifications, proposals and other documents presented by the AE-Constructor and submit written responses, as required within a reasonable time so as not to delay the services of the AE-Constructor.

4.1.4   The AE-Constructor will keep FirstEnergy's Project Team apprised of all work efforts, including third party meetings, status meetings, hiring of Subcontractors, etc.

      

        Amendment to EPC Agreement      

        Appendix I      

    

Appendix I

Within sixty (60) days after the issuance of the Notice to Proceed, the Scope Book will be updated to (i) reflect scope modifications associated with the relocation of the Secondary Dewatering Equipment from The Hollow Rock Disposal Facility to the Sammis Site (Alternate 43a) as described in Bechtel Letter to FirstEnergy 25186-000-TCM-GAM-00231, dated March 6, 2007,  (ii) to replace the intellectual property legend included in Part I (Scope of Services) and Part II (Technical Scope Description) of the Scope Book, and in Appendix W (Procurement Sourcing Strategies) of Part III of the Scope Book, and in the Material Assignment Schedule contained in Appendix J (pages MAS J-1 through J-8) of Part III of the Scope Book, with the following:

“This document contains information that is proprietary and confidential to First Energy Generation Corp (“First Energy”) and/or Bechtel Power Corporation (“Bechtel”).  Bechtel and FirstEnergy, respectively own and retain,  all intellectual property rights (including copyrights) in respective portions of this document, with such respective ownership rights to be determined as provided in Article 11 of the General Terms and Conditions for Engineering, Procurement, and Construction of Air Quality Control (AQC) Systems, dated August 26, 2005 (the “EPC Agreement”).”

and (iii) to remove from all Drawings contained within Part III (Appendix A –Z) of the Scope Book each intellectual property legend indicating that materials are confidential and proprietary to Bechtel and insert in its place an intellectual property legend, in the format used elsewhere in Part III on similar Drawings, indicating that such Drawings are confidential and proprietary to FirstEnergy, and (iv) except as otherwise provided above, to remove from Part III (Appendix A –Z) of the Scope Book each intellectual property legend indicating that materials are confidential and proprietary to Bechtel.

EX-10.2

FIRSTENERGY CORP.

EXECUTIVE DEFERRED COMPENSATION PLAN

Effective September 28, 1985

Amended and Restated as of January 1, 2005

TABLE OF CONTENTS

			Page
ARTICLE 1 – PURPOSE			1
	1.1	Purpose	1
ARTICLE 2 – DEFINITIONS			1
	2.1	Account	1
	2.2	Administrative Committee	1
	2.3	Beneficiary	1
	2.4	Board	1
	2.5	Change in Control	2
	2.6	Code	2
	2.7	Company	2
	2.8	Compensation Committee	2
	2.9	Deferral Election	2
	2.10	Deferral Period	2
	2.11	Disability	2
	2.12	Effective Date	3
	2.13	Elected Deferred Compensation	3
	2.14	ERISA	3
	2.15	Employer	3
	2.16	Initial Eligible Payment Date	3
	2.17	Interest Rate	3
	2.18	Long-Term Incentive Award	4
	2.19	Participant	4
	2.20	Participation Agreement	4
	2.21	Pension Plan	4
	2.22	Plan	4
	2.23	Retirement	4
	2.24	Retirement Account	4
	2.25	Retirement Stock Account	4
	2.26	Separation from Service	5
	2.27	Short-Term Incentive Award	5
	2.28	Stock Account	5
	2.29	Unforeseeable Emergency	5
ARTICLE 3 – PARTICIPATION AND DEFERRAL COMMITMENTS			5
	3.1	Eligibility and Participation	5
	3.2	Deferral Elections	6
	3.3	Commencement, Duration and Modification of Deferral Election	6

i

ARTICLE 4 – ACCOUNTS			7
	4.1	Elected Deferred Compensation	7
	4.2	Retirement Account	7
	4.3	Stock Account	8
	4.4	Retirement Stock Account	8
	4.5	Deferred Compensation Benefit	9
	4.6	Amounts Transferred from the GPU Companies Deferred Compensation Plan
		and Nonqualified Pension Plan	9
	4.7	Vesting of Accounts	9
	4.8	Statement of Accounts	10
ARTICLE 5 – DISTRIBUTION OF DEFERRED COMPENSATION BENEFITS			10
	5.1	Retirement Benefit	10
	5.2	Death Benefit	11
	5.3	Disability Benefit	12
	5.4	Separation from Service Benefit for Reasons Other Than Retirement Disability
		or Death – Retirement Account	13
	5.5	Stock Account Distributions	14
	5.6	Accelerated Distribution	14
	5.7	Financial Hardship Distributions	15
	5.8	Withholding; Payroll Taxes	16
	5.9	Commencement of Payments	16
	5.10	Payment to Guardian	17
	5.11	Small Accounts	17
ARTICLE 6 – SUPPLEMENTAL PENSION BENEFIT			17
	6.1	Eligibility and Participation	17
	6.2	Retirement Benefit	17
	6.3	Death Benefit	19
ARTICLE 7 – BENEFICIARY DESIGNATION			20
	7.1	Beneficiary Designation	20
	7.2	Amendments	20
	7.3	No Beneficiary Designation or Death of Beneficiary	20
	7.4	Effect of Payment	20
ARTICLE 8 – ADMINISTRATION			21
	8.1	Administrative Committee; Duties	21
	8.2	Agents	22
	8.3	Indemnity of Committees	22
	8.4	Participating Employers	22

ii

ARTICLE 9 – CLAIMS PROCEDURE			23
	9.1	Claim	23
	9.2	Initial Claim Review	23
	9.3	Review of Claim	24
	9.4	Review of Claims on and after a Change in Control	26
ARTICLE 10 – AMENDMENT AND TERMINATION OF PLAN			26
	10.1	Right to Amend	26
	10.2	Right to Terminate	27
	10.3	Distribution of Benefits on Plan Termination	27
ARTICLE 11 – MISCELLANEOUS			28
	11.1	Unfunded Plan	28
	11.2	Liability for Benefits	28
	11.3	Unsecured General Creditor	28
	11.4	Obligations to Employer	29
	11.5	Nonassignability	29
	11.6	Not a Contract of Employment	29
	11.7	Protective Provisions	29
	11.8	Captions	29
	11.9	Governing Law	29
	11.10	Validity	30
	11.11	Notice	30
	11.12	Successors	30
	11.13	Code Section 409A	30
APPENDIX A			31
APPENDIX B			32

iii

FIRSTENERGY CORP.

EXECUTIVE DEFERRED COMPENSATION PLAN

ARTICLE 1—PURPOSE

1.1      Purpose

           The purpose of this Executive Deferred Compensation Plan (the “Plan”) is to provide current tax planning opportunities as well as supplemental funds for retirement, death, disability or other separation of employment for key executives. The Plan is part of an integrated executive compensation program that is intended to attract, retain, and motivate certain key executives who are in positions to make significant contributions to the operation and profitability of Employers for the benefit of stockholders and customers.

           This Plan is hereby amended and restated effective as of January 1, 2005 in order to comply with Code Section 409A and supersedes all prior versions of the Plan.

ARTICLE 2—DEFINITIONS

           For the purposes of this Plan, the following terms shall have the meanings indicated, unless the content clearly indicates otherwise:

2.1     Account

           “Account” means the interest of a Participant in the Plan as represented by the hypothetical bookkeeping entries kept by Employer. A separate Account shall be established for each Participant and as may otherwise be required.

2.2     Administrative Committee

           “Administrative Committee” means the committee appointed to administer the Plan pursuant to Article 8.

2.3     Beneficiary

           “Beneficiary” means the person, persons or entity (including, without limitation any trustee) last designated by a Participant to receive the benefits specified in this Plan in the event of the Participant’s death.

2.4     Board

           “Board” means the Board of Directors of the Company.

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2.5     Change in Control

           “Change in Control” is defined in Appendix B of the Plan.

2.6     Code

           “Code” means the Internal Revenue Code of 1986, as amended together with all rules and regulations promulgated thereunder.

2.7     Company

           “Company” means FirstEnergy Corp., an Ohio corporation, or any successor to the business thereto.

2.8     Compensation Committee

           “Compensation Committee” means the Compensation Committee of the Board of Directors of the Company.

2.9     Deferral Election

           “Deferral Election” means a commitment by a Participant to defer a portion of his or her base salary, Short-Term Incentive Award and/or Long-Term Incentive Award pursuant to this Plan.

2.10   Deferral Period

           “Deferral Period” means the twelve (12) consecutive month period commencing January 1 of each year, except that the Deferral Period with respect to the initial year of eligibility pursuant to Section 3.1(c) of the Plan shall mean the period commencing on the later of the first (1^st) day of the second (2^nd) month following date of employment of an eligible employee or the date on which the eligible employee’s election to participate becomes irrevocable under Section 3.1(c), and ending on the next following December 31.

2.11   Disability

           “Disability” means:

           (a)           Solely with respect to Account balances that were accrued and vested as of December 31, 2004 and earnings, gains, and losses credited thereto after that date, a physical or mental condition such that a Participant is entitled to receive a monthly disability pension payment under the Pension Plan, except that a Participant need not have completed ten (10) years of Eligibility Service, as defined by the Pension Plan; and

           (b)           Solely with respect to Account balances that accrue and/or vest after December 31, 2004 and earnings, gains and losses credited thereto after that date, a physical or mental condition in which the Participant:

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                           (i)            Is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months; or

                           (ii)            Is by reason of any medically determinable physical or mental impairment which can be expected to result in death or an be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under an accident and health plan covering employees of the Company, or

                           (iii)            Is determined to be totally disabled by the Social Security Administration or the Railroad Retirement Board.

2.12   Effective Date

           This Plan is effective as of September 28, 1985, amended and restated as of May 17, 2004 and it is amended and restated as of January 1, 2005 unless specifically stated otherwise herein.

2.13   Elected Deferred Compensation

           “Elected Deferred Compensation” means the amount of base salary, Short-Term Incentive Award and Long-Term Incentive Award that a Participant elects to defer pursuant to a Deferral Election.

2.14   ERISA

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

2.15   Employer

           “Employer” means the Company and any affiliated or subsidiary entity as defined in Code Section 414(b) and (c) except that in applying Code Section 1563 “50 percent” shall be substituted for “80 percent.”

2.16   Initial Eligible Payment Date

           “Initial Eligible Payment Date” means the third (3^rd) anniversary of the date Elected Deferred Compensation for a Deferral Period is first credited to the Stock Account.

2.17   Interest Rate

           “Interest Rate” means the annual equivalent of the average of the Moody’s Average Long-Term Corporate Bond Yield Index for the twelve (12) consecutive month period ending on October 31 of the calendar year immediately preceding the Deferral Period to which the Interest Rate applies, as published by Moody’s Investors Service, Inc., or any successor thereto, or a substantially similar index if such index is no longer published.

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2.18   Long-Term Incentive Award

           “Long-Term Incentive Award” means those vested Performance Share awards, otherwise payable in cash but for the deferral hereunder, permitted under Article 9 of the Executive and Director Incentive Compensation Plan and earned under the FirstEnergy Executive Compensation Plan, as amended and revised.

2.19   Participant

           “Participant” means any key executive who is an employee of any Employer and who has been designated by the Chief Executive Officer of the Company as eligible to participate in this Plan pursuant to either Article 3 or Article 6 of this Plan. For purposes of the Deferred Compensation Benefit portion of this Plan, such an employee is a Participant only if he or she files a Participation Agreement with the Administrative Committee. Any employee who had amounts transferred from the GPU Companies Compensation Plan in accordance with Section 4.6 shall be a Participant as of the date of such transfer.

2.20   Participation Agreement

           “Participation Agreement” means the agreement, whether written or provided through electronic means, in which a Participant makes a Deferral Election and makes elections regarding the time and/or manner in which amounts shall be distributed from the Plan. In order for a Deferral Election to be effective for a Deferral Period, the Participation Agreement must be submitted by a Participant to the Administrative Committee or its delegates prior to the commencement of the Deferral Period in which the Elected Deferred Compensation is earned.

2.21   Pension Plan

           “Pension Plan” means the FirstEnergy Corp. Pension Plan as amended.

2.22   Plan

           “Plan” means this FirstEnergy Corp. Executive Deferred Compensation Plan as set forth in this document and as the same may be amended from time to time.

2.23           Retirement

           “Retirement” means Separation from Service on or after age fifty-five (55) except due to death and entitled to receive a benefit under the Pension Plan.

2.24   Retirement Account

           “Retirement Account” means the Account established pursuant to Section 4.2 of this Plan.

2.25   Retirement Stock Account

           “Retirement Stock Account” means the Account established pursuant to Section 4.4 of this Plan.

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2.26   Separation from Service

           “Separation from Service” means an employee’s “termination of employment” with all Employers. Whether a “termination of employment” has occurred is determined based on whether the facts and circumstances indicate that the Employers and the employee reasonably anticipate that no further services will be performed after a certain date or that the level of bona fide services the employee will perform after such date (whether as an employee or as an independent contractor) will permanently decrease to no more than twenty (20) percent of the average level of bona fide services performed (whether as an employee or independent contractor) over the immediately preceding thirty-six (36) months (or the full period of services to the Employers if the employee has been providing services to the Employers for less than thirty-six (36) months).

2.27   Short-Term Incentive Award

           “Short-Term Incentive Award” means those vested awards earned under the FirstEnergy Executive Incentive Compensation Plan, as amended and revised.

2.28   Stock Account

           “Stock Account” means the Account established pursuant to Section 4.3 of this Plan.

2.29   Unforeseeable Emergency

           “Unforeseeable Emergency” means a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participant’s spouse or the Participant’s Beneficiary or dependent (as defined in Code Section 152 without regard to sections 152(b)(1), (b)(2) and (d)(1)(B)); loss of the Participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant.

ARTICLE 3—PARTICIPATION AND DEFERRAL COMMITMENTS

3.1     Eligibility and Participation

        (a)           Eligibility.  The Chief Executive Officer of the Company may designate any key executive who is an employee of any Employer as eligible to make a Deferral Election and to receive Stock Premiums as of the first (1^st) day of any month following the employee’s date of hire.

           (b)           Participation.  An eligible employee may elect to participate in the Plan by filing with the Administrative Committee a Participation Agreement prior to the Deferral Period in which the employee is eligible to participate, except as set forth in subsection (c) below. The Participation Agreement shall be irrevocable as of the December 31 immediately preceding the Deferral Period.

5

           (c)           Initial Year of Eligibility.  An eligible employee may elect to participate in the Plan by filing with the Administrative Committee a Participation Agreement within thirty (30) days of the date such employee first becomes eligible to participate in the Plan. In the event an employee previously participated in this Plan, such employee may not elect to participate under this subsection unless he or she has not been eligible to participate for at least the twenty-four (24) month period immediately preceding the most recent date of eligibility. The Participation Agreement shall be irrevocable as of the thirtieth (30^th) day following the employee’s eligibility date.

           (d)           A Participation Agreement shall not be considered to be revocable merely because the employee or his or her Employer may make an election to change the time and form of payment or the employee may accelerate the time of payment of a Deferred Compensation Benefit but only to the extent such a change is permitted by this Plan.

3.2     Deferral Elections

           A Participant may elect in the Participation Agreement to defer any or all of the following:

           (a)           Salary Deferral.  A Participant may elect to defer a percentage of base salary earned and otherwise payable for the Deferral Period. The amount to be deferred shall be stated as a whole percentage and, effective January 1, 2002, shall not be more than fifty percent (50%) of base salary.

           (b)           Short-Term Incentive Award and/or Long-Term Incentive Award Deferral.  A Participant may elect to defer a percentage of his or her Short-Term Incentive Award and/or Long-Term Incentive Award that is earned during the Deferral Period and otherwise payable in the year following the Deferral Period. The amount to be deferred must be stated as a whole percentage and shall not be more than one hundred percent (100%) of such Award, less any taxes or other amounts that may be required to be withheld.

3.3     Commencement, Duration and Modification of Deferral Election

        (a)           Commencement.  A Deferral Election shall become effective on the first (1^st) day of the Deferral Period immediately following the date a Participation Agreement for such Deferral Election is filed with the Administrative Committee.

           (b)           Duration of Deferral Election.  A Deferral Election shall remain in effect for one (1) Deferral Period only.

           (c)           Modification Due to Unforeseeable Emergency or Hardship Distribution.  A Deferral Election shall be irrevocable, except that the Administrative Committee may permit a Participant to cancel the remainder of the Deferral Election for a Deferral Period upon a finding, based upon uniform standards established by the Administrative Committee, that the Participant has suffered an Unforeseeable Emergency or is qualified to receive a hardship distribution pursuant to Code Section 1.401(k)-1(d)(3). If the Administrative Committee grants a waiver, the Participant shall not be permitted to make a Deferral Election in the same Deferral Period.

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ARTICLE 4—ACCOUNTS

4.1     Elected Deferred Compensation

           A Participant’s Elected Deferred Compensation shall be credited to the Participant’s Account as of the date such amount would have otherwise been paid to such Participant.

4.2      Retirement Account

        (a)           Establishing a Retirement Account.  A Participant may establish an annual Retirement Account on and after January 1, 2005 which shall be maintained solely for recordkeeping purposes, by making a Deferral Election.

           (b)           Maximum Deferral.  A Participant may elect to defer up to fifty percent (50%) of base salary and up to one hundred percent (100%) of the Short-Term Incentive Award into the Retirement Account.

           (c)           Earnings

                          (i)             Prior to January 1, 2008, the Retirement Account shall be credited with earnings equal to the Interest Rate plus three (3) percentage points. The maximum Interest Rate shall be twelve percent (12%).

                          (ii)            Commencing January 1, 2008, a Participant may elect from among a series of hypothetical investment options, including the option described in paragraph (i) above, which are selected by the Administrative Committee and to which the Participant’s Elected Deferred Compensation shall be credited. The Participant’s Accounts shall be credited daily with earnings, gains and losses as if such Accounts were invested in one (1) or more Plan investment options, as selected by the Participant. Investment options may be changed from time to time by the Administrative Committee in its sole discretion.

                          (iii)           Participants may change the options into which Elected Deferred Compensation is credited and may change the allocation of existing Account balances which elections shall become effective as of the first (1^st) day of the month following the date such election is submitted to the Administrative Committee.

           (d)           Earnings for Senior Management Retirees.  The Retirement Account of any Member of senior management who retired before July 1, 1998 shall be credited with the greater of:

                           (i)            The Interest Rate plus four (4) percentage points, or

                           (ii)           The equivalent of a twelve percent (12%) annual yield.

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4.3     Stock Account

        (a)           Establishing a Stock Account.  A Participant may establish an annual Stock Account, which shall be maintained solely for recordkeeping purposes, by making a Deferral Election.

           (b)           Maximum Deferral.  A Participant may elect to defer up to one hundred percent (100%) of the Short-Term Incentive Award and Long-Term Incentive Award into the Stock Account.

           (c)           Stock Premium.  Amounts deferred into the Stock Account shall be credited with an amount equal to twenty percent (20%) of the amount deferred into the Stock Account. Such premium shall be credited as of the date the corresponding Elected Deferred Compensation is credited to the Stock Account.

           (d)           Stock Units and Earnings.  Amounts deferred into the Stock Account shall be converted into units of Company common stock. The number of stock units credited to the Stock Account shall be determined by dividing the amount deferred into the Stock Account, plus the Stock Premium described in (c) above, by the average daily closing price of Company common stock during February of the Deferral Period in which the Elected Deferred Compensation is credited to the Account.

          (e)           Dividends.  Additional stock units shall be credited to each Stock Account at the time dividend payments are made to Company shareholders. The number of additional units credited shall be based on the number of units in the Stock Account and the market price of Company stock at the close of that business day.

           (f)           Automatic Cessation of Stock Premium and Dividends.  Unless the Plan is terminated by the Company prior to the following, the crediting of the 20% stock premium and dividends in Company common stock will automatically cease on May 17, 2014 or earlier if the maximum share reserve of 1,000,000 shares is reached, unless shareholders reapprove these features on the earlier of the prior date or prior to the depletion of the maximum share reserve.

4.4     Retirement Stock Account

        (a)           Establishing a Retirement Stock Account.  Effective January 1, 2002, a Retirement Stock Account may be established for a Participant who has elected to defer receipt of his or her Stock Account pursuant to Section 5.5(a) of this Plan solely for recordkeeping purposes and shall be credited with earnings, gains, losses and dividends in the same manner as the Stock Account.

          (b)           Transfer to Retirement Account.  Upon Separation from Service or death the value of the Participant’s Retirement Stock Account shall be transferred to the Participant’s Retirement Account as of the date of Separation from Service or death and paid in cash pursuant to Article 5 of this Plan.

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4.5     Deferred Compensation Benefit

           The aggregate balances of a Participant’s Retirement Account, Stock Account and Retirement Stock Account shall be the Participant’s “Deferred Compensation Benefit.”

4.6     Amounts Transferred from the GPU Companies Deferred Compensation Plan and Nonqualified Pension Plan

           (a)           Deferred Compensation Amounts.  As of November 7, 2001, certain account balances from the GPU Companies Deferred Compensation Plan were transferred to this Plan in conjunction with the merger of GPU, Inc. into the Company. As of such date, the transferred balances shall be credited in a Retirement Account for each such former employee of the GPU Companies and shall be credited with earnings in the same manner as all other Retirement Accounts.

           (b)           Nonqualified Pension Plan Amounts.  As of November 7, 2001, the accrued benefit associated with certain GPU nonqualified pension plans were transferred to this Plan in conjunction with the merger of GPU, Inc. into the Company. Each such former employee affected by this transfer shall be entitled to receive an increase in such employee’s benefit equal to ten percent (10%) of the benefit, so that, when benefits are paid, they will be ten percent (10%) greater than the amount that otherwise would have been paid had the benefit been paid under the GPU Companies nonqualified pension plans.

4.7     Vesting of Accounts

           Each Participant shall be vested in the amounts credited to such Participant’s Accounts as follows:

           (a)           Elected Deferred Compensation.  A Participant shall be one hundred percent (100%) vested at all times in his Elected Deferred Compensation and any gains or losses thereon regardless of the Account to which such amounts are credited.

           (b)           Stock Premium.  A Stock Premium, and any earnings gains or losses thereon shall be one hundred percent (100%) vested on:

                           (i)           the Initial Eligible Payment Date for the related Elected Deferred Compensation, provided the Participant is either:

                                           a)           Employed by an Employer on the Initial Eligible Payment Date, or

                                           b)           Has a Separation from Service on or after reaching age sixty (60);

9

                           (ii)           the death of the Participant;

                          (iii)           a Separation from Service of the Participant due to one (1) of the following events:

                                           a)           his or her Disability;

                                           b)           involuntary termination under conditions where the Participant becomes eligible for and elects to accept an Employer severance benefit; or

                          (iv)           a Change in Control.

4.8     Statement of Accounts

           The Administrative Committee shall submit to each Participant, after the close of each calendar year and at such other times as determined by the Administrative Committee, a statement setting forth the balance to the credit of the Accounts maintained for a Participant.

ARTICLE 5—DISTRIBUTION OF DEFERRED COMPENSATION BENEFITS

5.1     Retirement Benefit

        (a)           Benefit.  Upon a Participant’s Retirement, the Participant shall be paid a Deferred Compensation Benefit equal to the amount of the Participant’s Retirement Account earned by the Participant to the date such amount is distributed, including any balance transferred from the Participant’s Retirement Stock Accounts and Stock Accounts.

           (b)           Form of Benefit.  The Participant may make an election in his or her Participation Agreement to receive benefits from the Retirement Account in the following manner:

                           (i)            A lump-sum payment; and/or

                          (ii)            Monthly installments over a period of up to three hundred (300) months. The amount of the installment shall be redetermined January 1 of each year based upon the then current earnings crediting rate under Section 4.2(c)(i) of the Plan, the remaining Retirement Account balance, and the remaining number of payment periods.

           (c)           Election Regarding Time of Payment.  A Participant may make an election in his or her Participation Agreement to defer commencement of payment of the Retirement Account to the later of Retirement or a specified date, but the specified date shall not be later than the first (1^st) day of the month following the Participant’s seventieth (70th) birthday.

           (d)           Default Form of Benefit.  If the Participant makes no election as to the manner in which benefits shall be distributed prior to the commencement of Deferral Period, the Employer shall pay benefits in a lump-sum payment.

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           (e)           Grandfathered Election Right.  Solely with respect to Account balances accrued and vested as of December 31, 2004 and earnings, gains and losses credited thereon after that date, a Participant may amend his or her elections regarding the form of benefit and time of payment up to ninety (90) days prior to Retirement.

           (f)           Changing Date or Form of Payment.  Solely with respect to Account balances that accrue and/or vest after December 31, 2004 including deemed earnings, gains and losses credited thereon after that date, a Participant may amend his or her elections regarding the form of benefit and time of payment provided:

                           (i)            Such election is submitted to the Committee in writing at least twelve (12) months prior to the date any amount is to be distributed from the Plan;

                           (ii)           Such election shall not take effect until twelve (12) months after it is submitted to the Committee in writing; and

                           (iii)          The payment of any benefits under this Plan shall not commence until at least five (5) years from the date such payment would otherwise have been made.

           (g)           Transition Election Right.  Notwithstanding the above, distribution elections made with respect to Deferral Elections made between January 1, 2005 and December 31, 2007 may be changed no later than December 31, 2007 in accordance with Code Section 409A.

5.2     Death Benefit

        (a)           Benefit.  Upon a Participant’s death, the Participant’s Beneficiary shall be paid a Deferred Compensation Benefit equal to the amount of the Participant’s Retirement Account, Stock Account and Retirement Stock Account earned by the Participant to the date such amount is distributed to the Participant’s Beneficiary. If a Participant dies prior to Separation from Service, such amounts shall be paid to the Beneficiary in the form elected by the Participant and in accordance with Section 5.5 of this Plan.

          (b)           Form of Payment.  Each Participant may make an election in his or her Participation Agreement to have his or her death benefits paid in any manner described in Section 5.1(b).

           (c)           Grandfathered Election Right.  Solely with respect to Account balances accrued and vested as of December 31, 2004 and earnings, gains and losses credited thereon after that date, the Participant may change such distribution election by filing a new election with the Administrative Committee at any time prior to such Participant’s death.

           (d)           Changing Form of Payment.  Solely with respect to Account balances that accrue and/or vest after December 31, 2004 including deemed earnings, gains and losses credited thereon after that date, a Participant may amend his or her elections regarding the form of benefit and such election shall take effect twelve (12) months after it is submitted to the Committee in writing.

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           (e)           Transition Election Right.  A Participant may change distribution elections made with respect to Deferral Elections between January 1, 2005 and December 31, 2007 no later than December 31, 2007 in accordance with Code Section 409A. Such elections made at any time thereafter shall become effective twelve (12) months after such election is filed with the Administrative Committee.

           (f)            Installment Payments.  If a Participant dies after Retirement and while receiving installment payments of such benefit, such amounts shall continue to be paid to the Beneficiary in the same manner.

           (g)           Deferral Not Effective.  If the Participant elected to defer commencement of Retirement benefits pursuant to Section 5.1(c) and dies prior to the commencement thereof, upon the Participant’s death such election to defer commencement of Retirement benefit payments shall become null and void and payments will commence immediately to the Beneficiary in the form elected by the Participant.

5.3     Disability Benefit

        (a)           Benefit.  Upon a Participant’s Separation from Service due to Disability, the Participant shall be paid a Deferred Compensation Benefit equal to the amount of the Participant’s Retirement Account, Stock Account and any balance transferred from the Retirement Stock Account or Stock Accounts earned by the Participant through the date such amount is distributed to the Participant.

           (b)           Form of Payment

                           (i)            Retirement Account.  A benefit shall be paid as elected by the Participant in the Participation Agreement with respect to the Retirement Account.

                           (ii)           Stock Account.  A benefit shall be paid from the Stock Account pursuant to Section 5.5 of the Plan.

           (c)           Grandfathered Election Right.  Solely with respect to Account balances accrued and vested as of December 31, 2004 and earnings, gains and losses credited thereon after that date, such election may be changed by the Participant at any time prior to Disability, and the Participant may choose to receive benefits in the same manner as described in Section 5.1(b) of the Plan.

           (d)           Changing Date or Form of Payment.  Solely with respect to Account balances that accrue and/or vest after December 31, 2004 including deemed earnings, gains and losses credited thereon after that date, a Participant may amend his or her elections regarding the form of benefit and time of payment provided:

                           (i)            Such election is submitted to the Committee in writing at least twelve (12) months prior to the date any amount is to be distributed from the Plan;

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                           (ii)           Such election shall not take effect until twelve (12) months after it is submitted to the Committee in writing; and

                           (iii)           The payment of any benefits under this Plan shall not commence until at least five (5) years from the date such payment would otherwise have been made.

           (e)           Transition Election Right.  Notwithstanding the above, distribution elections made with respect to Deferral Elections made between January 1, 2005 and December 31, 2007 may be changed no later than December 31, 2007 in accordance with Code Section 409A.

5.4     Separation from Service Benefit for Reasons Other Than Retirement, Disability or Death—Retirement Account

           (a)           Benefit.  Upon a Participant’s Separation from Service prior to his or her Retirement, Disability or death, the Participant shall be paid a Deferred Compensation Benefit equal to the amount of the Participant’s Retirement Account, Stock Account and any balance transferred from the Retirement Stock Account or Stock Accounts earned by the Participant through the date such amount is distributed to the Participant.

           (b)           Form of Payment.

                           (i)            Retirement Account.  The benefit under this Section shall be paid to the Participant in a lump-sum.

                           (ii)           Stock Account.  A benefit shall be paid from the Stock Account pursuant to Section 5.5 of the Plan.

           (c)           Grandfathered Election Right.  Notwithstanding the above, effective January 1, 2002 and solely with respect to Account balances accrued and vested as of December 31, 2004 including earnings, gains and losses credited thereon after that date, any Participant who has been involuntarily terminated under conditions where the Participant becomes eligible for and elects to accept an Employer severance benefit, may irrevocably elect at least thirty (30) days prior to the date of Separation from Service to receive three (3) installment payments, the first to be paid as soon as administratively feasible following the Participant’s date of Separation from Service and on January 1 of each of the next two (2) years. The amount of the installment shall be redetermined January 1 of each year based upon the then current earnings crediting rate under Section 4.2(c) of the Plan, the remaining Retirement Account balance, and the remaining number of payments.

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5.5     Stock Account Distributions

        (a)           Benefit of Participant Employed on Initial Eligible Payment Date or with a Separation from Service on or after Age Sixty.  An Employer shall pay a Participant who is employed by any Employer on his or her Initial Eligible Payment Date or who has a Separation from Service on or after age sixty (60) a Deferred Compensation Benefit equal to the amount of the Participant’s Stock Account earned by the Participant while he or she was employed by such Employer, including the Stock Premium, in Company common stock. Commencing January 1, 2002, a Participant may elect in his or her Participation Agreement to defer receipt of such payment to the Participant’s date of Separation from Service or death. If such an election is made, such Stock Account balance, including the Stock Premium, shall be transferred to a Retirement Stock Account or held in the Stock Account until Separation from Service or death and then transferred to a Retirement Account and paid in cash pursuant to the Participant’s elections or Plan provisions, whichever is applicable, under Sections 5.1, 5.2, 5.3, or 5.5 of this Plan.

           (b)           Benefit of Participant with Separation from Service prior to Age Sixty.  Commencing January 1, 2002, if a Participant with a Stock Account balance that has not reached its Initial Eligible Payment Date Separates from Service for any reason, including death or Disability prior to age sixty (60), such vested balance shall be transferred to a Retirement Account and paid in cash pursuant to the Participant’s elections or Plan provisions, whichever is applicable, under Article 5 of this Plan.

          (c)           Benefit of Participant with Separation from Service on and after Age Sixty.  Commencing January 1, 2002, if a Participant with a Stock Account balance that has not reached its Initial Eligible Payment Date Separates from Service for any reason including death or Disability on or after age sixty (60), such Stock Account, including the Stock Premium, shall be payable on the earlier of the date the Stock Premium becomes fully vested or the Initial Eligible Payment Date. A Participant may make an election each year in a Participation Agreement to receive the Stock Account, including the Stock Premium, either in the form of Company common stock or in cash and paid pursuant to the Participant’s elections or Plan provisions, whichever is applicable, under Article 5 of this Plan. If the Participant does not make an election prior to the Commencement of the Deferral Period, such Stock Accounts shall be paid in the form of Company common stock.

5.6      Accelerated Distribution

           Notwithstanding anything to the contrary herein and solely with respect to Accounts that are accrued and vested as of December 31, 2004 including earnings, gains and losses credited thereon after that date, at any time, a Participant (or the Participant’s Beneficiary in case of the death of the Participant) may request a distribution of his or her vested Account balance. Each Employer by whom the Participant was employed shall pay a Plan benefit equal to the amount of the Participant’s Retirement Account earned by the Participant during the Participant’s employment with such Employer. Such vested balance shall be reduced by ten percent (10%), which amount shall be forfeited by the Participant.

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           Such request must be made in writing in a form and manner specified by the Administrative Committee. The distribution to the Participant or Beneficiary shall be made as soon as administratively feasible in a lump-sum. The amount distributed from the Stock Account and the Retirement Stock Account shall be paid in Company common stock. Such distribution shall completely discharge the Administrative Committee and the Employers from all liability with respect to the Participant’s or Beneficiary’s Accounts.

           If the Participant is an employee of an Employer when the distribution is made, the Participant shall not make a Deferral Election until January 1 of the second calendar year following the calendar year in which the Participant receives such distribution.

           Notwithstanding the foregoing, if a Participant who is required to file reports under Section 16 of the Securities Exchange Act of 1934 requests an accelerated distribution of his Stock Account, and/or the Retirement Stock Account, the request must be approved by the Compensation Committee.

5.7     Financial Hardship Distributions

        (a)           Distribution upon an Unforeseeable Emergency.  Notwithstanding any other provision of the Plan and solely with respect to Account balances that accrue and vest after December 31, 2004 including deemed earnings, gains and losses credited thereon after that date, payment from the Participant’s Accounts may be made to the Participant, in the sole discretion of the Administrative Committee, due to an Unforeseeable Emergency.

           (b            Termination of Deferral Election.  If such a distribution is made, the Participant’s Deferral Election for the Deferral Period in which the distribution is made shall be void and such Participant shall not be eligible to make a Deferral Election until the next Deferral Period.

           (c)           Maximum Amount of Distribution.  Such payment shall not exceed the amount reasonably necessary to satisfy the Unforeseeable Emergency plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution after taking into account the extent to which such Unforeseeable Emergency is or may be relieved through cancellation of the Participant’s Deferral Election, reimbursement or compensation by insurance or otherwise or by liquidation of the Participant’s assets, to the extent such liquidation would not itself cause severe financial hardship. However, the determination of amounts necessary to satisfy the Unforeseeable Emergency is not required to take into account an available distribution or loan from a qualified plan, any additional compensation that is available under another nonqualified deferred compensation plan, including a grandfathered nonqualified deferred compensation plan, but has not actually been paid.

          (d)           Payment Form and Source.  Payment shall be made in a single lump-sum within thirty (30) days after the date the request for a distribution is approved by the Administrative Committee. Distributions shall be made first from the Retirement Account, then from any Retirement Stock Account and then from any Stock Account, excluding the Stock Premium.

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5.8     Withholding; Payroll Taxes

           An Employer paying a benefit shall withhold from payments made hereunder to the Participant or any Beneficiary, any amounts required to be withheld by applicable law. An Employer may withhold from either deferred or nondeferred compensation any amounts required to be withheld by the Federal Insurance Contributions Act (FICA), the Federal Unemployment Tax Act (FUTA), or any state income tax provision, or any other applicable law. All Plan administration expenses incurred by an Employer or the Administrative Committee shall be borne by the Company.

5.9     Commencement of Payments

        (a)           Commencement Date.  Except for a distribution upon an Unforeseeable Emergency as provided in Section 5.7 and for grandfathered benefits as provided in subsection (e) below, payment of benefits shall commence as soon as administratively feasible following the event giving rise to a distribution but not later than ninety (90) days following the date of the event giving rise to the distribution. A Participant shall not have a right to designate the taxable year of payment other than by an election that is otherwise permitted by this Plan.

           (b)           Specified Employee.  Notwithstanding subsection (a), a Participant who is a specified employee as defined in Code Section 409A(a)(2)(B)(i) on his date of Separation from Service (except due to death) shall not receive a distribution of any amount under this Plan, whether a Deferred Compensation Benefit or a Supplemental Pension Benefit, that is accrued and/or vested after December 31, 2004 including earnings, gains and losses credited thereon after that date before the date which is six (6) months after the date of Separation from Service.

           (c)           Delay in Payment.  In the event a distribution must be delayed as required in subsection (b):

                           (i)           If the payment is a lump-sum, such lump-sum shall continue to be credited with earnings, gains and losses pursuant to Section 4.2(c) until the actual date of distribution.

                          (ii)           If the benefit is to be paid in installments, the first payment shall include an amount equal to the sum of the monthly payments which would have been paid to the Participant but for the payment deferral mandated pursuant to subsection (b).

           (d)           All payments shall be made as of the first (1^st) day of the month.

           (e)           Grandfathered Commencement Date.  Solely with respect to benefits under this Plan accrued and vested as of December 31,2004 and earnings, gains and losses credited thereon after that date, payment of benefits shall commence as soon as administratively feasible following the event giving rise to a distribution.

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5.10   Payment to Guardian

           If a Plan benefit is payable to a minor or a person declared incompetent or to a person incapable of handling the disposition of property, the Administrative Committee may direct payment of such Plan benefit to the guardian, legal representative or person having the care and custody of such minor or incompetent person. The Administrative Committee may require proof of incompetence, minority, incapacity or guardianship as it may deem appropriate prior to distribution of the Plan benefit. Such distribution shall completely discharge the Administrative Committee and the Employer from all liability with respect to such benefit.

5.11   Small Accounts

           Notwithstanding anything herein to the contrary and solely with respect to account balances that are accrued and vested as of December 31, 2004, including earnings, gains and losses credited thereon after that date, in the event the Participant’s Account balance that will be paid in installments is less than one hundred thousand dollars ($100,000) on the date payments commence, and such Participant has elected to receive installment payments over a period of more than one hundred eighty (180) months, such election shall become null and void and the Participant shall receive such benefit in monthly installments over one hundred eighty (180) months.

ARTICLE 6—SUPPLEMENTAL PENSION BENEFIT

6.1     Eligibility and Participation

           The Chief Executive Officer of the Company may designate any key executive who is an employee of any Employer as eligible to receive the benefit described in this Article (“Supplemental Pension Benefit”) as of the first (1^st) day of the month following the employee’s date of hire.

6.2     Retirement Benefit

        (a)           Benefit.  Each Participant or Beneficiary who is entitled to a benefit under the Pension Plan shall be entitled to a Supplemental Pension Benefit equal to the benefit that would have been paid under the Pension Plan without regard to:

                           (i)            Compensation deferred under this Plan;

                           (ii)           Exclusion of Short-Term Incentive Award from the definition of compensation in the Pension Plan; and

                           (iii)           Limitations imposed by Code Sections 401(a)(17) and 415 in the Pension Plan.

           (b)           Offset.  The benefit described in subsection (a) shall be reduced by the amount payable from the Pension Plan.

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           (c)           Form of Payment.  Prior to the commencement of payments of the Supplemental Pension Benefit, a Participant shall select the form of payment from the following:

                           (i)           Single life annuity;

                           (ii)           Joint and 100%, 75%, 50% or 25% survivor annuity;

                           (iii)           Life annuity with payments guaranteed for a period of sixty (60), one hundred twenty (120) or one hundred eighty (180) months.

          (d)           Default Form of Payment.  In the absence of an election, the Supplemental Pension Benefit shall be paid as a single life annuity if the Participant is not married at the time payments are to commence, and in the form of a joint and 50% survivor annuity to a married Participant, with the Participant’s spouse as the joint annuitant unless the Participant has designated another joint annuitant.

          (e)           Actuarial Equivalent.  All forms of payment shall be actuarially equivalent based on reasonable actuarial assumptions as of the date benefit payments are to commence. On such date, the same actuarial assumptions shall be used in valuing each annuity payment option.

           (f)           Commencement of Payments.  Subject to Section 5.9(b), payment of the Supplemental Pension Benefit shall commence as follows:

(i)           If Separation from Service occurs prior to Retirement, payment of the Supplemental Pension Benefit shall commence on the first (1^st) day of the month following attainment of age sixty (60).

(ii)           Upon Retirement, payment of the benefit shall commence on the first (1^st) day of the month following Retirement.

          (g)           Changing Time of Commencement of Payments.  A Participant may make a subsequent Deferral Election with respect to the date that payment of a Supplemental Pension Benefit commences. Such election must be made not less than twelve (12) months before the date the benefit payment is scheduled to be paid and shall become effective twelve (12) months from the date such Deferral Election is submitted to the Administrative Committee. A subsequent Deferral Election becomes irrevocable to the extent required under Treasury Regulation Section 1.409A-2(b)(1) when it is submitted to the Administrative Committee. In the case of a benefit payment which is not due to Disability or death, the date payments may commence under a subsequent Deferral Election must be no earlier than five (5) years from the date such payment would otherwise have been made.

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          (h)           Grandfathered Election Right.  Solely with respect to the Supplemental Pension Benefit that was accrued and vested as of December 31, 2004, such Benefit shall be paid to the Participant at the same time and in the same manner as payments from the Pension Plan.

6.3     Death Benefit

        (a)           Benefit.  Each Beneficiary entitled to a pre-retirement survivor benefit under the Pension Plan shall be entitled to a death benefit under this Section 6.3 determined in the same manner as Retirement benefits under Section 6.2 of this Plan as if the first (1^st) day of the month following the Participant’s date of death was the later of (i) the Participant’s attainment of age fifty-five (55); or (ii) the date of the Participant’s Separation from Service.

          (b)           Form of Payment.  The Beneficiary shall receive the death benefit in the form of a single life annuity for the Beneficiary’s lifetime pursuant to a joint and 100% survivor annuity.

           (c)           Commencement of Payments.

                           (i)            If a Participant dies and has less than ten (10) years but at least five (5) years of Eligibility Service as defined in the Pension Plan on such Participant’s date of death, payments shall commence under this Section 6.3 on the later of:

                                           a)           The first day (1^st) of the month following the date the Participant would have attained age fifty-five (55); or

                                           b)           Within ninety (90) days of the Participant’s date of death.

                           (ii)           If a Participant dies and has at least ten (10) years of Eligibility Service as defined in the Pension Plan on such Participant’s date of death, payments shall commence no later than the first (1^st) day of the month following the Participant’s date of death.

                           (iii)          If a Participant dies prior to attaining age fifty-five (55), such Participant shall be deemed to have died on the day after such Participant would have attained age fifty-five (55).

           (d)           Pension Plan Reduction Factors.  Benefit reduction factors shall be applied in the same manner and pursuant to provisions in the Pension Plan.

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ARTICLE 7—BENEFICIARY DESIGNATION

7.1     Beneficiary Designation

           Each Participant shall have the right, at any time, to designate one (1) or more persons as the primary or contingent Beneficiary(ies) to whom benefits under Sections 5.2 and one (1) Beneficiary under Section 6.3 of this Plan shall be paid in the event of the Participant’s death prior to complete distribution to the Participant of the benefits due under the Plan. Unless stated otherwise in writing in the form provided by the Administrative Committee, payments hereunder shall be paid in equal shares to surviving Beneficiaries if more than one (1) Beneficiary has been designated. Each Beneficiary designation shall be in a written form prescribed by the Administrative Committee and shall be effective only when filed with the Administrative Committee during the Participant’s lifetime. If a Participant’s compensation is community property, any Beneficiary designation shall be valid or effective only as permitted under applicable law.

7.2     Amendments

           Any Beneficiary designation may be changed by a Participant without the consent of any Beneficiary by the filing of a new Beneficiary designation with the Administrative Committee.

7.3     No Beneficiary Designation or Death of Beneficiary

        (a)           Default Beneficiary Designation.  In the absence of an effective Beneficiary designation, or if all designated Beneficiaries predecease the Participant, the Participant’s Beneficiary shall be the person in the first (1^st) of the following classes:

                           (i)            The surviving spouse;

                           (ii)           The Participant’s estate.

          (b)           Lump-sum Distribution.  In the event of the death of a Beneficiary after payments commence but prior to the Beneficiary receiving all benefit payments under this Plan, in the remaining balance shall be paid in a lump-sum to the estate of the Beneficiary.

7.4     Effect of Payment

           Payment to the Beneficiary or Beneficiaries including a Beneficiary under Section 7.3 shall completely discharge the Employers’ obligations under this Plan.

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ARTICLE 8—ADMINISTRATION

8.1     Administrative Committee; Duties

           This Plan shall be administered by an Administrative Committee consisting of three (3) or more members who are appointed by the Chief Executive Officer of the Company. Members of the Administrative Committee may be Participants in this Plan. However, no member of the Administrative Committee may participate in a review of his or her own claim under Article 9. The Administrative Committee shall administer the Plan and shall have the power and the duty to take all action and to make all decisions necessary or proper to carry out the Plan. The determination of the Administrative Committee as to any question involving the general administration and interpretation of the Plan shall be final, conclusive, and binding except as otherwise provided in Article 9. A majority vote of the Administrative Committee members shall control any decision. Any discretionary actions to be taken under the Plan by the Administrative Committee with respect to the classification of employees, Participants, contributions or benefits shall be uniform in nature and applicable to all persons similarly situated. Without limiting the generality of the foregoing, the Administrative Committee shall have the following discretionary authority, powers and duties:

           (a)           To require any person to furnish such information as it may request for the purpose of the proper administration of the Plan as a condition to receiving any benefit under the Plan;

           (b)           To make and enforce such rules and regulations and prescribe the use of such forms as it deems necessary for the efficient administration of the Plan;

           (c)           To interpret the Plan and to resolve ambiguities, inconsistencies and omissions;

           (d)           To decide all questions concerning the Plan and any questions concerning the eligibility of any employee to participate in the Plan; and

           (e)           To determine the amount of benefits which will be payable to any person in accordance with the provisions of the Plan.

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Upon and after the occurrence of a Change in Control, the “Administrative Committee” shall be at least three (3) individuals selected by the individual who, immediately prior to the Change in Control, was the Company’s Chief Executive Officer or, if not so identified, the Company’s highest ranking officer (the “Ex-CEO”); provided, however, the Administrative Committee, as constituted immediately prior to a Change in Control, shall continue to act as the Administrative Committee for this Plan until the date on which the independent third parties selected by the Ex-CEO accept the responsibilities as members of the Administrative Committee under this Plan. Upon and after a Change in Control, the Administrative Committee shall have all discretionary authorities and powers granted the Administrative Committee under this Plan including the discretionary power to determine all questions arising in connection with the administration of the Plan and the interpretation of the Plan except benefit entitlement determinations upon appeal. Upon and after the occurrence of a Change in Control, the Company must: (1) pay all reasonable administrative expenses and fees of the Administrator; (2) indemnify the Administrator against any costs, expenses and liabilities including, without limitation, attorney’s fees and expenses arising in connection with the performance of the Administrator hereunder, except with respect to matters resulting from the gross negligence or willful misconduct of the Administrator or its employees or agents; and (3) supply full and timely information to the Administrator on all matters relating to the Plan, the Participants and their Beneficiaries, the Account balances of the Participants, the date and circumstances of the Retirement, Disability, death or Separation from Service of the Participants, and such other pertinent information as the Administrative Committee may reasonably require. Upon and after a Change in Control, a member of the Administrative Committee may only be removed (and a replacement may only be appointed) by the Ex-CEO.

8.2      Agents

           In the administration of this Plan, the Administrative Committee may, from time to time, employ agents and delegate to them such administrative duties as it sees fit, and may from time to time consult with counsel, who may be counsel to the Company.

8.3     Indemnity of Committees

           The Company shall indemnify and hold harmless the members of the Administrative Committee, the Appeals Committee and the Compensation Committee against any and all claims, loss, damage, expense or liability arising from any action or failure to act with respect to this Plan, except in the case of intentional misconduct.

8.4     Participating Employers

           The Compensation Committee or the Chief Executive Officer of Company may permit Employers to participate in this Plan. Any Employer may, upon resolution of its Board of Directors, withdraw from participating in the Plan and shall notify the Company of such resolution. An Employer’s withdrawal from the Plan shall not adversely affect balances in any Participant’s Accounts which shall continue to accrue earnings as set forth herein, shall not adversely affect the accrued Supplemental Pension Benefit and shall not change any distribution elections.

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ARTICLE 9—CLAIMS PROCEDURE

9.1     Claim

           Any person claiming a benefit (“Claimant”) under the Plan shall present the request in writing to the Administrative Committee.

9.2     Initial Claim Review

           In the case of a claims regarding Disability, the Administrative Committee will make a benefit determination within forty-five (45) days of its receipt of an application for benefits. This period may be extended up to an additional thirty (30) days, if the Administrative Committee provides the Claimant with a written notice of the extension within the initial forty-five (45)-day period. The extension notice will explain the reason for the extension and the date by which the Administrative Committee expects a decision will be made. The Administrative Committee may obtain a second thirty (30)-day extension by providing you written notice of such second extension within the thirty (30)-day extension. The second extension notice must include an explanation of the special circumstances necessitating the second extension and the date by which the Administrative Committee’s decision will be made. If the extension is necessary because additional information is needed to decide the claim, the extension notice will describe the required information. The Claimant will have forty-five (45) days after receiving the extension notice to provide the required information.

           In the case of all other claims, the Administrative Committee will make a benefit determination within ninety (90) days of its receipt of an application for benefits. This period may be extended up to an additional ninety (90) days, if the Administrative Committee provides the Claimant with a written notice of the extension within the initial ninety (90)-day period. The extension notice will explain the reason for the extension and the date by which the Administrative Committee expects a decision will be made.

           The Administrative Committee will notify the Claimant in writing, delivered in person or mailed by first-class mail to the Claimant’s last known address, if any part of a claim for benefits under the Plan has been denied. The notice of a denial of any claim will include:

           (a)           the specific reason for the denial;

           (b)           reference to specific provisions of the Plan upon which the denial is based;

           (c)           a description of any internal rule, guidelines, protocol or similar criterion relied on in making the denial (or a statement that such internal criterion will be provided free of charge upon request);

           (d)           a description of any additional material or information deemed necessary by the Administrative Committee for the Claimant to perfect the claim, and an explanation of why such material or information is necessary; and

           (e)           an explanation of the claims review procedure under the Plan.

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           If the notice described above is not furnished and if the claim has not been granted within the time specified above for payment of the claim, the claim will be deemed denied and will be subject to review as set forth in Section

9.3.    Review of Claim

           If a claim for benefits is denied, in whole or in part, the Claimant may request to have the claim reviewed. The Claimant will have one hundred eighty (180) days in which to request a review of a claim regarding Disability, and will have sixty (60) days in which to request a review of all other claims. The request must be in writing and delivered to the Compensation Committee. If no such review is requested, the initial decision of the Compensation Committee will be considered final and binding.

           The request for review must specify the reason the Claimant believes the denial should be reversed. He or she may submit additional written comments, documents, records, and other information relating to and in support of the claim; all information submitted will be reviewed whether or not it was available for the initial review. The Claimant may request reasonable access to and copies of, all documents, records, and other information relevant to the Claimant’s claim for benefits. A member of the Compensation Committee may not participate in the review of his or her own claim. In addition, if the Claimant requests a review, a member who is a subordinate of the original decision maker shall not participate in the review of the claim. The review will not defer to the initial adverse determination. If the denial was based in whole or in part on a medical judgment, the Compensation Committee will consult with an appropriate health care professional who was not consulted in the initial determination of his or her claim and who is not the subordinate of someone consulted in the initial determination. Names of the health care professionals will be available on request.

           Upon receipt of a request for review, the Compensation Committee may schedule a hearing within thirty (30) days of its receipt of such request, subject to availability of the Claimant and the availability of the Compensation Committee, at a time and place convenient for all parties at which time the Claimant may appear before the person or committee designated by the Compensation Committee to hear appeals for a full and fair review of the Administrative Committee’s initial decision. The Claimant may indicate in writing at the time the Compensation Committee attempts to schedule the hearing, that he or she wishes to waive the right to a hearing. If the Claimant does not waive his or her right to a hearing, he or she must notify the Compensation Committee in writing, at least fifteen (15) days in advance of the date established for such hearing, of his or her intention to appear at the appointed time and place. The Claimant must also specify any persons who will accompany him or her to the hearing, or such other persons will not be admitted to the hearing. If written notice is not timely provided, the hearing will be automatically canceled. The Claimant or the Claimant’s duly authorized representative may review all pertinent documents relating to the claim in preparation for the hearing and may submit issues, documents, affidavits, arguments, and comments in writing prior to or during the hearing.

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           The Compensation Committee will notify the Claimant of its decision following the reviews. In the case of a claim regarding Disability, the Compensation Committee will render its final decision within forty-five (45) days of receipt of an appeal or such shorter period as may be required by law. If the Compensation Committee determines that an extension of the time for processing the claim is needed, it will notify the Claimant of the reasons for the extension and the date by which the Compensation Committee expects a decision will by made. The extended date may not exceed ninety (90) days after the date of the filing of the appeal.

           In the case of all other claims, the Compensation Committee will render its final decision within sixty (60) days of receipt of an appeal. If the Compensation Committee determines that an extension of the time for processing the claim is needed, it will notify the Claimant of the reasons for the extension and the date by which the Compensation Committee expects a decision will be made. The extended date may not exceed one hundred twenty (120) days after the date of the filing of the appeal

           If after the review the claim continues to be denied, the Claimant will be provided a notice of the denial of the appeal which will contain the following information:

           (a)           The specific reasons for the denial of the appeal;

           (b)           A reference to the specific provisions of the Plan on which the denial was based;

          (c)           A statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the claim for benefits;

           (d)           A statement disclosing any internal rule, guidelines, protocol or similar criterion relied on in making the denial (or a statement that such information would be provided free of charge upon request); and

           (e)           A statement describing the Claimant’s right to bring a civil suit under Federal law and a statement concerning other voluntary alternative dispute resolutions options.

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9.4     Review of Claims on and after a Change in Control

           Upon and after the occurrence of a Change in Control, the Compensation Committee, as constituted immediately prior to a Change in Control, shall be the Appeals Committee. In the event any member of the Appeals Committee resigns or is unable to perform the duties of a member of the Appeals Committee, successors to such members shall be selected by the Ex-CEO. Upon and after a Change in Control, the Appeals Committee shall have all discretionary authorities and powers granted the Compensation Committee under this Plan to review denied claims as provided in Section 9.3. A member of the Appeals Committee may not participate in the review of his or her own claim and may not participate in the review a claim if he or she is a subordinate of the original decision maker. Upon and after the occurrence of a Change in Control, the Company must: (1) pay all reasonable administrative expenses and fees of the Appeals Committee; (2) indemnify the Appeals Committee against any costs, expenses and liabilities including, without limitation, attorney’s fees and expenses arising in connection with the performance of the Appeals Committee hereunder, except with respect to matters resulting from the gross negligence or willful misconduct of the Appeals Committee or its employees or agents; and (3) supply full and timely information to the Appeals Committee on all matters relating to the Plan, the Participants and their Beneficiaries, the Account balances of the Participants, the date and circumstances of the Retirement, Disability, death or Separation from Service of the Participants, and such other pertinent information as the Appeals Committee may reasonably require. Upon and after a Change in Control, a member of the Appeals Committee may only be removed (and a replacement may only be appointed) by the Ex-CEO.

ARTICLE 10—AMENDMENT AND TERMINATION OF PLAN

10.1   Right to Amend

           The Plan may be amended any time by action of the Board or the Compensation Committee or by a writing executed on behalf of the Board or Compensation Committee by the Company’s duly elected officers, except that:

           (a)           No amendment shall be effective to decrease or restrict any Participant’s Account balance or Supplemental Pension Benefit accrued to that date, and

           (b)           No amendment shall be effective to restrict the right of a Participant to elect to receive a lump-sum form of benefit payment of his or her Account upon Retirement, death, Disability or other separation of employment, and

           (c)           No amendment to the method for calculating earnings on the portion of the Retirement Account allocated to the investment option described in Section 4.2(c)(i) of the Plan shall decrease the interest rate credited to the Retirement Account balance of any Participant below the Moody’s Average Long-Term Corporate Bond Yield Index less one (1) percentage point; otherwise the Retirement Account balance that is accrued and vested as of December 31, 2004 including earnings credited thereon after that date shall be paid to all Participants within sixty (60) days of the effective date of such amendment.

26

Such amendment shall be effective on the first (1^st) day of the calendar year following the adoption by the Company of such amendment, provided that all Participants are notified of such amendment no later than November 15 of the year in which such amendment is adopted.

10.2   Right to Terminate

           The Board or the Compensation Committee may at any time terminate the Plan if, in its sole judgment, the tax, accounting or other effects of the continuance of the Plan or potential payments thereunder would not be in the best interests of the Company. Such termination shall not adversely affect any Plan Participant’s Account balance or accrued Supplemental Pension Benefit. Each Employer shall pay the balances of a Participant’s Accounts that were accrued and vested as of December 31, 2004 including earnings, gains and losses credited thereon after that date, and earned while employed by such Employer within sixty (60) days after the effective date of the Plan termination.

10.3   Distribution of Benefits on Plan Termination

           In the event the Corporation elects to amend, modify or terminate the Plan as provided under Section 10.2 and solely with respect to Account balances that accrue and/or vest after December 31, 2004, including deemed earnings, gains and losses credited thereon after that date, no right to the payment of benefits shall arise as a result of a Plan Termination;

           (a)           The Company may, in its discretion, provide by amendment to the Plan a right to the payment of all such Account balances as a result of the liquidation and termination of the Plan where:

                           (i)            the termination and liquidation does not occur proximate to a downturn in the financial health of the Company and the participating Employers;

                           (ii)           the Plan and all arrangements required to be aggregated with the Plan under Code Section 409A are terminated and liquidated;

                          (iii)           no payments, other than those that would be payable under the terms of the Plan and the aggregated arrangements if the termination and liquidation had not occurred, are made within twelve (12) months of the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan;

                           (iv)           all payments are made within twenty-four (24) months of the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan; and

                           (v)           the Company and the Employers do not adopt a new arrangement that would be aggregated with any terminated arrangement under Code Section 409A, at any time within three (3) years following the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan.

27

           (b)           Similarly, the Company may, in its discretion, provide by amendment to liquidate and terminate the Plan where the termination and liquidation occurs within twelve (12) months of a corporate dissolution taxed under Code Section 331, or with the approval of a bankruptcy court pursuant to 11 United States Code § 503(b)(1)(A), provided that all amounts deferred under the Plan are included in the Participants’ gross incomes in the latest of the following years (or, if earlier, the taxable year in which the amount is actually or constructively received):

                           (i)            the calendar year in which the termination occurs;

                           (ii)           the calendar year in which the amount is no longer subject to a substantial risk of forfeiture; or

                           (iii)           the first calendar year in which the payment is administratively practicable.

ARTICLE 11—MISCELLANEOUS

11.1   Unfunded Plan

           This Plan is intended to be an unfunded plan for federal income tax purposes and for purposes of ERISA, maintained primarily to provide deferred compensation benefits for a select group of management employees or highly compensated employees. This Plan is not intended to create an investment contract, but to provide tax planning opportunities and retirement benefits to eligible individuals who have elected to participate in the Plan. Eligible individuals are select members of management who, by virtue of their position with an Employer, have the ability to materially affect the Employer’s profitability and operations.

11.2   Liability for Benefits

           Except as otherwise agreed in writing, liability for the payment of a Participant’s benefit under this Plan shall be borne solely by the participating Employer that employs the Participant and reports the Participant as being on its payroll during the accrual or increase in the benefit. No liability for the payment of any Deferred Compensation Benefit or any Supplemental Pension Benefit shall be incurred by reason of Plan sponsorship or participation except for benefits of a participating Employer’s own employees. Nothing in this Section shall be interpreted as prohibiting any participating Employer from expressly agreeing in writing to the assumption of liability or guarantee of payment of any benefit under this Plan.

11.3   Unsecured General Creditor

           Participants and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interest or claims in any property or assets of any Employer. Any and all assets of each Employer shall be, and remain, the general, unpledged, unrestricted assets of the Employer. An Employer’s obligations under the Plan shall be merely that of an unfunded and unsecured promise of the Employer to pay money in the future.

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11.4   Obligations to Employer

           If a Participant becomes entitled to the payment of a benefit under the Plan and the Participant has outstanding any debt, obligation, or other liability representing an amount owing to the Employer obligated to pay the benefit at the time of payment, then the Employer may offset such amount owing to it against the amount of benefits otherwise distributable to the Participant or Beneficiary. Such determination shall be made by the Administrative Committee.

11.5   Nonassignability

        (a)           Except as stated in subsection (b) below, neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate or convey in advance of actual receipt the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are, expressly declared to be unassignable and nontransferable. No part of the amounts payable shall, prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, nor be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency.

          (b)           Domestic Relations Order.  An Employer may pay benefits to an alternate payee pursuant to a domestic relations order provided the Administrative Committee determines such order meets the requirements of a Qualified Domestic Relations Order pursuant to Code Section 414(p)(1)(B).

11.6   Not a Contract of Employment

           The terms and conditions of this Plan shall not be deemed to constitute a contract of employment between any Employer and the Participant, and neither the Participant nor any Beneficiary shall have any rights against any Employer except as may otherwise be specifically provided herein. Moreover, nothing in this Plan shall be deemed to give a Participant the right to be retained in the service of any Employer or to interfere with the right of any Employer to discipline or discharge such Participant at any time.

11.7   Protective Provisions

           A Participant shall cooperate with each Employer by furnishing any and all information requested by any Employer in order to facilitate the payment of benefits under this Plan.

11.8   Captions

           The captions of the articles, sections and subsection of this Plan are for convenience only and shall not control or affect the meaning or construction of any of its provisions.

11.9   Governing Law

           The provisions of this Plan shall be construed, administered, and enforced according to and governed by the laws (other than conflict of law provisions) of the state of Ohio, except to the extent such laws are superseded by ERISA.

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11.10  Validity

             In case any provision of this Plan shall be held illegal or invalid for any reason, such illegality or invalidity shall not affect the remaining parts hereof, but this Plan shall be construed and enforced as if such illegal and invalid provision had never been inserted herein.

11.11  Notice

            Any notice or filing required or permitted to be given to the Administrative Committee under the Plan shall be sufficient if in writing and hand delivered, or sent by registered or certified mail to any member of the Administrative Committee, or to the statutory agent of Company. Notice to the Administrative Committee may be given to any member of the Administrative Committee and if mailed shall be addressed to the principal executive offices of Company. Notice mailed to the Participant shall be sent to the address set out in the Participant’s most recent Participation Agreement or such other address as is given to the Administrative Committee by notice. Notices shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark, or the receipt for registration or certification.

11.12  Successors

            The provisions of this Plan shall bind and inure to the benefit of each Employer and its successors and assigns. The term successors as used herein shall include any corporate or other business entity which shall, whether by merger, consolidation, purchase or otherwise acquire all or substantially all of the business and assets of an Employer, and successors of any such corporation or other business entity.

11.13  Code Section 409A

            Notwithstanding anything to the contrary in the provisions of this Plan regarding the benefits payable hereunder and the time and form thereof, this Plan is intended to meet any applicable requirements of Code Section 409A and this Plan shall be construed and administered in accordance with Section 409A of the Code, Department of Treasury regulations and other interpretive guidance issued thereunder, including without limitation any such regulations or other guidance that may be issued after the Effective Date. In the event that the Company determines that any provision of this Plan or the operation thereof may violate Section 409A of the Code and related Department of Treasury guidance, the Company may in its sole discretion adopt such amendments to this Plan and appropriate policies and procedures, including amendments and policies with retroactive effect, or take such other actions, as the Company determines necessary or appropriate to comply with the requirements of Section 409A of the Code.

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APPENDIX A

1 Participating Employer	2 Adoption Date	3 Termination Date
American Transmissions Systems, Inc.	January 1, 2003
Cleveland Electric Illuminating Company	July 1, 1998
FirstEnergy Corp.	January 1, 1998
FirstEnergy Facilities Services Group, Inc.	January 1, 2003
FirstEnergy Generation Corp.	January 1, 2003
FirstEnergy Nuclear Operating Company	January 1, 1999
FirstEnergy Service Company	January 1, 1999
FirstEnergy Solutions Corp.	January 1, 2003
Jersey Central Power and Light	January 1, 2003
Metropolitan Edison	January 1, 2003
Ohio Edison Company	January 1, 1983
Pennsylvania Electric	January 1, 2003
Pennsylvania Power Company	January 1, 1983
Toledo Edison Company	July 1, 1998

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APPENDIX B

Change in Control

           Effective as of the date approved by shareholders and for purposes of the Plan, a “Change in Control” means:

           1.             An acquisition by any individual, entity, or group (within the meaning of

Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of fifty percent (50%) (twenty-five percent (25%) if such Person proposes any individual for election to the Board of Directors or any member of the Board is the representative of such Person) or more of either (i) the then outstanding shares of common stock of the Company (“Outstanding Company Common Stock”), or (ii) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (“Outstanding Company Voting Securities”); provided, however, that the following acquisitions will not constitute a Change in Control:

           (a)           Any acquisition directly from the Company (excluding an acquisition by virtue of the exercise of a conversion privilege);

           (b)           Any acquisition by the Company;

           (c)           Any acquisition by an employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company; or

           (d)           Any acquisition by any corporation pursuant to a reorganization, merger, or consolidation if, following such reorganization, merger, or consolidation, the conditions described in clauses 3(b), 3(c) and 3(d) of this Appendix B are satisfied.

           2.             Individuals who, as of the date hereof, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company’s shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of either an actual or threatened election contest (as such terms are used in Rule 14a-11 of Regulation 14A promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or

32

APPENDIX B

Change in Control

(Continued)

           3.             Consummation of a reorganization, merger, or consolidation or sale or other disposition of all or substantially all of the assets of the Company, in each case, unless, following such reorganization, merger, or consolidation or sale or other disposition of assets:

           (a)           More than seventy-five percent (75%) of, respectively, the then outstanding shares of common stock of the corporation resulting from such reorganization, merger, consolidation, or acquiring such assets and the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors is then beneficially owned, directly or indirectly, by all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such reorganization, merger, consolidation, or sale or other disposition of assets in substantially the same proportions as their ownership, immediately prior to such reorganization, merger, consolidation, or sale or other disposition of assets, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be;

           (b)           No Person (excluding the Company, any employee benefit plan (or related trust) of the Company or such corporation resulting from such reorganization, merger, consolidation, or sale or other disposition of assets, and any Person beneficially owning, immediately prior to such reorganization, merger, consolidation, or sale or other disposition of assets, directly or indirectly, twenty-five percent (25%) or more of the Outstanding Company Common Stock or Outstanding Voting Securities, as the case may be) beneficially owns, directly or indirectly, twenty-five percent (25%) or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such reorganization, merger, or consolidation or acquiring such assets or the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors; and

           (c)           At least a majority of the members of the Board of Directors of the corporation resulting from such reorganization, merger, or consolidation or acquiring such assets were members of the Incumbent Board at the time of the execution of the initial agreement providing for such reorganization, merger, consolidation or sale or other disposition of assets; or

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

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However, in no event will a Change in Control be deemed to have occurred, with respect to a Participant, if the Participant is part of a purchasing group which consummates the Change in Control transaction. The Participant will be deemed “part of a purchasing group” for purposes of the preceding sentence if the Participant is an equity participant or has agreed to become an equity participant in the purchasing company or group (excluding passive ownership of less than five percent (5%) of the voting securities of the purchasing company or ownership of equity participation in the purchasing company or group which is otherwise not deemed to be significant, as determined prior to the Change in Control by a majority of the nonemployee continuing members of the Board of Directors).

34

EX-10.3

EX-12

EXHIBIT 12

FIRSTENERGY CORP.
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	Nine Months Ended
	September 30,
	2007		2006
	(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	1,040,868	$	983,743
Interest and other charges, before reduction for amounts capitalized		593,091		533,356
Provision for income taxes		695,467		624,887
Interest element of rentals charged to income (a)		146,390		170,065
Earnings as defined	$	2,475,816	$	2,312,051
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest expense	$	593,091	$	527,569
Subsidiaries’ preferred stock dividend requirements		-		5,787
Adjustments to subsidiaries’ preferred stock dividends
to state on a pre-income tax basis		-		3,676
Interest element of rentals charged to income (a)		146,390		170,065
Fixed charges as defined	$	739,481	$	707,097
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		3.35		3.27
____________________
(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest
element can be determined which we believe represents an appropriate interest factor.

EXHIBIT 12

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	Nine Months Ended
	September 30,
	2007		2006
	(Dollars in Thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	408,684	$	311,956
Interest and other charges, before reduction for amounts capitalized		132,749		140,544
Provision for income taxes		243,736		184,572
Interest element of rentals charged to income (a)		1,092		1,168
Earnings as defined	$	786,261	$	638,240
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest expense	$	132,749	$	140,544
Interest element of rentals charged to income (a)		1,092		1,168
Fixed charges as defined	$	133,841	$	141,712
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		5.87		4.50
____________________
(a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest
element can be determined which we believe represents an appropriate interest factor.

EXHIBIT 12

OHIO EDISON COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	Nine Months Ended
	September 30,
	2007		2006
	(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	147,862	$	166,536
Interest and other charges, before reduction for amounts capitalized		62,749		60,662
Provision for income taxes		79,074		91,239
Interest element of rentals charged to income (a)		60,370		67,064
Earnings as defined	$	350,055	$	385,501
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest on long-term debt	$	54,493	$	49,280
Other interest expense		8,256		10,914
Subsidiaries’ preferred stock dividend requirements		-		467
Adjustments to subsidiaries’ preferred stock dividends
to state on a pre-income tax basis		-		291
Interest element of rentals charged to income (a)		60,370		67,064
Fixed charges as defined	$	123,119	$	128,016
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		2.84		3.01
____________________
(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest
element can be determined which we believe represents an appropriate interest factor.

EXHIBIT 12

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	Nine Months Ended
	September 30,
	2007		2006
	(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	163,957	$	153,355
Interest and other charges, before reduction for amounts capitalized		79,467		70,092
Provision for income taxes		118,637		120,506
Interest element of rentals charged to income (a)		6,143		6,635
Earnings as defined	$	368,204	$	350,588
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest on long-term debt	$	65,949	$	56,612
Other interest expense		13,518		13,480
Interest element of rentals charged to income (a)		6,143		6,635
Fixed charges as defined	$	85,610	$	76,727
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		4.30		4.57
____________________
(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest
element can be determined which we believe represents an appropriate interest factor.

EXHIBIT 12

METROPOLITAN EDISON COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	Nine Months Ended
	September 30,
	2007		2006
	(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	75,797	$	82,981
Interest and other charges, before reduction for amounts capitalized		38,471		35,546
Provision for income taxes		53,145		55,390
Interest element of rentals charged to income (a)		1,509		1,324
Earnings as defined	$	168,922	$	175,241
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest on long-term debt	$	21,032	$	25,987
Other interest expense		17,439		9,559
Interest element of rentals charged to income (a)		1,509		1,324
Fixed charges as defined	$	39,980	$	36,870
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		4.23		4.75
____________________
(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest
element can be determined which we believe represents an appropriate interest factor.

EXHIBIT 12

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	Nine Months Ended
	September 30,
	2007		2006
	(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	74,237	$	56,666
Interest and other charges, before reduction for amounts capitalized		38,426		33,974
Provision for income taxes		49,025		39,251
Interest element of rentals charged to income (a)		2,402		2,387
Earnings as defined	$	164,090	$	132,278
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest on long-term debt	$	22,642	$	20,937
Other interest expense		15,783		13,037
Interest element of rentals charged to income (a)		2,402		2,387
Fixed charges as defined	$	40,827	$	36,361
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		4.02		3.64
____________________
(a)Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest
element can be determined which we believe represents an appropriate interest factor.

EX-15

 EXHIBIT 15

October 31, 2007

Securities and Exchange Commission

100 F Street, N.E.

Washington, DC 20549

Commissioners:

We are aware that our report dated October 31, 2007 on our review of interim financial information of FirstEnergy Corp. (the "Company") for the three and nine month periods ended September 30, 2007 and 2006 and included in the Company's quarterly report on Form 10-Q for the quarter ended September 30, 2007, is incorporated by reference in their Registration Statements on Form S-3 (Nos. 333-48587, 333-102074 and 333-103865) and S-8 (Nos. 333-56094, 333-58279, 333-67798, 333-72766, 333-72768, 333-81183, 333-89356, 333-101472, 333-110662, and 333-146170).

Very truly yours,

PricewaterhouseCoopers LLP

EXHIBIT 15

October 31, 2007

Securities and Exchange Commission

100 F Street, N.E.

Washington, DC 20549

Commissioners:

We are aware that our report dated October 31, 2007 on our review of interim financial information of Ohio Edison Company (the "Company") for the three and nine month periods ended September 30, 2007 and 2006 and included in the Company's quarterly report on Form 10-Q for the quarter ended September 30, 2007, is incorporated by reference in its Registration Statement on Form S-3 (No. 333-133117).

Very truly yours,

PricewaterhouseCoopers LLP

EXHIBIT 15

October 31, 2007

Securities and Exchange Commission

100 F Street, N.E.

Washington, DC 20549

Commissioners:

We are aware that our report dated October 31, 2007 on our review of interim financial information of Pennsylvania Electric Company (the "Company") for the three and nine month periods ended September 30, 2007 and 2006 and included in the Company's quarterly report on Form 10-Q for the quarter ended September 30, 2007 is incorporated by reference in their Registration Statements on Form S-3 (Nos. 333-62295, 333-62295-01, and 333-62295-02).

Very truly yours,

PricewaterhouseCoopers LLP

EX-31.1

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this report on Form 10-Q of FirstEnergy Corp.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31 , 2007

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Exhibit 31.1

Certification

I, Charles E. Jones, certify that:

1.	I have reviewed this report on Form 10-Q of FirstEnergy Solutions Corp.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Charles E. Jones

Charles E. Jones

Chief Executive Officer

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this report on Form 10-Q of Ohio Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this report on Form 10-Q of The Cleveland Electric Illuminating Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this report on Form 10-Q of The Toledo Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Exhibit 31.1

Certification

I, Stephen E. Morgan, certify that:

1.	I have reviewed this report on Form 10-Q of Jersey Central Power & Light Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Stephen E. Morgan

Stephen E. Morgan

Chief Executive Officer

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this report on Form 10-Q of Metropolitan Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this report on Form 10-Q of Pennsylvania Electric Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-Q of FirstEnergy Corp.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-Q of FirstEnergy Solutions Corp.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-Q of Ohio Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-Q of The Cleveland Electric Illuminating Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-Q of The Toledo Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Exhibit 31.2

Certification

I, Paulette R. Chatman, certify that:

1.	I have reviewed this report on Form 10-Q of Jersey Central Power & Light Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Paulette R. Chatman

Paulette R. Chatman

Chief Financial Officer

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-Q of Metropolitan Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this report on Form 10-Q of Pennsylvania Electric Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of FirstEnergy Corp. ("Company") on Form 10-Q for the period ending September 30, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: October 31, 2007

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of FirstEnergy Solutions Corp. ("Company") on Form 10-Q for the period ending September 30, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Charles E. Jones

Charles E. Jones

President

(Chief Executive Officer)

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: October 31, 2007

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of Ohio Edison Company ("Company") on Form 10-Q for the period ending September 30, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: October 31, 2007

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of The Cleveland Electric Illuminating Company ("Company") on Form 10-Q for the period ending September 30, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: October 31, 2007

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of The Toledo Edison Company ("Company") on Form 10-Q for the period ending September 30, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: October 31, 2007

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of Jersey Central Power & Light Company ("Company") on Form 10-Q for the period ending September 30, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Stephen E. Morgan

Stephen E. Morgan

President

(Chief Executive Officer)

Date: October 31, 2007

/s/ Paulette R. Chatman

Paulette R. Chatman

Controller

(Chief Financial Officer)

Date: October 31, 2007

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of Metropolitan Edison Company ("Company") on Form 10-Q for the period ending September 30, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: October 31, 2007

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of Pennsylvania Electric Company ("Company") on Form 10-Q for the period ending September 30, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)          The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

Date: October 31, 2007

/s/ Richard H. Marsh

Richard H. Marsh

Chief Financial Officer

Date: October 31, 2007